- Email: [email protected]
Aliso Canyon Leakage as an Analogue for Worst Case CO2 Leakage and Quantification of Acceptable Storage Loss
Available online at www.sciencedirect.com
ScienceDirect Energy Procedia 114 (2017) 4279 – 4286
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Aliso Canyon leakage as an analogue for worst case CO2 leakage and quantification of acceptable storage loss Erik Lindeberg*, Per Bergmo, Malin Torsæter and Alv-Arne Grimstad SINTEF Petroleum Research, P.O.Box 4763 Sluppen, NO-7465 Trondheim, Norway
Abstract The Aliso Canyon gas well leakage is used as an analogue to study a possible accident from a CO2 storage site. Because the blowout is the second largest in USA, it can be used as a worst-case blowout analogue for a possible CO2 blowout from an underground CO2 storage. Reservoir modelling and well modelling of the Aliso Canyon case is used to determine the leakage pathway and leakage mechanisms that will mimic the escape history. This data are put in a new model where the gas is replaced by CO 2 and a similar accident is simulated. Several factors are different between gas leakage from gas storage and potential leakage from a typical CO2 storage in an aquifer, due to differences in thermodynamic properties and flow properties both along in the leakage pathway and in the porous medium in the storage reservoir. The specific features of the two cases are compared and show that as the risk elements are very different, remediation measures will be different. The escape rate is significant lower for the CO 2 scenario than the observed gas escape from Aliso Canyon gas well (4.9 Sm3/s respectively 21.3 Sm3/s). While 2.8 % of the stored gas was lost at the Aliso Canyon leak, the corresponding loss from a CO2 well if the facility was used for CO2 storage would be 0.37%. Due to the high density of CO2, the well pressure at the rupture was less than half than for CO2 compared to gas, which will make remediation easier. © 2017 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license © 2017 The Authors. Published by Elsevier Ltd. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: Type your keywords here, separated by semicolons ;
* Corresponding author. Tel.: +47 41609611, Fax.: +47 73593350 E-mail address: [email protected]
1876-6102 © 2017 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1914
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1. Background Occasionally gas blowout from wells occur in the gas storage industry and by studying these events, much can be learned to improve predictions of what may can happen in a blowout from similar CO 2 storage site in general. Specifically, it is of interest to study the integrity of wells in old petroleum reservoirs because it has been expressed some concern on storing CO2 in this kind of sites due to the many wells penetrating the cap rock. 2. Objective The objective of this study is to describe a realistic pathway for the leakage giving the same plateau production of gas as the observed rates. This is done through reservoir modelling and "well modelling" of the leaking well. When the leakage dimensions and physics has been determined, simulation of a corresponding CO 2 leakage is performed on the same physical model. The results are used to estimate the impact of a scenario that possibly can occur when CO2 is stored in depleted oil and gas fields with many old wells penetrating the caprock. 3. Aliso Canyon gas leak The Aliso Canyon gas leak (also referred to as Porter Ranch gas leak) was a massive natural gas leak that was discovered in October 2015. Gas was escaping from one of the wells of the Aliso Canyon's underground storage facility in the Santa Susana Mountains near Porter Ranch, Los Angeles County. This is the 4th largest natural gas storage reservoirs in the USA, containing up to 4.79 GSm3 of gas (168 billion SCF) of which 51% is the working capacity for commercial use. Natural gas was leaking from 23 October 2015 until the leakage was preliminary remediated 11 February 2016[1]. The storage site is a depleted petroleum reservoir from 1952, containing 115 wells, which was repurposed for gas storage in 1972. The particular leaking well, referred to as Standard Sesnon 25 (SS-25), is 2670 m deep. It was drilled in 1953, and the reason for the leakage is that the 7" casing in the well has failed. The casing was not cemented to surface, and leakage occurred through the un-cemented space behind the casing and into the shallow soil surrounding the well. Early attempts to stop the leakage by using a mixture of mud and brine failed due to ice formation and a high pressure. A relief well intercepting the leaking well at approximately 2560 m depth was drilled, and at 11 February, heavy fluid injection near the bottom of the leaking well temporarily halted the leak. A subsequent cement injection sealed the well on 18 February. The leakage rate was monitored by a specially instrumented aircraft in 13 period surveys in the period from 7 November 2015 to 13 February 2016. The reported leakage data from the well is illustrated in Figure 1 [2], and the gas release, totally 0.13 GSm3, is the second largest of its kind recorded in USA, exceeded only by the 0.17 GSm3 of natural gas released in the collapse of an underground storage facility in Moss Bluff, Texas in 2004.
Fig. 1. Reported emission rates, cumulative emissions and a simplified emission profile.
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4. Modelling of the leaking well and reservoir To analyse the leakage and identify its special features the blowout was modelled and input parameters on the well and reservoir was needed. Some well dimensions and a possible leakage pathway is presented in Figure 2.
Fig. 2 Simplified profile of the leaking well and the expected leakage pathway [3].
Most of the transport takes place on the large casing between the pipe and the 7" casing. There is a possible constriction where the gas enters the casing. In addition, there is a constriction where the gas breaks out of the casing in the upper end of the well. From the foot of the outer casing at 302 m depth the gas is flowing between the casing and the rock, but possibly also in the porous rock in the shallow sediments. The volume rate becomes very large near the surface due the low pressure. The flow modelling in this part is complicated, and some strong simplifications has to be made. The Aliso Canyon field is located in the Ventura Basin and gas contained in a Pliocene Pico sand. It has an average permeability of 0.084∙10-12 m2 (85 mDarcy) and a porosity of 23% [4, 5]. The sand and the surrounding formations consists of a complex tilted fault block system [6]. To model the blowout some basic reservoir properties are needed. Information on the gas composition is sparse (only the methane and the ethane concentration are reported [1]), but the composition given in Table 1 is sufficient for this study. For the modelling purpose the gas density, Joule-Thompson coefficient, and enthalpy as function of pressure and temperature was calculated by the GERG-2008 equation of state. The gas viscosity was computed with a correlation from Lee at al. [7].
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Erik Lindeberg et al. / Energy Procedia 114 (2017) 4279 – 4286 Table 1. Gas composition
Component Methane Nitrogen Carbon dioxide Ethane Propane Butane
Concentration, mole fraction 0.951 0.003 0.002 0.040 0.003 0.001
The properties of CO2 at reservoir and leakage conditions were computed by an equation of state by Span and Wagner [8].
4.1 Reservoir modelling Volumes, rates and other input parameter used in the numerical reservoir simulations are summarized in Table 2. Two different thickness estimates has been reported [9, 10] and an average value was used in this study. Table 2 Reservoir input parameter for modelling
Parameter Depth at top of formation Reservoir area Reservoir net height Reservoir pressure at start Porosity Pore volume Dip Gas in place Permeability, base case Permeability, alternative Grid blocks (40 x 40 x 20) Gas plateau rate, base case Gas plateau rate, alternative
Unit m km2 m bar % million m3 ° GSm3 m2 m2 Sm3/s Sm3/s
Value 2591 1.801 61 219 23 25.25 15 4.79 0.084∙10-12 0.113∙10-12 32000 21.25 23.42
A 3D reservoir model was compiled on basis of the data above and the blowout was simulated with a reservoir simulator tool, Eclipse 100. The first test was performed with an open escape through the 7" annulus. The production exceeded immediately the observed production rate without exceeding the speed of sound at the outlet of the well Next, a constant rate test was performed with a gas loss (21.25 Sm3/s) plateau rate corresponding to the observed rate through the 42 first days of leakage. There was no exhaustion of the gas drive after 42 days and the only way to in anyway mimic the shape of the escape profile (Figure 1), was to switch the well control in the simulator from rate control to a constant well pressure control. The values on plateau rate and the permeability are very uncertain and these were selected as variables in a few sensitivity tests. An increase of the plateau rate with 10% or an increase of the permeability by 35% can be used to mimic the escape profile, but there is no rationale for selecting any of these and there was done no attempt to further history match the escape profile, as this will give no additional value on leakage mechanisms. The reservoir properties has a negligible influence on the escape profile because the bottom-hole pressure is almost constant during the whole run for all cases. This means that the reservoir is sufficiently large and has sufficiently large permeability to maintain an almost constant bottom-hole pressure for a wide range of rates. An explanation of the observed leakage profile
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including the two plateau rates and the transition between them must be found in the leakage path in and around the well and not in the reservoir. In this study, however, the most interesting period is the plateau rate period because this corresponds to a "worst case scenario". The issue of what happens in the well during the decline period and after are left to other researchers to answer. The results of some sensitivity tests are illustrated in Figure 3 and the specific parameters used in addition to the values in Table 2 are listed in Table 3. Table 3 Combinations of rate and reservoir permeability in three simulator runs cases
Case 1 2 3
Permeability, m2 0.084∙10-12 0.113∙10-12 0.113∙10-12
Plateau rate, Sm3/s 23.42 23.42 21.25
Plateau rate, million Sm3/day 2.024 2.024 1.836
Fig. 3. Simulated escape scenarios: Escape rates and bottom-hole pressure
4.1 Well modelling The gas flow along the escape pathway was modelled as flow in pipes with constrictions that limits the rates to the observed rate. In addition to the rate constrain the gas velocity can never exceed the velocity of sound in the gas. To model the hydrocarbon gas flow a standard pipe flow equation was used. There are a number of these equations [10] and the main difference is how to handle the friction factor. In this study the “1/9th power” equation was selected because it can handle gas flow at high Reynolds number. For the CO 2 well flow, an in-house well simulator for CO2 was used [11] due to its capacity to handle two-phase flow. In addition, it is based on accurate thermodynamic property calculation for CO2 and has previously been tested on CO2 blowouts.
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To find a pathway that meets the operational and physical constrains some major simplifications was needed. It was assumed that the main constriction to flow is in and near the fracture in the upper part of the casing and that the pressure at the outlet from this constriction cannot be lower than a hydrostatic backpressure of 30 bars as it escape out between the casings at 302 m depth (Figure 2). By tuning the pathway geometry, an equivalent escape pathway consisting of subsequent sections of varying size, was designed. The equivalent pathway is illustrated in Figure 4. It must be emphasised that this is one possible solution and that other geometries could meet the physical constraints.
Fig. 4. Simplified tube pathway for gas escape inside and outside of the well. The right picture is a magnification of the upper 320 m. The diameter of the smallest constriction is 0.0259 m mimicking the fracture in the casing.
The resulting density, temperature, pressure, gas velocity and velocity of sound profiles along the well is illustrated in Figure 5. At the main constriction, the velocity is limited by the velocity of sound. The same model is then applied on the CO2 well simulator and the results are illustrated in Figure 6. Key differences are summarized in Table 4. Table 4 Comparison of key data from the Aliso Canyon leakage and a similar leakage from a CO2 well
Parameter Leakage rate Leakage rate Total loss during 112 days Total loss during 112 days Total loss fraction during 112 days Pressure at casing fracture during flow Total gas in formation Total gas in formation Density at reservoir conditions Fluid temperature after constriction Fluid temperature at surface
Unit Sm3/s kg/s tonne GSm3 % bar GSm3 million tonne kg/m3 °C °C
Gas well 21.3 15.0 94500 0.134 2.8 184 4.79 3.37 133 51 9.9
CO2 well 4.87 9.11 57330 0.0307 0.37 91 8.34 15.6 618 -5.5 -70
Erik Lindeberg et al. / Energy Procedia 114 (2017) 4279 – 4286
Fig. 5 Density, temperature, pressure, velocity of gas, velocity of sound along the escape path for gas
Fig. 6 Density, temperature, pressure, velocity of gas, velocity of sound along the escape path for CO 2
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5. Discussion and conclusion It should be noted that as soon as CO2 enters the outside of the well at 302 meter, it is not only at a lower temperature than the hydrate temperature of 11 °C, but it is also colder than the freezing point of water. This will probably limit the flow, but it is difficult to model and this effect have not been included in this study. Here it is assumed the worst case; that neither hydrates nor ice is formed. Experiments have shown that cooling a well below the freezing point of pore fluid will crack not only well cement, but also surrounding rock [12]. It is thus not recommended to repair/re-use a well after such an event. When permanently sealing the blowout well, it should also be made sure that any thermally induced cracks in the formation surrounding the well are sufficiently sealed. From a climate, perspective 0.37 % CO2 loss is tolerable when it is considered that this is the second largest gas blowout in USA. Even if the CO2 loss is smaller than for natural gas, the escape of 57 000 tonne CO2 during a 112 period in a residential area is still a serious accident. Due to much lower well pressure at the well break (91 bar for CO2 respectively 184 bar for gas); it may be much easier to remediate the well. There is a big difference how a gas storage facility and CO 2 storage is operated. As gas storage, facility is kept alive with cyclic injection and production for an extended period in addition to the time the field was operated as a hydrocarbon production period, while a CO2 storage project is a one-way operation of the field and when the formation is full, the wells can be closed down, plugged and abandoned. There will still be a risk for leakage and an extended monitoring will be needed. . References [1] Conley, S. Franco, G. Faloona, I. Blake, D. R., Peischl, J., Ryerson, T. B., Methane emissions from the 2015 Aliso Canyon blowout in Los Angeles, CA, Science 10.1126/science.aaf2348, 2016. [2] SoCalGas, Aliso Canyon Natural Gas Leak, Preliminary Estimate of Greenhouse Gas Emissions, (As of March 08, 2016), Press release. [3] Bauer, S., Blankenship, D., Dykhuizen, R., Roberts, B., Freifeld, B., Jordan, P., Pan, L., Oldenburg, C., Perfect, S., Morris, J., National Lab Activity Overview presented at Workshop on Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers, Denver, Colorado, July 12-13, 2016, (http://eesa.lbl.gov/workshop-helps-reducing-risk-future-incidents-natural-gas-storage-leak/) [4] Kuintomi, D.S., Schroeder, T., Natural Gas Storage Operations and the Geology of the Aliso Canyon Field, Los Angeles Co., California, GB 77 Geology and Tectonics of the San Fernando Valley and East Ventura Basin, 2001, Wright, T., Yeats, R. (eds.), 224 p [5] Hsü, K.J., Studies of Ventura Field, California, II: Lithology, Compaction, and Permeability of Sands, The American Association of Petroleum Geologists Bulletin V. 61, No. 2 (February 1977). p. 169 191. [6] Namson, J.S., and Davis, T.L.,1991, Detection and seismic potential of blind thrusts in the Los Angeles, Ventura and Santa Barbara areas, and adjoining Transverse Ranges, Final technical report, USGSNEHRP, Award 14-08-0001-G1687 [7] Lee, A.L., Gonzalez, M.H., Eakin, B.E. 1966. The Viscosity of Natural Gases. J Pet Technol 18 (8): 997–1000. SPE-1340-PA [8] Span, R., Wagner, W., 1996 “A New Equation of State for Carbon Dioxide Covering the Fluid Region from the Triple-Point Temperature to 100 K at Pressures up to 800 MPa”, J. Phys. Chem. Ref. Data, Vol. 25, No. 6, pp. 1509 – 1596 [9] DOGGR, 1998, California Oil & Gas Fields, Volume II – Southern, Central Coastal and Offshore California Oil and Gas Fields, ftp://ftp.consrv.ca.gov/pub/oil/publications/Datasheets/Dtasheet_vol_2.pdf [10] IGU (2006) International Gas Union (IGU) Website on Underground Gas Storage Facilities, World Wide Web Address: http://www.igu.org/html/wgc2006/WOC2database/Excel/Report_Tab_Summary_UGS_Key_Data_2006_in_operation_english.xls [11] Ouyang LB, Aziz K. Steady-state gas flow in pipes. Journal of Petroleum Science and Engineering 1996;14:137–58. [12] Lindeberg, E., Modelling pressure and temperature profile in a CO2 injection well, Energy Procedia 4 (2011) 3935–3941 [13] J. Todorovic, K. Gawel, A. Lavrov, M. Torsæter: Integrity of Downscaled Well Models Subject to Cooling. SPE 180052 paper at SPE Bergen One Day Seminar, Bergen, Norway 20 April 2016.
ScienceDirect Energy Procedia 114 (2017) 4279 – 4286
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Aliso Canyon leakage as an analogue for worst case CO2 leakage and quantification of acceptable storage loss Erik Lindeberg*, Per Bergmo, Malin Torsæter and Alv-Arne Grimstad SINTEF Petroleum Research, P.O.Box 4763 Sluppen, NO-7465 Trondheim, Norway
Abstract The Aliso Canyon gas well leakage is used as an analogue to study a possible accident from a CO2 storage site. Because the blowout is the second largest in USA, it can be used as a worst-case blowout analogue for a possible CO2 blowout from an underground CO2 storage. Reservoir modelling and well modelling of the Aliso Canyon case is used to determine the leakage pathway and leakage mechanisms that will mimic the escape history. This data are put in a new model where the gas is replaced by CO 2 and a similar accident is simulated. Several factors are different between gas leakage from gas storage and potential leakage from a typical CO2 storage in an aquifer, due to differences in thermodynamic properties and flow properties both along in the leakage pathway and in the porous medium in the storage reservoir. The specific features of the two cases are compared and show that as the risk elements are very different, remediation measures will be different. The escape rate is significant lower for the CO 2 scenario than the observed gas escape from Aliso Canyon gas well (4.9 Sm3/s respectively 21.3 Sm3/s). While 2.8 % of the stored gas was lost at the Aliso Canyon leak, the corresponding loss from a CO2 well if the facility was used for CO2 storage would be 0.37%. Due to the high density of CO2, the well pressure at the rupture was less than half than for CO2 compared to gas, which will make remediation easier. © 2017 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license © 2017 The Authors. Published by Elsevier Ltd. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: Type your keywords here, separated by semicolons ;
* Corresponding author. Tel.: +47 41609611, Fax.: +47 73593350 E-mail address: [email protected]
1876-6102 © 2017 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1914
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1. Background Occasionally gas blowout from wells occur in the gas storage industry and by studying these events, much can be learned to improve predictions of what may can happen in a blowout from similar CO 2 storage site in general. Specifically, it is of interest to study the integrity of wells in old petroleum reservoirs because it has been expressed some concern on storing CO2 in this kind of sites due to the many wells penetrating the cap rock. 2. Objective The objective of this study is to describe a realistic pathway for the leakage giving the same plateau production of gas as the observed rates. This is done through reservoir modelling and "well modelling" of the leaking well. When the leakage dimensions and physics has been determined, simulation of a corresponding CO 2 leakage is performed on the same physical model. The results are used to estimate the impact of a scenario that possibly can occur when CO2 is stored in depleted oil and gas fields with many old wells penetrating the caprock. 3. Aliso Canyon gas leak The Aliso Canyon gas leak (also referred to as Porter Ranch gas leak) was a massive natural gas leak that was discovered in October 2015. Gas was escaping from one of the wells of the Aliso Canyon's underground storage facility in the Santa Susana Mountains near Porter Ranch, Los Angeles County. This is the 4th largest natural gas storage reservoirs in the USA, containing up to 4.79 GSm3 of gas (168 billion SCF) of which 51% is the working capacity for commercial use. Natural gas was leaking from 23 October 2015 until the leakage was preliminary remediated 11 February 2016[1]. The storage site is a depleted petroleum reservoir from 1952, containing 115 wells, which was repurposed for gas storage in 1972. The particular leaking well, referred to as Standard Sesnon 25 (SS-25), is 2670 m deep. It was drilled in 1953, and the reason for the leakage is that the 7" casing in the well has failed. The casing was not cemented to surface, and leakage occurred through the un-cemented space behind the casing and into the shallow soil surrounding the well. Early attempts to stop the leakage by using a mixture of mud and brine failed due to ice formation and a high pressure. A relief well intercepting the leaking well at approximately 2560 m depth was drilled, and at 11 February, heavy fluid injection near the bottom of the leaking well temporarily halted the leak. A subsequent cement injection sealed the well on 18 February. The leakage rate was monitored by a specially instrumented aircraft in 13 period surveys in the period from 7 November 2015 to 13 February 2016. The reported leakage data from the well is illustrated in Figure 1 [2], and the gas release, totally 0.13 GSm3, is the second largest of its kind recorded in USA, exceeded only by the 0.17 GSm3 of natural gas released in the collapse of an underground storage facility in Moss Bluff, Texas in 2004.
Fig. 1. Reported emission rates, cumulative emissions and a simplified emission profile.
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4. Modelling of the leaking well and reservoir To analyse the leakage and identify its special features the blowout was modelled and input parameters on the well and reservoir was needed. Some well dimensions and a possible leakage pathway is presented in Figure 2.
Fig. 2 Simplified profile of the leaking well and the expected leakage pathway [3].
Most of the transport takes place on the large casing between the pipe and the 7" casing. There is a possible constriction where the gas enters the casing. In addition, there is a constriction where the gas breaks out of the casing in the upper end of the well. From the foot of the outer casing at 302 m depth the gas is flowing between the casing and the rock, but possibly also in the porous rock in the shallow sediments. The volume rate becomes very large near the surface due the low pressure. The flow modelling in this part is complicated, and some strong simplifications has to be made. The Aliso Canyon field is located in the Ventura Basin and gas contained in a Pliocene Pico sand. It has an average permeability of 0.084∙10-12 m2 (85 mDarcy) and a porosity of 23% [4, 5]. The sand and the surrounding formations consists of a complex tilted fault block system [6]. To model the blowout some basic reservoir properties are needed. Information on the gas composition is sparse (only the methane and the ethane concentration are reported [1]), but the composition given in Table 1 is sufficient for this study. For the modelling purpose the gas density, Joule-Thompson coefficient, and enthalpy as function of pressure and temperature was calculated by the GERG-2008 equation of state. The gas viscosity was computed with a correlation from Lee at al. [7].
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Erik Lindeberg et al. / Energy Procedia 114 (2017) 4279 – 4286 Table 1. Gas composition
Component Methane Nitrogen Carbon dioxide Ethane Propane Butane
Concentration, mole fraction 0.951 0.003 0.002 0.040 0.003 0.001
The properties of CO2 at reservoir and leakage conditions were computed by an equation of state by Span and Wagner [8].
4.1 Reservoir modelling Volumes, rates and other input parameter used in the numerical reservoir simulations are summarized in Table 2. Two different thickness estimates has been reported [9, 10] and an average value was used in this study. Table 2 Reservoir input parameter for modelling
Parameter Depth at top of formation Reservoir area Reservoir net height Reservoir pressure at start Porosity Pore volume Dip Gas in place Permeability, base case Permeability, alternative Grid blocks (40 x 40 x 20) Gas plateau rate, base case Gas plateau rate, alternative
Unit m km2 m bar % million m3 ° GSm3 m2 m2 Sm3/s Sm3/s
Value 2591 1.801 61 219 23 25.25 15 4.79 0.084∙10-12 0.113∙10-12 32000 21.25 23.42
A 3D reservoir model was compiled on basis of the data above and the blowout was simulated with a reservoir simulator tool, Eclipse 100. The first test was performed with an open escape through the 7" annulus. The production exceeded immediately the observed production rate without exceeding the speed of sound at the outlet of the well Next, a constant rate test was performed with a gas loss (21.25 Sm3/s) plateau rate corresponding to the observed rate through the 42 first days of leakage. There was no exhaustion of the gas drive after 42 days and the only way to in anyway mimic the shape of the escape profile (Figure 1), was to switch the well control in the simulator from rate control to a constant well pressure control. The values on plateau rate and the permeability are very uncertain and these were selected as variables in a few sensitivity tests. An increase of the plateau rate with 10% or an increase of the permeability by 35% can be used to mimic the escape profile, but there is no rationale for selecting any of these and there was done no attempt to further history match the escape profile, as this will give no additional value on leakage mechanisms. The reservoir properties has a negligible influence on the escape profile because the bottom-hole pressure is almost constant during the whole run for all cases. This means that the reservoir is sufficiently large and has sufficiently large permeability to maintain an almost constant bottom-hole pressure for a wide range of rates. An explanation of the observed leakage profile
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including the two plateau rates and the transition between them must be found in the leakage path in and around the well and not in the reservoir. In this study, however, the most interesting period is the plateau rate period because this corresponds to a "worst case scenario". The issue of what happens in the well during the decline period and after are left to other researchers to answer. The results of some sensitivity tests are illustrated in Figure 3 and the specific parameters used in addition to the values in Table 2 are listed in Table 3. Table 3 Combinations of rate and reservoir permeability in three simulator runs cases
Case 1 2 3
Permeability, m2 0.084∙10-12 0.113∙10-12 0.113∙10-12
Plateau rate, Sm3/s 23.42 23.42 21.25
Plateau rate, million Sm3/day 2.024 2.024 1.836
Fig. 3. Simulated escape scenarios: Escape rates and bottom-hole pressure
4.1 Well modelling The gas flow along the escape pathway was modelled as flow in pipes with constrictions that limits the rates to the observed rate. In addition to the rate constrain the gas velocity can never exceed the velocity of sound in the gas. To model the hydrocarbon gas flow a standard pipe flow equation was used. There are a number of these equations [10] and the main difference is how to handle the friction factor. In this study the “1/9th power” equation was selected because it can handle gas flow at high Reynolds number. For the CO 2 well flow, an in-house well simulator for CO2 was used [11] due to its capacity to handle two-phase flow. In addition, it is based on accurate thermodynamic property calculation for CO2 and has previously been tested on CO2 blowouts.
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To find a pathway that meets the operational and physical constrains some major simplifications was needed. It was assumed that the main constriction to flow is in and near the fracture in the upper part of the casing and that the pressure at the outlet from this constriction cannot be lower than a hydrostatic backpressure of 30 bars as it escape out between the casings at 302 m depth (Figure 2). By tuning the pathway geometry, an equivalent escape pathway consisting of subsequent sections of varying size, was designed. The equivalent pathway is illustrated in Figure 4. It must be emphasised that this is one possible solution and that other geometries could meet the physical constraints.
Fig. 4. Simplified tube pathway for gas escape inside and outside of the well. The right picture is a magnification of the upper 320 m. The diameter of the smallest constriction is 0.0259 m mimicking the fracture in the casing.
The resulting density, temperature, pressure, gas velocity and velocity of sound profiles along the well is illustrated in Figure 5. At the main constriction, the velocity is limited by the velocity of sound. The same model is then applied on the CO2 well simulator and the results are illustrated in Figure 6. Key differences are summarized in Table 4. Table 4 Comparison of key data from the Aliso Canyon leakage and a similar leakage from a CO2 well
Parameter Leakage rate Leakage rate Total loss during 112 days Total loss during 112 days Total loss fraction during 112 days Pressure at casing fracture during flow Total gas in formation Total gas in formation Density at reservoir conditions Fluid temperature after constriction Fluid temperature at surface
Unit Sm3/s kg/s tonne GSm3 % bar GSm3 million tonne kg/m3 °C °C
Gas well 21.3 15.0 94500 0.134 2.8 184 4.79 3.37 133 51 9.9
CO2 well 4.87 9.11 57330 0.0307 0.37 91 8.34 15.6 618 -5.5 -70
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Fig. 5 Density, temperature, pressure, velocity of gas, velocity of sound along the escape path for gas
Fig. 6 Density, temperature, pressure, velocity of gas, velocity of sound along the escape path for CO 2
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5. Discussion and conclusion It should be noted that as soon as CO2 enters the outside of the well at 302 meter, it is not only at a lower temperature than the hydrate temperature of 11 °C, but it is also colder than the freezing point of water. This will probably limit the flow, but it is difficult to model and this effect have not been included in this study. Here it is assumed the worst case; that neither hydrates nor ice is formed. Experiments have shown that cooling a well below the freezing point of pore fluid will crack not only well cement, but also surrounding rock [12]. It is thus not recommended to repair/re-use a well after such an event. When permanently sealing the blowout well, it should also be made sure that any thermally induced cracks in the formation surrounding the well are sufficiently sealed. From a climate, perspective 0.37 % CO2 loss is tolerable when it is considered that this is the second largest gas blowout in USA. Even if the CO2 loss is smaller than for natural gas, the escape of 57 000 tonne CO2 during a 112 period in a residential area is still a serious accident. Due to much lower well pressure at the well break (91 bar for CO2 respectively 184 bar for gas); it may be much easier to remediate the well. There is a big difference how a gas storage facility and CO 2 storage is operated. As gas storage, facility is kept alive with cyclic injection and production for an extended period in addition to the time the field was operated as a hydrocarbon production period, while a CO2 storage project is a one-way operation of the field and when the formation is full, the wells can be closed down, plugged and abandoned. There will still be a risk for leakage and an extended monitoring will be needed. . References [1] Conley, S. Franco, G. Faloona, I. Blake, D. R., Peischl, J., Ryerson, T. B., Methane emissions from the 2015 Aliso Canyon blowout in Los Angeles, CA, Science 10.1126/science.aaf2348, 2016. [2] SoCalGas, Aliso Canyon Natural Gas Leak, Preliminary Estimate of Greenhouse Gas Emissions, (As of March 08, 2016), Press release. [3] Bauer, S., Blankenship, D., Dykhuizen, R., Roberts, B., Freifeld, B., Jordan, P., Pan, L., Oldenburg, C., Perfect, S., Morris, J., National Lab Activity Overview presented at Workshop on Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers, Denver, Colorado, July 12-13, 2016, (http://eesa.lbl.gov/workshop-helps-reducing-risk-future-incidents-natural-gas-storage-leak/) [4] Kuintomi, D.S., Schroeder, T., Natural Gas Storage Operations and the Geology of the Aliso Canyon Field, Los Angeles Co., California, GB 77 Geology and Tectonics of the San Fernando Valley and East Ventura Basin, 2001, Wright, T., Yeats, R. (eds.), 224 p [5] Hsü, K.J., Studies of Ventura Field, California, II: Lithology, Compaction, and Permeability of Sands, The American Association of Petroleum Geologists Bulletin V. 61, No. 2 (February 1977). p. 169 191. [6] Namson, J.S., and Davis, T.L.,1991, Detection and seismic potential of blind thrusts in the Los Angeles, Ventura and Santa Barbara areas, and adjoining Transverse Ranges, Final technical report, USGSNEHRP, Award 14-08-0001-G1687 [7] Lee, A.L., Gonzalez, M.H., Eakin, B.E. 1966. The Viscosity of Natural Gases. J Pet Technol 18 (8): 997–1000. SPE-1340-PA [8] Span, R., Wagner, W., 1996 “A New Equation of State for Carbon Dioxide Covering the Fluid Region from the Triple-Point Temperature to 100 K at Pressures up to 800 MPa”, J. Phys. Chem. Ref. Data, Vol. 25, No. 6, pp. 1509 – 1596 [9] DOGGR, 1998, California Oil & Gas Fields, Volume II – Southern, Central Coastal and Offshore California Oil and Gas Fields, ftp://ftp.consrv.ca.gov/pub/oil/publications/Datasheets/Dtasheet_vol_2.pdf [10] IGU (2006) International Gas Union (IGU) Website on Underground Gas Storage Facilities, World Wide Web Address: http://www.igu.org/html/wgc2006/WOC2database/Excel/Report_Tab_Summary_UGS_Key_Data_2006_in_operation_english.xls [11] Ouyang LB, Aziz K. Steady-state gas flow in pipes. Journal of Petroleum Science and Engineering 1996;14:137–58. [12] Lindeberg, E., Modelling pressure and temperature profile in a CO2 injection well, Energy Procedia 4 (2011) 3935–3941 [13] J. Todorovic, K. Gawel, A. Lavrov, M. Torsæter: Integrity of Downscaled Well Models Subject to Cooling. SPE 180052 paper at SPE Bergen One Day Seminar, Bergen, Norway 20 April 2016.