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Interpretation of Above Zone and Storage Zone Pressure Responses to Carbon Dioxide Injection in the 2016 CO2CRC Field Test
Available online at www.sciencedirect.com
ScienceDirect Energy Procedia 114 (2017) 5671 – 5679
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 1418 November 2016, Lausanne, Switzerland
Interpretation of above zone and storage zone pressure responses to carbon dioxide injection in the 2016 CO2CRC field test. J. Ennis-King*a,e, T. LaForcea,e, L. Patersona,e, T. Danceb,e, C. Jenkinsc,e,Y. Cinard,e a
CSIRO Energy, Private Bag 10, Clayton South, Victoria 3169, Australia CSIRO Energy, 26 Dick Perry Avenue, Kensington WA 6151, Australia c Pye Laboratory, CSIRO Black Mountan, Canberra 2601, Australia d School of Petroleum Engineering, University of New South Wales, (now at Saudi Aramco) e CO2CRC Ltd, 700 Swanston Street, University of Melbourne, Victoria 3010 Australia b
Abstract
The measurement of pressure in a permeable zone overlying a CO 2 injection zone has been tested as a useful technique for monitoring CO2 plume evolution and detecting potential leakage. From Nov 2015 to April 2016 15,000 t of CO2-rich gas were injected at the CO2CRC Otway site in Victoria, Australia, and pressure was monitored with multiple gauges both in-zone and above-zone. The pressure response to injection has been analysed by numerical methods, and it is demonstrated that the above-zone pressure response can be explained by pressure diffusion through the intervening layers. Crown Copyright © 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-reviewunder underresponsibility responsibility of the organizing committee of GHGT-13. Peer-review of the organizing committee of GHGT-13. Keywords: CO2 storage; monitoring; pressure response; above-zone
* Corresponding author. Tel.: +61-3-9545 8355; fax: +61-3-9545-8380. E-mail address: [email protected]
1876-6102 Crown Copyright © 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.2017.03.1706
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1. Introduction The measurement of downhole pressure both in a CO 2 storage formation, and in overlying permeable zones, is a key technique for monitoring CO2 plume evolution and potential leakage [1]. However, there are significant issues in interpreting such measurements: if for example there is an above-zone pressure signal during injection, how can one distinguish between the possible mechanisms for that response? [2] Is it due to pressure diffusion, leakage within the wellbore or further afield, a geomechanical response, or regional-scale groundwater variations? Does one remove other known signals, such as earth tides, water table changes or barometric pressure variations, or does the response to those signals itself contain useful information? Above-zone pressure monitoring has been trialled at the Cranfield site in Mississippi, U.S.A, while 4 million t of CO2 were injected [3]. The monitoring interval was 120 m above the injection interval. Over an 18 month period, a pressure increase of 0.8-0.9 MPa was observed in the above-zone interval, corresponding to about 0.019 Pa/s (1.6 kPa/day), while over the same period the injection zone pressure increased by about 10 MPa. There are a number of possible explanations for this, including leakage of fluid up the observation well (which was completed in both intervals), and so extensive modelling and analysis was conducted [4-7]. Leakage within the observation well was eventually excluded as a cause [8], but possibilities remain for geomechanical effects [9] or some more distant or diffuse form of leakage. Unrelated aquifer effects are also possible, given petroleum operations in other parts of the Cranfield site. Above-zone monitoring was also used at the Ketzin site in Germany, but for a much smaller scale of CO 2 injection. The above-zone interval at 446 m below ground level was 184 m higher than the storage formation at 630-636 m below ground level, and of high permeability (1.8 darcy) and net thickness (over three layers) of 12 m. Over a period of a year, an above-zone pressure increase of 7.4 kPa was observed [10]. Possible scenarios include the impact of an aquifer gas storage site at 350 m below ground level, hydraulic communication via a fault at 1.5-2 km distance, or regional changes in the hydrological water balance. These two field examples illustrate potential complications of above-zone pressure monitoring. In these cases there was no threshold set beforehand for what might constitute evidence of a leak, so that the observed pressure increase required an investment of research effort to interpret. Given other possible explanations for the pressure increase, particularly other injection operations or regional aquifer changes, it was difficult to give a definitive explanation of an observed change in pressure. As with other methods of leakage monitoring, the presumption that an actual leak is unlikely to occur or be observed means that interpretation is likely to be inconclusive as to the source of any observed pressure increase. The "Otway 2C project" is a 15,000 t test injection at the CO2CRC Otway site in South-West Victoria, Australia. Injection commenced in Dec. 2015 and continued until April 2016. The objective of this test has been to examine the lower limits of surface seismic detection and to conduct detailed pressure injection monitoring[11,12]. A key aspect of the project design was injection near the bottom of a highly permeable formation, thereby creating a thick plume near the well that is more likely to be visible on seismic images. A unique feature of the test was the installation of eight pressure and temperature gauges in the injection well, four straddling the perforations in the injection well and four in an isolated zone about 50 m above the storage interval, but within the storage formation complex. These multiple gauges provided more information than is normally available for CO2 storage projects. A variety of reservoir simulation models were used extensively in the design and analysis of the test, both for forward modelling of the expected seismic response, and to ensure the injected plume remained within regulatory constraints. This paper describes the rich data set provided by having multiple pressure and temperature measurements (both in the reservoir interval and above zone) and its use in monitoring the injection.
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2. Design The target injection zone was parasequence PS 1.1 of the Paaratte A formation at a depth of approximately 1500 m MD (measured depth). The well CRC-2 was recompleted with four pressure and temperature gauges installed near the perforated injection interval, and four more gauges installed behind a sealed sleeve in parasequence PS 2 of the lower Paaratte formation for remote monitoring, approximately 50 m above the injection interval. The gauges in the shallower interval were packed off from the injection tubing so that the pressure measurements were representative of the formation at the shallower interval, rather than pressure in the well. Table 1 gives the depths of the gauges in the well completion, where IZ is the injection zone and AZ is the above-zone. The PS 1 and PS 2 formations are believed to be separated by a low-permeability baffle that propagates the pressure signal, but will not conduct CO2 vertically into the shallower formation due to capillary entry barriers. Table 1: Depths of gauges in well completion
Gauge number 8 4 7 3 6 2 5 1
Depth (m MD) 1440.63 1442.51 1447.89 1450.58 1495.89 1497.77 1509.19 1511.07
Interval (IZ or AZ) AZ AZ AZ AZ IZ IZ IZ IZ
The injection gas, supplied from the nearby Buttress field, was approximately 80% CO 2 and 20% CH4 by mole fraction. Repeat seismic surveys were undertaken after 5,000 t, 10,000 t and at the end of injection, so the injection fell into three stages. During the second and third stages of injection (5,000-10,000 t and 10,000-15,000 t) the injection rate was varied in a square wave fashion, which is a form of harmonic injection. The purpose of the pulsing of the rate was to collect information about pressure communication between the injection interval and the overlying formation. 3. Results
The downhole pressure data is of sufficiently high quality that it is necessary to account for the coupling to barometric pressure variations at surface [13] and the effect of earth tides [14]. Water table changes due to precipitation could also have some effects [15], but are not considered here. Data were obtained for the barometric pressure variations over the interval of the test, and the earth tide forcing term was obtained from standard calculations of the effect of the gravitational variations of the Sun and Moon upon the elastic properties of the Earth [16,17]. Coupling coefficients were then fitted to the downhole data. The coupling to barometric pressure contains information about the geomechanical response of the overlying formations, while the coupling to earth tides depends on the compressibility of the formation. The latter coefficient can be used to detect changes in reservoir compressibility from changes in fluid properties (such as the presence of gases) [18], and this has been used elsewhere to detect CO2 arrival at a monitoring well [19]. In the injection zone, the earth tide coupling changed significantly once CO 2 had been injected, whereas in the above-zone interval, the coupling stayed nearly constant, indicating no change in reservoir compressibility due to CO2 near the well. Fig. 1 shows the comparison of the raw pressure signal (in blue), and the reconstructed signal (in red) after fitting the barometric and earth tide components, and fitting a low-order polynomial to match the effect of the slow variations in injection rate.
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Figure 1: Above-zone pressure signal during second phase of injection. Blue is gauge data. The red curve is the reconstructed signal after fitting barometric and earth-tide components and filtering. Pressure is in psi, and dates are in February 2016.
This analysis then allows one to subtract off the barometric and earth tide contributions to focus on the reservoir responses to injection. Fig. 2 shows the injection rates (top panel), and the in-zone pressure (middle panel) and abovezone pressure (bottom panel) during the test (note the difference in pressure scales in the two lower panels). During CO2 injection there was a clear above-zone pressure response amounting to 30 kPa over the first 5000 t of injection, compared to 180 kPa in the injection interval. Several possible mechanisms were considered, and numerical simulation was used to examine the possible contribution from pressure diffusion, which required fitting of the vertical conductivity of the reservoir to pressure. A layered radial model was constructed from the geological data, and injection was simulated using TOUGH2 with the EOS7G module for gas mixtures. Initially the pressure response in the injection interval was used to fit the average permeability of the formation, both from a standard water-injection test, and then from injection of CO2-rich gas. The response to injection interruptions or variations in the injection rate provided particularly useful information as a kind of pressure fall-off test of vertical pressure diffusion. Changes in vertical permeability have an impact on the pressure response in the injected interval, so it is necessary to perform an iterative fitting process to achieve a good match to pressure in both intervals. This results in a model that fits the magnitude and shape of the pressure response in both measured intervals far better than the usual method of fitting only the average horizontal permeability.
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Figure 2: Field data as a function of days since the start of November 2015. Top panel: injection rate in (t/d). Middle panel: in-zone pressure in MPa. Bottom panel: above-zone pressure in MPa.
Figure 3: Fitting of simulation model to field data by varying the average vertical permeability of the baffle. Top panel: above-zone pressure. Bottom panel: in-zone pressure. The time is days since the start of the test (1st December 2016). The blue curve is the field data. The black curve has the base vertical permeability of the baffle increased by a factor of 5, the red curve by a factor of 10, and the green curve by a factor of 15.
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Fig. 3 shows that by adjusting the vertical permeability of the “baffle” between the two zones, it is possible for a simulation model to fit both the in-zone and above-zone pressure response, both in magnitude and in the time-scale of the fall-off when injection stops. This is an indication that a pressure diffusion mechanism is a plausible explanation for the observed above-zone pressure response in this test. The three injection stages of 5000 t (with about 10 days between each stage) provides one kind of harmonic injection test, with a clear above-zone response. The above-zone pressure data has been examined to see if the smaller scale variations in injection rate imposed in the second and third injection stages can be observed there, but a frequency analysis indicates that the signal due to that variation is not strong enough to detect it with certainty at the level of noise. Additionally, not enough temporal cycles in injection rate were possible to distinguish their effect from other, unexplained, low-frequency oscillations that seem to be present in the data. The pressure diffusion response in this setting does complicate the use of above-zone monitoring to detect leakage, since the injection phase (when a leak is most likely to occur) is also the stage at which the abovezone pressure response can also be significant. The response to large changes in injection rate would then be a way to distinguish the pressure diffusion signal from a possible leakage signal.
Figure 4: Inferred depth of CO2/water interface in the injection interval during the part of the test. The time scale is days since the start of Novermber 2015.
Multiple gauges within each interval allowed the use of pressure differences between gauges to estimate the density of the fluid at the wellbore. In the perforated interval the movement of the CO 2/water interface in the wellbore during and post injection can be estimated, allowing for a substantial improvement in modelling the vertical distribution of the flow through the perforations [18]. Fig. 4 shows the estimated interface location in the injection interval during the first two parts of the test, using two different pairs of gauges, with the interface depths shown as horizontal lines. Clearly the interface location can only be detected when it is between that particular pair of gauges. It’s noticeable that when injection begins, the CO2/water interface is initially pushed down to the bottom of the perforations, then slowly comes back up until the water covers the location of Gauge 5. When injection stops after 5000 t, the interface
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quickly rises about 5 m up the wellbore. Similar behavior was observed during the 2011 and 2014 tests in the overlying formation for the same well [19,20]. During the second 5000 t injection, when there are variations in the injection rate (see Fig. 1), for each drop in the injection rate the CO 2/water interface comes up the well about 1 m, and then pushes back down as the rate increases. This agrees with the predictions that the vertical extent of CO2 injection is a function of injection rate [19,21]. In the above-zone monitoring interval the fluid density inferred from the pressure difference between gauges is used to verify that no CO2 has entered the monitoring interval. The temperature response at both intervals also provides information about whether there is fluid movement into the formation. Fig. 5 shows the response in the above-zone gauges to CO2 injection. Here the pressure gauges are on the outside of the tubing, and are thus in thermal contact with the cooler fluid within the tubing, so there’s an immediate temperature drop once injection begins. The sharp temperature recovery in the above-zone gauges at the end of injection (in contrast to the slow temperature recovery at the reservoir level) is further evidence that no CO2 has entered the above-zone interval at the wellbore.
Figure 5: Downhole gauge temperature in the above-zone interval during the first phase of the injection test. Time is in days since the start of November 2015
4. Conclusions The injection of 15,000 t of CO2-rich gas at the CO2CRC Otway site into a saline formation in the period Dec 2015April 2016 provided an opportunity to examine the efficacy of pressure monitoring from downhole gauges. The scale of injection is not large, so it could be regarded either as a proxy for a larger injection (with responses scaled up), or a proxy for leakage from a much larger injection. The presence of other signals, coupled to barometric pressure
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changes and earth tides, requires careful analysis to extract the reservoir response, but also provides additional information on formation compressibility. The combined interpretation of multi-level pressure and temperature gauge data was sufficient to conclude that the above zone pressure response was consistent with a pressure diffusion mechanism, and did not indicate CO2 migration. Above-zone pressure was also sensitive to large variations in injection rate, but smaller variations could not reliably be distinguished. The reservoir model as constrained to the pressure measurements provides a key input to forward modelling and informing the interpretation of the seismic response in the injection formation.
Acknowledgements The authors acknowledge the role of CO2CRC Ltd in jointly conceptualizing the project, providing technical oversight and data, and funding this research. The authors also acknowledge financial assistance provided through Australian National Low Emissions Coal Research and Development (ANLEC R&D). ANLEC R&D is supported by Australian Coal Association Low Emissions Technology Limited and the Australian Government through the Clean Energy Initiative. References [1] Chabora ER, Benson SM. Brine displacement and leakage detection using pressure measurements in aquifers overlying CO2 storage reservoirs. Energy Procedia, 2009; 1:2405–2412. [2] Cihan A, Birkholzer JT, Zhou, Q. Pressure buildup and brine migration during CO2 storage in multilayered aquifers. Ground Water, 2013; 51: 252–67. [3] Hovorka SD, Meckel TA, Trevino RH, Lu J, Nicot J-P, et al. Monitoring a large volume CO2 injection: Year two results from SECARB project at Denbury’s Cranfield, Mississippi, USA. Energy Procedia 2011; 4:3478–3485. [4] Hosseini SA, Lashgari H, Choi JW, Nicot J-P, Lu J, Hovorka SD. Static and dynamic reservoir modeling for geological CO2 sequestration at Cranfield, Mississippi, U.S.A. Int. J. Greenhouse Gas Control 2013; 18:449–462. [5] Meckel TA, Zeidouni M, Hovorka SD, Hosseini SA. Assessing sensitivity to well leakage from three years of continuous reservoir pressure monitoring during CO2 injection at Cranfield, MS, USA. Int. J. Greenhouse Gas Control 2013; 18:439–448. [6] Nicot J-P, Oldenburg CM, Houseworth JE, Choi J-W. Analysis of potential leakage pathways at the Cranfield, MS, U.S.A., CO 2 sequestration site. Int. J. Greenhouse Gas Control 2013; 18:388–400. [7] Tao Q, Bryant SL, Meckel TA. Modeling above-zone measurements of pressure and temperature for monitoring CCS sites. Int. J. Greenhouse Gas Control 2013; 18:523–530. [8] Tao Q, Bryant SL, Meckel TA. Leakage fingerprints during storage: modeling above-zone measurements of pressure and temperature. Energy Procedia 2013; 37:4310–4316. [9] Kim S, Hosseini SA. Above-zone pressure monitoring and geomechanical analyses for a field-scale CO2 injection project in Cranfield , MS. Greenhouse Gas Sci. Tech. 2014; 4:81–98. [10] Wiese B, Zimmer M, Nowak M, Pellizzari L, Pilz P. Well-based hydraulic and geochemical monitoring of the above zone of the CO2 reservoir at Ketzin, Germany. Environ. Earth Sci. 2013; 70:3709–3726. [11] Cinar Y, Ennis-King J, Paterson L. The CO2CRC Otway Project Stage 2C dynamic modelling: Final report. CO2CRC Techical report RPT12-4007, 2012. [12] Watson M, Cinar Y, Dance T, Pevzner R, Tenthorey E, Caspari E, Ennis-King J, Shulakova V, Bunch M, Urosevic M, Singh R, Gurevich B, Paterson L, Jenkins C, Hortle A, Raab M. Otway stage 2C science report: Verification of CO2 storage in a saline formation (Paaratte) using time-lapse seismic. CO2CRC Technical report RPT12-4109, 2012. [13] Lai G, Ge H, Wang W. Transfer functions of the well-aquifer systems response to atmospheric loading and Earth tide from low to highfrequency band. J. Geophys. Res. Solid Earth 2013; 118: 1904–1924. [14] Arditty PC, Ramey Jr HJ, Nur AM. Response of a closed well-reservoir system to stress induced by earth tides. In Proceedings of SPE Annual Fall Technical Conference and Exhibition, Houston Texas Oct 1-3. Society of Petroleum Engineers; 1978. [15] Matsumoto N, Kitagawa G, Roeloffs EA. Hydrological response to earthquakes in the Haibara well, central Japan – I. Groundwater level changes revealed using state space decomposition of atmospheric pressure, rainfall and tidal responses. Geophys. J. Int. 2003; 155:885-898. [16] Chang E, Firoozabadi A. Gravitational potential variations of the sun and moon for estimation of reservoir compressibility. SPE J. 2000; 5:456–465. [17] Van Camp M, Vauterin P. Tsoft: graphical and interactive software for the analysis of time series and Earth tides. Comp. Geosci. 2005; 31:631-640.
J. Ennis-King et al. / Energy Procedia 114 (2017) 5671 – 5679 [18] Paterson, L, Ennis-King, J, Friefeld, B. Monitoring wellbore fluid displacement in the perforation interval using multiple downhole pressure and temperature gauges.In SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, 25-27 October 2016 (paper SPE 28804).Society of Petroleum Engineers; 2016. [19] Ennis-King J, Paterson L, Dance T, Freifeld B, Zhang Y. Variability in field-scale residual CO2 saturation: evidence from pressure and temperature data during the CO2CRC residual saturation and dissolution test sequence. (in preparation) [20] Ennis-King J, LaForce T, Paterson L, Black JR, Vu HP, Haese RR, Serno S, Gilfillan S, Johnson G, Freifeld B, Singh R. Stepping into the same river twice: field evidence for the repeatability of a CO2 injection test. Energy Procedia 2016 (this volume). [21] Kumar N, Bryant SL. Semi-analytical model to determine perforation interval for secure CO2 storage in saline aquifers. Energy Procedia 2009; 1:3071–3078.
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ScienceDirect Energy Procedia 114 (2017) 5671 – 5679
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 1418 November 2016, Lausanne, Switzerland
Interpretation of above zone and storage zone pressure responses to carbon dioxide injection in the 2016 CO2CRC field test. J. Ennis-King*a,e, T. LaForcea,e, L. Patersona,e, T. Danceb,e, C. Jenkinsc,e,Y. Cinard,e a
CSIRO Energy, Private Bag 10, Clayton South, Victoria 3169, Australia CSIRO Energy, 26 Dick Perry Avenue, Kensington WA 6151, Australia c Pye Laboratory, CSIRO Black Mountan, Canberra 2601, Australia d School of Petroleum Engineering, University of New South Wales, (now at Saudi Aramco) e CO2CRC Ltd, 700 Swanston Street, University of Melbourne, Victoria 3010 Australia b
Abstract
The measurement of pressure in a permeable zone overlying a CO 2 injection zone has been tested as a useful technique for monitoring CO2 plume evolution and detecting potential leakage. From Nov 2015 to April 2016 15,000 t of CO2-rich gas were injected at the CO2CRC Otway site in Victoria, Australia, and pressure was monitored with multiple gauges both in-zone and above-zone. The pressure response to injection has been analysed by numerical methods, and it is demonstrated that the above-zone pressure response can be explained by pressure diffusion through the intervening layers. Crown Copyright © 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-reviewunder underresponsibility responsibility of the organizing committee of GHGT-13. Peer-review of the organizing committee of GHGT-13. Keywords: CO2 storage; monitoring; pressure response; above-zone
* Corresponding author. Tel.: +61-3-9545 8355; fax: +61-3-9545-8380. E-mail address: [email protected]
1876-6102 Crown Copyright © 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.2017.03.1706
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1. Introduction The measurement of downhole pressure both in a CO 2 storage formation, and in overlying permeable zones, is a key technique for monitoring CO2 plume evolution and potential leakage [1]. However, there are significant issues in interpreting such measurements: if for example there is an above-zone pressure signal during injection, how can one distinguish between the possible mechanisms for that response? [2] Is it due to pressure diffusion, leakage within the wellbore or further afield, a geomechanical response, or regional-scale groundwater variations? Does one remove other known signals, such as earth tides, water table changes or barometric pressure variations, or does the response to those signals itself contain useful information? Above-zone pressure monitoring has been trialled at the Cranfield site in Mississippi, U.S.A, while 4 million t of CO2 were injected [3]. The monitoring interval was 120 m above the injection interval. Over an 18 month period, a pressure increase of 0.8-0.9 MPa was observed in the above-zone interval, corresponding to about 0.019 Pa/s (1.6 kPa/day), while over the same period the injection zone pressure increased by about 10 MPa. There are a number of possible explanations for this, including leakage of fluid up the observation well (which was completed in both intervals), and so extensive modelling and analysis was conducted [4-7]. Leakage within the observation well was eventually excluded as a cause [8], but possibilities remain for geomechanical effects [9] or some more distant or diffuse form of leakage. Unrelated aquifer effects are also possible, given petroleum operations in other parts of the Cranfield site. Above-zone monitoring was also used at the Ketzin site in Germany, but for a much smaller scale of CO 2 injection. The above-zone interval at 446 m below ground level was 184 m higher than the storage formation at 630-636 m below ground level, and of high permeability (1.8 darcy) and net thickness (over three layers) of 12 m. Over a period of a year, an above-zone pressure increase of 7.4 kPa was observed [10]. Possible scenarios include the impact of an aquifer gas storage site at 350 m below ground level, hydraulic communication via a fault at 1.5-2 km distance, or regional changes in the hydrological water balance. These two field examples illustrate potential complications of above-zone pressure monitoring. In these cases there was no threshold set beforehand for what might constitute evidence of a leak, so that the observed pressure increase required an investment of research effort to interpret. Given other possible explanations for the pressure increase, particularly other injection operations or regional aquifer changes, it was difficult to give a definitive explanation of an observed change in pressure. As with other methods of leakage monitoring, the presumption that an actual leak is unlikely to occur or be observed means that interpretation is likely to be inconclusive as to the source of any observed pressure increase. The "Otway 2C project" is a 15,000 t test injection at the CO2CRC Otway site in South-West Victoria, Australia. Injection commenced in Dec. 2015 and continued until April 2016. The objective of this test has been to examine the lower limits of surface seismic detection and to conduct detailed pressure injection monitoring[11,12]. A key aspect of the project design was injection near the bottom of a highly permeable formation, thereby creating a thick plume near the well that is more likely to be visible on seismic images. A unique feature of the test was the installation of eight pressure and temperature gauges in the injection well, four straddling the perforations in the injection well and four in an isolated zone about 50 m above the storage interval, but within the storage formation complex. These multiple gauges provided more information than is normally available for CO2 storage projects. A variety of reservoir simulation models were used extensively in the design and analysis of the test, both for forward modelling of the expected seismic response, and to ensure the injected plume remained within regulatory constraints. This paper describes the rich data set provided by having multiple pressure and temperature measurements (both in the reservoir interval and above zone) and its use in monitoring the injection.
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2. Design The target injection zone was parasequence PS 1.1 of the Paaratte A formation at a depth of approximately 1500 m MD (measured depth). The well CRC-2 was recompleted with four pressure and temperature gauges installed near the perforated injection interval, and four more gauges installed behind a sealed sleeve in parasequence PS 2 of the lower Paaratte formation for remote monitoring, approximately 50 m above the injection interval. The gauges in the shallower interval were packed off from the injection tubing so that the pressure measurements were representative of the formation at the shallower interval, rather than pressure in the well. Table 1 gives the depths of the gauges in the well completion, where IZ is the injection zone and AZ is the above-zone. The PS 1 and PS 2 formations are believed to be separated by a low-permeability baffle that propagates the pressure signal, but will not conduct CO2 vertically into the shallower formation due to capillary entry barriers. Table 1: Depths of gauges in well completion
Gauge number 8 4 7 3 6 2 5 1
Depth (m MD) 1440.63 1442.51 1447.89 1450.58 1495.89 1497.77 1509.19 1511.07
Interval (IZ or AZ) AZ AZ AZ AZ IZ IZ IZ IZ
The injection gas, supplied from the nearby Buttress field, was approximately 80% CO 2 and 20% CH4 by mole fraction. Repeat seismic surveys were undertaken after 5,000 t, 10,000 t and at the end of injection, so the injection fell into three stages. During the second and third stages of injection (5,000-10,000 t and 10,000-15,000 t) the injection rate was varied in a square wave fashion, which is a form of harmonic injection. The purpose of the pulsing of the rate was to collect information about pressure communication between the injection interval and the overlying formation. 3. Results
The downhole pressure data is of sufficiently high quality that it is necessary to account for the coupling to barometric pressure variations at surface [13] and the effect of earth tides [14]. Water table changes due to precipitation could also have some effects [15], but are not considered here. Data were obtained for the barometric pressure variations over the interval of the test, and the earth tide forcing term was obtained from standard calculations of the effect of the gravitational variations of the Sun and Moon upon the elastic properties of the Earth [16,17]. Coupling coefficients were then fitted to the downhole data. The coupling to barometric pressure contains information about the geomechanical response of the overlying formations, while the coupling to earth tides depends on the compressibility of the formation. The latter coefficient can be used to detect changes in reservoir compressibility from changes in fluid properties (such as the presence of gases) [18], and this has been used elsewhere to detect CO2 arrival at a monitoring well [19]. In the injection zone, the earth tide coupling changed significantly once CO 2 had been injected, whereas in the above-zone interval, the coupling stayed nearly constant, indicating no change in reservoir compressibility due to CO2 near the well. Fig. 1 shows the comparison of the raw pressure signal (in blue), and the reconstructed signal (in red) after fitting the barometric and earth tide components, and fitting a low-order polynomial to match the effect of the slow variations in injection rate.
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Figure 1: Above-zone pressure signal during second phase of injection. Blue is gauge data. The red curve is the reconstructed signal after fitting barometric and earth-tide components and filtering. Pressure is in psi, and dates are in February 2016.
This analysis then allows one to subtract off the barometric and earth tide contributions to focus on the reservoir responses to injection. Fig. 2 shows the injection rates (top panel), and the in-zone pressure (middle panel) and abovezone pressure (bottom panel) during the test (note the difference in pressure scales in the two lower panels). During CO2 injection there was a clear above-zone pressure response amounting to 30 kPa over the first 5000 t of injection, compared to 180 kPa in the injection interval. Several possible mechanisms were considered, and numerical simulation was used to examine the possible contribution from pressure diffusion, which required fitting of the vertical conductivity of the reservoir to pressure. A layered radial model was constructed from the geological data, and injection was simulated using TOUGH2 with the EOS7G module for gas mixtures. Initially the pressure response in the injection interval was used to fit the average permeability of the formation, both from a standard water-injection test, and then from injection of CO2-rich gas. The response to injection interruptions or variations in the injection rate provided particularly useful information as a kind of pressure fall-off test of vertical pressure diffusion. Changes in vertical permeability have an impact on the pressure response in the injected interval, so it is necessary to perform an iterative fitting process to achieve a good match to pressure in both intervals. This results in a model that fits the magnitude and shape of the pressure response in both measured intervals far better than the usual method of fitting only the average horizontal permeability.
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Figure 2: Field data as a function of days since the start of November 2015. Top panel: injection rate in (t/d). Middle panel: in-zone pressure in MPa. Bottom panel: above-zone pressure in MPa.
Figure 3: Fitting of simulation model to field data by varying the average vertical permeability of the baffle. Top panel: above-zone pressure. Bottom panel: in-zone pressure. The time is days since the start of the test (1st December 2016). The blue curve is the field data. The black curve has the base vertical permeability of the baffle increased by a factor of 5, the red curve by a factor of 10, and the green curve by a factor of 15.
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Fig. 3 shows that by adjusting the vertical permeability of the “baffle” between the two zones, it is possible for a simulation model to fit both the in-zone and above-zone pressure response, both in magnitude and in the time-scale of the fall-off when injection stops. This is an indication that a pressure diffusion mechanism is a plausible explanation for the observed above-zone pressure response in this test. The three injection stages of 5000 t (with about 10 days between each stage) provides one kind of harmonic injection test, with a clear above-zone response. The above-zone pressure data has been examined to see if the smaller scale variations in injection rate imposed in the second and third injection stages can be observed there, but a frequency analysis indicates that the signal due to that variation is not strong enough to detect it with certainty at the level of noise. Additionally, not enough temporal cycles in injection rate were possible to distinguish their effect from other, unexplained, low-frequency oscillations that seem to be present in the data. The pressure diffusion response in this setting does complicate the use of above-zone monitoring to detect leakage, since the injection phase (when a leak is most likely to occur) is also the stage at which the abovezone pressure response can also be significant. The response to large changes in injection rate would then be a way to distinguish the pressure diffusion signal from a possible leakage signal.
Figure 4: Inferred depth of CO2/water interface in the injection interval during the part of the test. The time scale is days since the start of Novermber 2015.
Multiple gauges within each interval allowed the use of pressure differences between gauges to estimate the density of the fluid at the wellbore. In the perforated interval the movement of the CO 2/water interface in the wellbore during and post injection can be estimated, allowing for a substantial improvement in modelling the vertical distribution of the flow through the perforations [18]. Fig. 4 shows the estimated interface location in the injection interval during the first two parts of the test, using two different pairs of gauges, with the interface depths shown as horizontal lines. Clearly the interface location can only be detected when it is between that particular pair of gauges. It’s noticeable that when injection begins, the CO2/water interface is initially pushed down to the bottom of the perforations, then slowly comes back up until the water covers the location of Gauge 5. When injection stops after 5000 t, the interface
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quickly rises about 5 m up the wellbore. Similar behavior was observed during the 2011 and 2014 tests in the overlying formation for the same well [19,20]. During the second 5000 t injection, when there are variations in the injection rate (see Fig. 1), for each drop in the injection rate the CO 2/water interface comes up the well about 1 m, and then pushes back down as the rate increases. This agrees with the predictions that the vertical extent of CO2 injection is a function of injection rate [19,21]. In the above-zone monitoring interval the fluid density inferred from the pressure difference between gauges is used to verify that no CO2 has entered the monitoring interval. The temperature response at both intervals also provides information about whether there is fluid movement into the formation. Fig. 5 shows the response in the above-zone gauges to CO2 injection. Here the pressure gauges are on the outside of the tubing, and are thus in thermal contact with the cooler fluid within the tubing, so there’s an immediate temperature drop once injection begins. The sharp temperature recovery in the above-zone gauges at the end of injection (in contrast to the slow temperature recovery at the reservoir level) is further evidence that no CO2 has entered the above-zone interval at the wellbore.
Figure 5: Downhole gauge temperature in the above-zone interval during the first phase of the injection test. Time is in days since the start of November 2015
4. Conclusions The injection of 15,000 t of CO2-rich gas at the CO2CRC Otway site into a saline formation in the period Dec 2015April 2016 provided an opportunity to examine the efficacy of pressure monitoring from downhole gauges. The scale of injection is not large, so it could be regarded either as a proxy for a larger injection (with responses scaled up), or a proxy for leakage from a much larger injection. The presence of other signals, coupled to barometric pressure
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changes and earth tides, requires careful analysis to extract the reservoir response, but also provides additional information on formation compressibility. The combined interpretation of multi-level pressure and temperature gauge data was sufficient to conclude that the above zone pressure response was consistent with a pressure diffusion mechanism, and did not indicate CO2 migration. Above-zone pressure was also sensitive to large variations in injection rate, but smaller variations could not reliably be distinguished. The reservoir model as constrained to the pressure measurements provides a key input to forward modelling and informing the interpretation of the seismic response in the injection formation.
Acknowledgements The authors acknowledge the role of CO2CRC Ltd in jointly conceptualizing the project, providing technical oversight and data, and funding this research. The authors also acknowledge financial assistance provided through Australian National Low Emissions Coal Research and Development (ANLEC R&D). ANLEC R&D is supported by Australian Coal Association Low Emissions Technology Limited and the Australian Government through the Clean Energy Initiative. References [1] Chabora ER, Benson SM. Brine displacement and leakage detection using pressure measurements in aquifers overlying CO2 storage reservoirs. Energy Procedia, 2009; 1:2405–2412. [2] Cihan A, Birkholzer JT, Zhou, Q. Pressure buildup and brine migration during CO2 storage in multilayered aquifers. Ground Water, 2013; 51: 252–67. [3] Hovorka SD, Meckel TA, Trevino RH, Lu J, Nicot J-P, et al. Monitoring a large volume CO2 injection: Year two results from SECARB project at Denbury’s Cranfield, Mississippi, USA. Energy Procedia 2011; 4:3478–3485. [4] Hosseini SA, Lashgari H, Choi JW, Nicot J-P, Lu J, Hovorka SD. Static and dynamic reservoir modeling for geological CO2 sequestration at Cranfield, Mississippi, U.S.A. Int. J. Greenhouse Gas Control 2013; 18:449–462. [5] Meckel TA, Zeidouni M, Hovorka SD, Hosseini SA. Assessing sensitivity to well leakage from three years of continuous reservoir pressure monitoring during CO2 injection at Cranfield, MS, USA. Int. J. Greenhouse Gas Control 2013; 18:439–448. [6] Nicot J-P, Oldenburg CM, Houseworth JE, Choi J-W. Analysis of potential leakage pathways at the Cranfield, MS, U.S.A., CO 2 sequestration site. Int. J. Greenhouse Gas Control 2013; 18:388–400. [7] Tao Q, Bryant SL, Meckel TA. Modeling above-zone measurements of pressure and temperature for monitoring CCS sites. Int. J. Greenhouse Gas Control 2013; 18:523–530. [8] Tao Q, Bryant SL, Meckel TA. Leakage fingerprints during storage: modeling above-zone measurements of pressure and temperature. Energy Procedia 2013; 37:4310–4316. [9] Kim S, Hosseini SA. Above-zone pressure monitoring and geomechanical analyses for a field-scale CO2 injection project in Cranfield , MS. Greenhouse Gas Sci. Tech. 2014; 4:81–98. [10] Wiese B, Zimmer M, Nowak M, Pellizzari L, Pilz P. Well-based hydraulic and geochemical monitoring of the above zone of the CO2 reservoir at Ketzin, Germany. Environ. Earth Sci. 2013; 70:3709–3726. [11] Cinar Y, Ennis-King J, Paterson L. The CO2CRC Otway Project Stage 2C dynamic modelling: Final report. CO2CRC Techical report RPT12-4007, 2012. [12] Watson M, Cinar Y, Dance T, Pevzner R, Tenthorey E, Caspari E, Ennis-King J, Shulakova V, Bunch M, Urosevic M, Singh R, Gurevich B, Paterson L, Jenkins C, Hortle A, Raab M. Otway stage 2C science report: Verification of CO2 storage in a saline formation (Paaratte) using time-lapse seismic. CO2CRC Technical report RPT12-4109, 2012. [13] Lai G, Ge H, Wang W. Transfer functions of the well-aquifer systems response to atmospheric loading and Earth tide from low to highfrequency band. J. Geophys. Res. Solid Earth 2013; 118: 1904–1924. [14] Arditty PC, Ramey Jr HJ, Nur AM. Response of a closed well-reservoir system to stress induced by earth tides. In Proceedings of SPE Annual Fall Technical Conference and Exhibition, Houston Texas Oct 1-3. Society of Petroleum Engineers; 1978. [15] Matsumoto N, Kitagawa G, Roeloffs EA. Hydrological response to earthquakes in the Haibara well, central Japan – I. Groundwater level changes revealed using state space decomposition of atmospheric pressure, rainfall and tidal responses. Geophys. J. Int. 2003; 155:885-898. [16] Chang E, Firoozabadi A. Gravitational potential variations of the sun and moon for estimation of reservoir compressibility. SPE J. 2000; 5:456–465. [17] Van Camp M, Vauterin P. Tsoft: graphical and interactive software for the analysis of time series and Earth tides. Comp. Geosci. 2005; 31:631-640.
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