- Email: [email protected]
Simultaneous CO2 injection and water production to optimise aquifer storage capacity
International Journal of Greenhouse Gas Control 5 (2011) 555–564
Contents lists available at ScienceDirect
International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
Simultaneous CO2 injection and water production to optimise aquifer storage capacity Per Eirik S. Bergmo ∗ , Alv-Arne Grimstad, Erik Lindeberg SINTEF Petroleum Research, N-7465 Trondheim, Norway
a r t i c l e
i n f o
Article history: Received 15 October 2009 Received in revised form 2 September 2010 Accepted 15 September 2010 Available online 3 November 2010 Keywords: CO2 aquifer storage Pressure control Storage resources Utsira formation Johansen formation Water production
a b s t r a c t The estimates for geological CO2 storage capacity worldwide vary, but it is generally believed that the capacity in saline aquifers will be sufficient for the amounts of CO2 that will need to be stored. The effort required to select and qualify a geological storage site for safe storage will, however, be significant and storage capacity may be a limited resource regionally. Both from a economic and resource management perspective it is therefore important that potential storage sites are exploited to their full potential. In static capacity estimates, where the maximum stored amount of CO2 is given as a fraction of the formation pore volume, typically arrive at efficiency factors in the range of a few per cents. Recent work has shown that when the dynamic behaviour of the injected CO2 is taken into account, the efficiency factor will be reduced because of the increase in pore pressure in the region around the injection well(s). The increase in pore pressure will propagate much further than the CO2 . The EU directive on geological CO2 storage specifically addresses the restriction that will apply when different storage sites are interacting due to pressure communication. Consequently, the pore pressure increase at the boundary of the storage license area will be an important limiting factor for the amount of CO2 that can be injected. One obvious method to control the pore pressure is to produce water from the aquifer at some distance from the CO2 injection wells. This paper discusses results from simulations of CO2 injection in two aquifers on the Norwegian Continental Shelf; the Johansen aquifer and the southern part of the Utsira aquifer. These aquifers are candidates for injection of CO2 shipped out via pipeline from the Norwegian West Coast. The injected amounts of CO2 over a period of 50 years are 0.518 Gtonne for the Johansen aquifer and 1.04 Gtonne for the Utsira aquifer. Several design options for the injection operations are investigated: Injection of CO2 without water production; injection into several wells to distribute the injected fluids and reduce the local pressure increase around each injection well; and injection with simultaneous production of water from one or more wells. The boundaries of the aquifer formations are assumed closed in all simulations. The possible consequences of other types of boundary conditions (semi-closed or open) are briefly discussed. © 2010 Elsevier Ltd. All rights reserved.
1. Introduction Previous estimates of geological storage resources have indicated that the global capacity should not be a limiting factor for CO2 capture and storage (CCS) as a mitigation option to reduce climate warming (Holloway et al., 1996; IPCC, 2005; VangkildePedersen et al., 2009). Even if these estimates assume that only a fraction of the formation pore volume can be utilised as effective storage space for dense CO2 , these estimates can only be realised if the formation pore pressure is effectively managed during the injection period (Lindeberg et al., 2009). It is important to realise that the pore space underneath the seal of a prospective aquifer
∗ Corresponding author. E-mail address: [email protected] (P.E.S. Bergmo). 1750-5836/$ – see front matter © 2010 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2010.09.002
storage site is already filled with water which has low compressibility. If the formation is assumed to be a closed unit, the only space that injected CO2 can occupy will be from compression of this water and from expansion of the pore space by compression of the rock minerals (usually negligible) and by increasing the bulk volume of the formation, (accompanied by an increase in the pore pressure of the formation). The low compressibility of rock and water means that utilisation of more than 1–2% of the pore space will lead to a pressure increase that might compromise the integrity of the cap rock or activate faults. If CCS shall be applied as a large scale option to mitigate climate warming (Odenberger et al., 2008) a larger fraction of the pore space will need to be utilised. Some relief may be found in the observation that fully closed boundaries are rarely found for aquifer units. If open or semiclosed boundary conditions (lateral and vertical) for the storage
556
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
formation is assumed, the utilised pore space may be larger, since pore water may then flow into neighbouring formations and some of the pressure increase will be avoided (Birkholzer and Zhou, 2009; Birkholzer et al., 2009; Nicot, 2008). The simulated pressure increase shown in this paper can therefore be considered to be conservative. However, if the formation(s) that the pore water would flow into also are underground resources of some kind (potential CO2 storage sites, potable water resources, etc.), conflicts of interest would arise which could make this kind of pressure control unfeasible. Uncontrolled displacement of formation water, typically brine, upward into shallow aquifers or to the surface is not a desired option for pressure control. The EU directive on geological CO2 storage (EU Directive, 2009) even contains a provision that a storage operation should be managed in such a way that it will not degrade other storage sites in the same hydraulic unit. A conclusion from this is that it will be necessary to control the pore pressure in some way to avoid that the pressure increase propagates too far from the injection point. This paper investigates one potentially efficient way to actively control pressure in the reservoir by producing formation water from dedicated water production wells. The method is investigated through model simulation of two potential saline aquifer storage sites on the continental shelf west of Norway. 1.1. Johansen and Utsira formations The location of the two aquifer formations used in this study is illustrated in Fig. 1.
The Johansen formation is a promising candidate for permanent storage of CO2 conveniently located near the coast only 70 km from Mongstad, a major CO2 source at the west coast of Norway. The lower Jurassic Johansen formation of the Dunlin Group consists of an east-west dipping sand stone formation with several large vertical faults in the north-south direction, some with a throw of several hundred meters. The north-western part of the formation lies around 600 m below the oil and gas bearing formations in the Troll field. The main faults also penetrates the Troll oil and gas field where they are sealing (part of the trap) and it is therefore assumed that there is no lateral communication over the faults in the Johansen formation. The shallow part of the formation is less than 40 km from Mongstad and the formation deepen towards west to a depth of 3200 m over a distance of around 60 km. The thickness of the sandy part of the formation varies from a few meters in the eastern part to around 150 m in central and western parts. The Utsira formation is one of the large aquifers in the North Sea (areal extent 24,000 km2 ). In the southern part, large areas of the formation have a thickness of more than 200 m. The formation thins out to the east. More than 10 million tonne of CO2 has already been injected into the southern part of the formation during the Sleipner injection project since 1996 (see e.g., Chadwick et al., 2006; Arts et al., 2008). The behaviour of the injected CO2 has been extensively monitored and this has revealed geological information about the internal structure and transport properties of the formation. The main capillary seal, the Nordland formation, is expected to provide safe storage, and all monitoring results to date support this assumption.
Fig. 1. Location of aquifers and areas for detailed model studies (pink polygons). The southern area is part of the Utsira aquifer, while the northern area is part of the Johansen aquifer. Hypothetical pipelines from CO2 point sources at Kårstø and Mongstad are shown, each ending at the location of the injection wells in the model studies. Depth is in m, and the axes show UTM31-coordinates. (For interpretation of the references to color in text, the reader is referred to the web version of the article.)
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
2. Compressibility and pressure increase Assuming that the formation targeted for CO2 injection is a closed entity with a given initial pore volume, the injection of CO2 will result in a compression of the existing formation fluids and an increase in pore volume due to rock compressibility. The resulting average increase in pressure is proportional to the in situ volume of the injected phase. This can be expressed as p =
Vinj Vpor ct
,
(1)
where Vinj is the in situ volume of injected phase, Vpor is the total pore volume and ct is the total compressibility. The total compressibility is given by the sum of the fluid compressibility, cw , and the rock compressibility, cr , and is expressed by ct = cw + cr . The compressibility of formation water is mainly a function of temperature, salinity and depth and does not vary very much between formations. The typical range of compressibility for the Johansen and Utsira formation water is between cw = 3 × 10−5 and cw = 4 × 10−5 bar−1 . The rock compressibility, however, varies with an order of magnitude between the unconsolidated sand in Utsira, cr = 3.5 × 10−4 bar−1 , and the consolidated sand in Johansen, cr = 4 × 10−5 bar−1 . For the Utsira formation the rock compressibility value used for the model studies in this paper is based on measured values from the formation (Springer et al., 2002). For the Johansen formation the compressibility has been estimated with the Hall correlation (e.g., Bradley, 1987). With these compressibility values, injection of CO2 corresponding to 1% of the pore volume will give an approximate average pressure increase of 25 bar for the Utsira formation and 150 bar for the Johansen formation. As the formation pressure increases, the probability of a mechanical failure of the cap rock also increases. Moss et al. (2003) have compared the reservoir pressures with the lithostatic pressure gradient in several of the formations in the North Viking Graben in the North Sea and found that in general the maximum observed formation pressure corresponds to approximately 80% of the lithostatic pressure. This can be interpreted as the pressure limit where microfractures open in the caprock, allowing fluids to leak through and suppressing further pressure build-up in the formation. The increase in pressure in Eq. (1) can be interpreted as the pressure increase at every point in the formation after pressure equilibrium has been reached. The local pressure increase will be much higher since the pressure increase needs some time to diffuse into the formation away from the injection well. Outside of the CO2 plume the fluid flow will be single phase, and the time scale of the pressure diffusion is given by T=
L2 , Dh
where Dh =
k ct
557
be to use long (horizontal) injection wells or to use several injection wells. However, since the region of elevated pressure increase for large scale injection operations will extend further than current limits on horizontal well lengths, this option will not be sufficient for pressure control, although it may be selected for other reasons (e.g., to minimise the risk of re-production of CO2 ). The EU directive on geological storage of CO2 (EU Directive, 2009) states that in case more than one storage site is located in the same hydraulic unit, the potential pressure interactions between the storage operations should not risk compromising the seal in any part of the unit. One promising storage design option for avoiding pressure increases that may compromise the formation seal or interfere with other interests such as other storage operations is to produce water out of the storage formation in sufficient amounts to control the pressure increase. This methodology has been investigated in several publications (e.g., Yang, 2008; Lindeberg et al., 2009) and is being considered for the Gorgon CO2 aquifer injection project (Flett et al., 2008). The present paper investigates this option for the two model cases. It is suggested to let the water production wells be passive producers, i.e., the wells produce only from the increase in formation pressure and not by active pumping. This will give increased production rates when the pressure in the formation increases and a decrease in production rate with increasing distance from injection wells. The production wells should be placed as close as possible to the injectors without risking production of CO2 . This can be achieved by placing the production well down-dip and perforate the well in the lower part of the formation (see Fig. 2). The produced water may represent an environmental challenge in itself, since most candidate aquifer formations for CO2 storage will contain water with salinity too high for release at the surface. The notable exception to this is storage sites under the sea bottom, where the salinity of the formation water may actually be lower than seawater. On-shore the saline formation water may be de-salinated and used for agriculture or for industrial purposes (Newmark et al., 2010). In this paper it is assumed that the water can be released in the ocean (after suitable treatment). 3. Simulation models The formation water viscosity, CO2 solubility and formation volume factor used in the simulations are based on Numbere et al. (1977), Diamond and Akinfiev (2003a,b) and Enick and Klara (1990). The injection gas is assumed to be pure CO2 with properties taken from correlations prepared by Span and Wagner (1996) and Vukalovich and Altunin (1969).
(2)
is the hydraulic diffusivity, which depends on the mobility of the fluid (k/), the porosity and the total compressibility. From welltest theory it is known that the fluid pressure gradient in the well region depends on the injection rate and the length of the contact between well and formation, in addition to the reservoir properties. Thus, two available options to reduce local pressure increase would
3.1. Johansen simulation model The most promising part of the Johansen formation for CO2 storage is the part west of the main north-south fault. The eastern part slopes upward toward the coast and has no proven seal along the eastern boundary. The western part slopes upward to the north-west, away from the main fault, but contains at least one
Fig. 2. Schematic view of placement of injection and production wells during CO2 injection. Note that the injection well may also be constructed as a horizontal well to increase the contact between well and formation.
558
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
between 0.15 and 0.29, with the porosity within a zone degrading towards south as the depth of the formation increases. Horizontal permeability in the sand varies between 300 and 1500 mD and is correlated to the porosity. The vertical to horizontal permeability ratio is set to 0.1, typical for consolidated sediments. An outline of the simulation model is shown in Fig. 3 (for further details on the simulation model see Bergmo and Lindeberg, 2007 and Bergmo et al., 2009a). 3.2. Utsira simulation model
Fig. 3. Outline of the Johansen simulation model in the north-western part of the formation. The colouring shows the depth of the top surface of the formation, in meters. The coordinates are given in UTM31-coordinates. The location of the injection wells are shown in Fig. 5. (For interpretation of the references to color in text, the reader is referred to the web version of the article.)
large fault and several smaller faults directed mainly in a northsouth direction. These faults extend up to the Troll hydrocarbon reservoir overlying parts of the Johansen formation. The present study assumes that the faults are sealing. Sensitivity studies on the fault transmissibility and possible consequences for the hydrocarbon production from Troll have been conducted in another project (Bergmo and Lindeberg, 2007). Mapping of the reservoir properties of the western parts of the Johansen formation through interpretation of well logs is most extensive to the north. Few wells penetrate the southern part, but it is assumed that the reservoir properties degrade toward the south as the formation deepens. The main part of the modelling reported in the present paper for the Johansen formation is performed on the north-western part shown in Fig. 3. The region selected for detailed studies is bounded to the west, north and east by faults that are assumed sealing. Communication with the rest of the formation is along the southern boundary of the simulation model. Pore volume multipliers are applied at this boundary to give the simulation model a total pore volume equal to the full formation. This boundary condition will effectively move the average distance to the large communicating volume closer, and will give a more slowly increasing pore pressure in the near-well region than if the volumes were placed at their true distance. A simulation on a more coarsely gridded model of the whole formation is included for comparison of the pressure development using a single injection well. The simulation model for the detailed study is gridded with an average lateral grid size of 200 m by 200 m, for a total model extension of 44 km (N-S) by 33 km (E-W). Since the same model was also used for detailed long-term migration studies (reported in Bergmo and Lindeberg, 2007 and Bergmo et al., 2009a) the gridding was relatively uniform throughout the model, and no near-well grid refinement was used. An interpretation of the geological layering was used to create 18 simulation grid layers, giving a total of some 230 thousand grid blocks. The height of the grid blocks varies from around 2–3 m in the layers close to the top (sand), to around 10 m in the sand layers below. Porosity in the sand layers varies
The part of Utsira considered for detailed modelling of CO2 deposition in the present study is located at the south-eastern edge of the Utsira formation. The outline of the model area is illustrated in Fig. 4. The extent of the simulation model is 53 km east-west in the southern part (68 km total), and 80 km total north-south. The simulation model has approximately 370 thousand grid blocks with an areal size of 400 m by 400 m, and 10 grid layers. The simulation grid was also used for long-term CO2 migration studies (reported in Bergmo and Lindeberg, 2007 and Bergmo et al., 2008, 2009b), and therefore lateral gridding was uniform rather than with grid refinement around the wells. The simulation model was given a uniform porosity of 0.35. The permeability was set to 1000 mD in the lateral directions and 100 mD in the vertical direction to mimic the reduced vertical transport properties caused by the intra-sand shales observed on well logs from the Utsira formation. Further details on the simulation model can be found in Bergmo and Lindeberg (2007) and Bergmo et al. (2008, 2009b). The current interpretation of the Utsira formation in the southern part is that it thins out to the east and south. The communication with the rest of the formation will be along the western and northern boundary of the detailed model. Pore volume multipliers were used along these boundaries to give the simulation model a total pore volume equal to the full Utsira formation. As for the Johansen formation, this will give a slightly slower increase in the pore pressure around the injection well(s) than if the pore volume were placed at the correct distance from the well. The simulations on the detailed model will therefore be too optimistic with respect to the amount of CO2 that can be injected while keeping the pressure increase below a given level. 3.3. Injection scenarios For each of the storage sites the placement of the wells was selected to minimise the transport length to the onshore CO2 supply points, while at the same time being positioned where the reservoir properties were favourable. For the southern Utsira study area it was also desired to select an injection point where the long-term migration would be relatively well contained. The scenarios for annual CO2 injection rates were dictated by scenarios for the establishment of CO2 transportation hubs onshore at Mongstad and Kårstø, respectively, for the Johansen and Utsira case studies. In these scenarios, CO2 will be collected from several sources and transported to the storage formations. The development of the transportation hubs would proceed in stages, Table 1 CO2 injection profile for injection into Johansen. Total injection period is 50 years and injection starts January 2012. Period, year
2012–2013 2014 2015–2061
CO2 injection rate tonne/day
Mtonne/year
13,426 18,797 29,192
4.90 6.87 10.66
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
559
Fig. 4. Outline of the simulation model located at the southern part of the Utsira formation. The colouring shows the interpreted thickness (in meters) of the formation in the southern part of the Utsira formation. Injection well locations are marked with filled circles, while open circles mark the position of the water production wells. (For interpretation of the references to color in text, the reader is referred to the web version of the article.)
and the annually stored amounts would therefore increase in steps. A summary of the injection scenarios is given in Tables 1 and 2. The total simulated injected amounts over a 50-year injection period are 0.518 Gtonne for the Johansen aquifer and 1.04 Gtonne for the Utsira aquifer. For each of the main cases, a number of well configurations were tested, to investigate the effect of CO2 injection operation design on the formation pore pressure increase. For the Johansen study, three main configurations were tested: 1. Two injection wells with no water production. 2. Two injection wells and one water production well at the southern boundary of the model (approximately 13 km from the nearest injection well). 3. Two injection wells and one water production midway between the southern boundary and the nearest injection well. In addition, two simulations were run to investigate the effect of the boundary conditions of the detailed model region on the pressure development in the formation. To achieve this, a model of the full formation was used, with larger grid block sizes and fewer grid layers. A cut-out of this model corresponding to the detailed Table 2 CO2 injection profile for injection into Utsira. Total injection period is 50 years and injection starts January 2012. Period, year
2012–2014 2015–2016 2017–2061
CO2 injection rate tonne/day
Mtonne/year
31,653 46,613 59,293
11.6 17.0 21.7
model area was also created. Since interpreted geometry and total pore volume of the formation in the full field model does not match exactly the data used to generate the detailed model, the results of these two additional simulations cannot be compared directly to the simulations on the detailed model. For the Utsira study, three well configurations were tested: 1. Single injection well with no water production. 2. Three injection wells to distribute the pressure increase over a larger area and reduce the maximum pressure increase. 3. Three injection wells and three water production wells. In addition a simulation was run on a model of the full Utsira formation with a single injection well to investigate the effect of the implementation of the boundary between the regional detailed model and the full formation. 4. Simulation results 4.1. Johansen formation During the injection period, the flow of gas is mainly dominated by the radial spread around the injection points, displacing formation water and only to a small extent dissolving in the contacted water. Fig. 5 shows the distribution of the injected CO2 after 50 years for the case with two injection wells and a water production well at the boundary of the maximum CO2 extent. The location of the production well in the case where it is located at the southern boundary of the model is also shown. The formation pressure increases significantly in the near-well region in the case with no water production, reaching 85 bar pressure increase at the top of the formation near the injection wells
560
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
Fig. 7. Comparison of pressure increase (in bars) after 50 years of injection between full field model and a sector model with pore volume multipliers along the southern boundary. Pressure increase in the near-well region and a control volume surrounding the injection well is significantly larger when the full field is modelled, due to lower connectivity to the distant pore volumes.
Fig. 5. Simulation model of the Johansen formation showing distribution of the injected CO2 after 50 years and location of injection wells (two northern wells) and the water production wells. The red colour shows grid blocks where CO2 exists as a separate phase. Grid blocks with no CO2 are coloured blue and intermediate colours show grid blocks where CO2 exists dissolved in water but not as a separate phase. At most one production well is active in each scenario. (For interpretation of the references to color in text, the reader is referred to the web version of the article.)
after 50 years of injection. Fig. 6 shows the pressure increase for the three investigated well configurations for the Johansen injection case, given as the pressure increase near the top of the formation close to the injection well and the average pressure increase for the whole formation volume. The safe pore pressure, estimated as 0.8 times the lithostatic pressure, gives a limit on the safe pressure increase below the cap rock at the injection site of 116 bar. Even the worst-case well configuration tested, with no pressure control, gives a pressure increase below this limit. However, given that the implementation of boundary conditions may give optimistic estimates of pressure increase, reference simulations were run with a model of the full formation. The available full-field model has a lower estimate for the total pore volume of the formation, and also uses a different interpretation of the formation topography in the region for the detailed model. Therefore, the simulations on the full-field model cannot be compared directly to the detailed model simulations, but is compared to a sector model corresponding to the extent of the detailed model, and with similar boundary conditions. The results are illustrated in Fig. 7. It is seen that for this sector model, representing
the communication to the rest of the formation by pore volume mulitipliers will significantly overestimate the effective communication. The pressure increase is therefore underestimated in the sector model. From this we conclude that the detailed model also underestimates the pressure increase in the near-well region. The difference in the pressure increase at the top of the formation is close to 30 bar between the two simulations on the reference models. If this is scaled with the difference between the pressure increase in the sector models (detailed simulation model vs. sector of full-field model) the results indicates a maximum pressure increase of 110 bar in the near-well region when no water is produced from the formation. Thus, it is very likely that some kind of pressure control will be needed if the given injection schedule shall be implemented. As seen in Fig. 6, the pressure increase in the region near the injection wells is lower when formation water is allowed to escape through water production wells. But pressure increase is still large if the production well is placed close to the southern boundary of the model area. Note that the above comparison of simulations with the reference full field model shows that the efficiency of the southern water production well is probably underestimated with the boundary conditions used. If the water production well is moved closer to the injection wells, to the point where the CO2 plume just reaches the production well after 50 years of injection, the pressure increase is much lower. Fig. 8 shows the pressure increase for the case with a water production well halfway to the southern boundary of the detailed simulation model. It is noted that it will be a challenge to locate wells to maximise pressure control and at the same time avoid reproduction of injected CO2 . Even if the Johansen formation is dipping, the slope is not large enough to keep CO2 from spreading down-dip towards the water production well. The effectiveness of water production as a pressure control option depends on how much water is produced for a given injected amount of CO2 . The distance between the injection wells is a major influencing factor. Moving the production well further away from the injection wells reduce the difference between the well pressure and the hydrostatic pressure, and thus reduce the possible water production rate for a passively producing well. The produced water volume for the two well configurations with water production wells is compared to the injected CO2 volume in Fig. 9. 4.2. Utsira formation
Fig. 6. Local pressure increase below the cap rock of Johansen close to the injection wells and average pressure increase in the formation both as a function of years after start of injection.
For the Utsira formation, estimated safe pressure increase in the near-well region is 45 bar. The simulation results show that
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
561
Fig. 8. Pressure increase (in bars) after 50 years in the detailed simulation model for the well configuration with the lowest maximum pressure increase; two injection well and a water production well halfway to the southern boundary of the model.
the configuration with a single injection well is close to this critical limit, although the assumption of completely sealed formation boundaries means that this estimate will be probably be too high. Distributing the injected volume over three injection wells is seen to reduce the maximum pressure increase, but the average pressure increase in the near-well region is not much reduced. Fig. 10 shows the local pressure increase and the field-average pressure increase in the Utsira formation in the investigated scenarios. The weak topography of the Utsira aquifer (as small as a few meters per kilometer in the near-well region) makes placement of water production wells in this formation particularly challenging.
Fig. 9. Comparison of the reservoir volumes of injected CO2 and produced water in the Johansen storage scenario.
The injected gas will spread nearly radially out from an injection well. If a single injection/production well pair is used, the production well must be placed more than 13 km away from the injection well to avoid re-production of CO2 . This distance makes the pressure control for passive production wells too ineffective. With more than one injection well the size of the plume around each well will be smaller, and the production wells can be moved closer to the injection wells and therefore be more effective in controlling pressure increase. Lindeberg et al. (2009) have shown how it is possible in a large-scale deployment of CO2 injection and water produc-
Fig. 10. Local pressure increase below the cap rock of Utsira close to the injection wells and average pressure increase in the formation (dashed lines) both as a function of years since start of injection. (The pressure fluctuations in the first year are caused by the well control algorithm in the reservoir simulator.)
562
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
Fig. 11. Simulated pressure increase (in bars) in the southern part of Utsira after 50 years of injection through a single well. In the left plot the full Utsira formation is modelled, while in the right plot only the detailed model area is included, and the communication with the rest of the formation is modelled by increasing the pore volume at the boundary to the west and north.
tion to limit reproduction of injected CO2 to a small fraction of the injected volume by just sealing off any production wells violating CO2 concentration thresholds. A reference simulation with a single injection well on a model of the full formation have been performed to check the effect of implementing pore volume multipliers along the boundary of the detailed simulation model to represent the volume of the full formation. As seen in Figs. 11–13 the simulated pressure increase match fairly well in the near-well region. The match is better than in the Johansen case, probably because the wells are further away from the boundary where the pore volume multipliers are used. With some tuning it is probably feasible to use this method with even better accuracy. Fig. 14 shows the pressure increase map for the case with three injection wells and three water production wells. Comparing this with the right plot of Fig. 11 we see that the region of highest pressure increase is much more confined, in particular towards the north. In the Utsira injection scenario relatively less water is being produced as illustrated in Fig. 15. This has the expense that the large
Fig. 13. Comparison of pressure increase (in bars) after 50 years of injection between full field model and a sector model with pore volume multipliers along the western and northern boundary.
Utsira formation is pressurised 4–5 bar at end of injection even with water production. 5. Discussion and conclusions
Fig. 12. Difference between simulated pressure increase (in bars) for the two simulations in Fig. 11, inside the region of the detailed model.
In both simulation cases local pressure increase under the seal is close to the estimated safe limit if no water production is employed. Increasing the number of injection wells will reduce the maximum pressure increase. Controlling formation pressure by allowing water to be produced from passive water production wells will further reduce the pressure build-up in particular in the near-well region but also in the formation as a whole. Passive water production is considered in this study. While this production method may save costs in the production and operation of the wells, this requires that the aquifer pressure exceeds the hydrostatic pressure near the production well. A residual pressure increase will therefore propagate past the production wells and into the far parts of the aquifer. The cost of this full-aquifer pressurisation in terms of detrimental effects for future storage operations or other underground resources should be balanced against the increased cost of more active water extraction such as pumping. It is seen that even with passive water production the produced water volume is a significant fraction of the reservoir volume of
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
563
Fig. 14. Pressure increase contours for the Utsira case with three injection wells and three water production wells after 50 years of injection.
the injected CO2 . For a large injection operation the produced volumes will be on the order of 1 km3 water produced per Gtonne CO2 injected. Both the Utsira and Johansen formations are located far from the shore in the North Sea and it is assumed that an emission permit for the formation water with 3–5% salinity can be obtained. To utilise more than 1–2% of the available pore space massive water production from the formation will be necessary to constrain pressure build-up to within safe limits and to avoid interference with other potential storage projects in the same hydraulic unit. Results from the reference simulations on the full field models indicate that if no water is produced pressure increase in the far parts of the formations is still significant. After 50 years the eastern parts of the Johansen formation have a pressure increase of 20–25 bar, and the pressure increase 80 km north of the injection wells in Utsira is 2 bar.
Fig. 15. Comparison of the reservoir volumes of injected CO2 and produced water in the Utsira storage scenario with three injection wells and three water production wells.
Acknowledgements This publication has been produced with support from the BIGCCS Centre, performed under the Norwegian research program Centres for Environment-friendly Energy Research (FME). The authors acknowledge the following partners for their contributions: Aker Solutions, ConocoPhilips, Det Norske Veritas AS, Gassco AS, Hydro Aluminium AS, Shell Technology AS, Statkraft Development AS, Statoil Petroleum AS, TOTAL E&P Norge AS, and the Research Council of Norway (193816/S60). References Arts, R.J., Chadwick, A., Eiken, O., van Thibeau, S., Nooner, S., 2008. Ten years’ experience of monitoring CO2 injection in the Utsira Sand at Sleipner, offshore Norway. First Break 26, 65–72. Bergmo, P.E., Grimstad A.-A., Lindeberg, E., 2008. Storage of CO2 in the southern part of the Utsira formation (16/11). SINTEF Petroleum Research Report 54.5949.00/01/08, Confidential. Available through Norwegian Petroleum Directorate. Bergmo, P.E., Grimstad, A.-A., Lindeberg, E., 2009a. Exploring geological storage sites for CO2 from Norwegian gas power plants: Johansen formation. In: Proceedings GHGT-9, Washington 2009, pp. 2945–2952. Bergmo, P.E., Grimstad, A.-A., Lindeberg, E., 2009b. Exploring geological storage sites for CO2 from Norwegian gas power plants: Utsira South. In: Proceedings GHGT-9, Washington 2009, pp. 2953–2959. Bergmo, P.E., Lindeberg, E., 2007. Near coastal sites for storing CO2 from Mongstad and Kårstø. SINTEF Petroleum Research Report 52.5928.00/01/07, Confidential. Available through the Norwegian Petroleum Directorate. Birkholzer, J.T., Zhou, Q., Tsang, C.F., 2009. Large-scale impact of CO2 storage in deep saline aquifers: a sensitivity study on the pressure response in stratified systems. Int. J. Greenhouse Gas Control 3 (2), 181–194. Birkholzer, J.T., Zhou, Q., 2009. Basin-Scale Hydrogeologic Impacts of CO2 Storage: Capacity and Regulatory Implications. Int. J. Greenhouse Gas Control 3 (6), 745–756. Bradley, H.B., 1987. Petroleum Engineering Handbook, pp. 26–28. Chadwick, A., Arts, R., Eiken, O., Williamson, P., Williams, G., 2006. Geophysical monitoring of the CO2 plume at Sleipner, North Sea: an outline review. In: Lombardi, S., Altunina, L.K., Beaubien, S.E. (Eds.), Advances in the Geological Storage of Carbon Dioxide: International Approaches to Reduce Anthropogenic Green-
564
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
house Gas Emissions. Springer, Dordrecht, The Netherlands, pp. 303–314 (NATO Science Series IV: Earth and Environmental Sciences, 2006). Diamond, L.W., Akinfiev, N.N., 2003a. Solubility of CO2 in water from −1.5 to 100 ◦ C and from 0.1 to 100 MPa: evaluation of literature data and thermodynamic modelling. Fluid Phase Equilib. 208 (2003), 265–290. Diamond, L.W., Akinfiev, N.N., 2003b. Solubility of CO2 in water from 0 to 100 ◦ C and from 0.1 to 100 MPa: evaluation of literature data and thermodynamic modelling. Fluid Phase Equilib. 208, 265–290. Enick, R.M., Klara, S.M., 1990. CO2 solubility in water and brine under reservoir conditions. Chem. Eng. Commun. 90, 23–33. Flett, M., Beacher, G., Brantjes, J., Burt, A., Dauth, C., Koelmeyer, F., Lawrence, R., Leigh, S., McKenna, J., Gurton, R., Robinson, W.F., Tankersley, T., 2008. Gorgon project: subsurface evaluation of carbon dioxide disposal under Barrow Island. In: Paper SPE 116372 Presented at the 2008 SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia. EU Directive, 2009. Directive 2009/31/Ec Of The European Parliament And Of The Council of 23 April 2009 Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC, 2008/1/EC and Regulation (EC) No. 1013/2006. L140, Official Journal of the European Union on the geological storage of carbon dioxide and amending Council Directive 85/337/EEC, European Parliament and Council, pp 114–135. Holloway, S., Bateman, K., Barbier, J., Doherty, P., Fabriol, H., Harrison, R., Heederik, J.P., van der Meer, L.G.H., Czernichowski-Lauriol, I., Lindeberg, E.G.B., Pearce, J.M., Summerfield, I.R., Rochelle, C., Sanjuan, B., Schartzkopf, T., Kaarstad, O., Berger, B., 1996. The underground disposal of carbon dioxide. Final Report of JOULE II Project No. CT92-0031. Non Nuclear Energy R&D Programme. IPCC, 2005. IPCC special report on carbon dioxide capture and storage. In: Metz, B., Davidson, O., de Coninck, H.C., Loos, M., Meyer, L.A. (Eds.), Prepared by Working Group III of the Intergovernmental Panel on Climate Change. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442pp. Lindeberg, E., Vuillaume, J.F., Ghaderi, G., 2009. Determination of the CO2 storage capacity of the Utsira formation. Energy Procedia 1, 2777–2784. http://www.sciencedirect.com/science/journal/18766102.
Moss, B., Barson, D., Rakhit K., Dennis, H., 2003. Formation pore pressures and formation waters. In: Evans, D., Graham, C., Armour, A., Bathurst, P. (Eds. and Coordinators). Millennium Atlas: Petroleum Geology of the Central and Northern North Sea, pp. 317–329 (Chapter 18). Newmark, R.L., Friedmann, S.J., Carroll, S.A., 2010. Water challenges for geologic carbon capture and sequestration. Environ. Manage. 45 (4), 651–661. Nicot, J.P., 2008. Evaluation of large-scale carbon storage on fresh-water section of aquifers: a Texas study. Int. J. Greenhouse Gas Control 2 (4), 582–593. Numbere, D., Brigham, W.E., Standing, M.B., 1977. Correlations for Physical Properties of Petroleum Reservoir Brines. Petroleum Research Institute, Stanford University, p. 8. Odenberger, M., Kjärstad, J., Johnsson, F., 2008. Ramp-up of CO2 capture and storage within Europe. Int. J. Greenhouse Gas Control 2 (2008), 417–438. Span, R., Wagner, W., 1996. A new equation of state for carbon dioxide covering the fluid region from the triple-point temperature to 1100 K at pressures up to 800 MPa. J. Phys. Chem. Ref. Data 25 (6), 1509–1596. Springer, N., Høier, C., Lindgren, H., 2002. Mineralogical and petrophysical properties of Utsira sand before and after reaction with CO2 saturated formation water. SACS Project, Phase II, GEUS Rapport 2002/42. Vangkilde-Pedersen, T., Lyng Anthonsen, K., Smith, N., Kirk, K., Neele, P., van der Meer, B., Le Gallo, Y., Bossie-Codreanud, D., Wojcickie, A., Le Nindre, Y.-M., Hendriks, C., Dalhoff, F., Christensenh, N.P., 2009. Assessing European capacity for geological storage of carbon dioxide – the EU GeoCapacity project. Energy Procedia, vol. 1(1), February 2009, pp. 2663–2670. Greenhouse Gas Control Technologies 9, Proceedings of the 9th International Conference on Greenhouse Gas Control Technologies (GHGT-9), 16–20 November 2008, Washington DC, USA. Vukalovich, M.P., Altunin, V.V., 1969. Thermophysical Properties of Carbon Dioxide. Collet’s Publishers Ltd., London & Wellingborough, p. 419. Yang, Q., 2008. Dynamic modelling of CO2 injection in a closed saline aquifer in the Browse Basin, Western Australia. In: Paper SPE 115236 Presented at the 2008 SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia.
Contents lists available at ScienceDirect
International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
Simultaneous CO2 injection and water production to optimise aquifer storage capacity Per Eirik S. Bergmo ∗ , Alv-Arne Grimstad, Erik Lindeberg SINTEF Petroleum Research, N-7465 Trondheim, Norway
a r t i c l e
i n f o
Article history: Received 15 October 2009 Received in revised form 2 September 2010 Accepted 15 September 2010 Available online 3 November 2010 Keywords: CO2 aquifer storage Pressure control Storage resources Utsira formation Johansen formation Water production
a b s t r a c t The estimates for geological CO2 storage capacity worldwide vary, but it is generally believed that the capacity in saline aquifers will be sufficient for the amounts of CO2 that will need to be stored. The effort required to select and qualify a geological storage site for safe storage will, however, be significant and storage capacity may be a limited resource regionally. Both from a economic and resource management perspective it is therefore important that potential storage sites are exploited to their full potential. In static capacity estimates, where the maximum stored amount of CO2 is given as a fraction of the formation pore volume, typically arrive at efficiency factors in the range of a few per cents. Recent work has shown that when the dynamic behaviour of the injected CO2 is taken into account, the efficiency factor will be reduced because of the increase in pore pressure in the region around the injection well(s). The increase in pore pressure will propagate much further than the CO2 . The EU directive on geological CO2 storage specifically addresses the restriction that will apply when different storage sites are interacting due to pressure communication. Consequently, the pore pressure increase at the boundary of the storage license area will be an important limiting factor for the amount of CO2 that can be injected. One obvious method to control the pore pressure is to produce water from the aquifer at some distance from the CO2 injection wells. This paper discusses results from simulations of CO2 injection in two aquifers on the Norwegian Continental Shelf; the Johansen aquifer and the southern part of the Utsira aquifer. These aquifers are candidates for injection of CO2 shipped out via pipeline from the Norwegian West Coast. The injected amounts of CO2 over a period of 50 years are 0.518 Gtonne for the Johansen aquifer and 1.04 Gtonne for the Utsira aquifer. Several design options for the injection operations are investigated: Injection of CO2 without water production; injection into several wells to distribute the injected fluids and reduce the local pressure increase around each injection well; and injection with simultaneous production of water from one or more wells. The boundaries of the aquifer formations are assumed closed in all simulations. The possible consequences of other types of boundary conditions (semi-closed or open) are briefly discussed. © 2010 Elsevier Ltd. All rights reserved.
1. Introduction Previous estimates of geological storage resources have indicated that the global capacity should not be a limiting factor for CO2 capture and storage (CCS) as a mitigation option to reduce climate warming (Holloway et al., 1996; IPCC, 2005; VangkildePedersen et al., 2009). Even if these estimates assume that only a fraction of the formation pore volume can be utilised as effective storage space for dense CO2 , these estimates can only be realised if the formation pore pressure is effectively managed during the injection period (Lindeberg et al., 2009). It is important to realise that the pore space underneath the seal of a prospective aquifer
∗ Corresponding author. E-mail address: [email protected] (P.E.S. Bergmo). 1750-5836/$ – see front matter © 2010 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2010.09.002
storage site is already filled with water which has low compressibility. If the formation is assumed to be a closed unit, the only space that injected CO2 can occupy will be from compression of this water and from expansion of the pore space by compression of the rock minerals (usually negligible) and by increasing the bulk volume of the formation, (accompanied by an increase in the pore pressure of the formation). The low compressibility of rock and water means that utilisation of more than 1–2% of the pore space will lead to a pressure increase that might compromise the integrity of the cap rock or activate faults. If CCS shall be applied as a large scale option to mitigate climate warming (Odenberger et al., 2008) a larger fraction of the pore space will need to be utilised. Some relief may be found in the observation that fully closed boundaries are rarely found for aquifer units. If open or semiclosed boundary conditions (lateral and vertical) for the storage
556
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
formation is assumed, the utilised pore space may be larger, since pore water may then flow into neighbouring formations and some of the pressure increase will be avoided (Birkholzer and Zhou, 2009; Birkholzer et al., 2009; Nicot, 2008). The simulated pressure increase shown in this paper can therefore be considered to be conservative. However, if the formation(s) that the pore water would flow into also are underground resources of some kind (potential CO2 storage sites, potable water resources, etc.), conflicts of interest would arise which could make this kind of pressure control unfeasible. Uncontrolled displacement of formation water, typically brine, upward into shallow aquifers or to the surface is not a desired option for pressure control. The EU directive on geological CO2 storage (EU Directive, 2009) even contains a provision that a storage operation should be managed in such a way that it will not degrade other storage sites in the same hydraulic unit. A conclusion from this is that it will be necessary to control the pore pressure in some way to avoid that the pressure increase propagates too far from the injection point. This paper investigates one potentially efficient way to actively control pressure in the reservoir by producing formation water from dedicated water production wells. The method is investigated through model simulation of two potential saline aquifer storage sites on the continental shelf west of Norway. 1.1. Johansen and Utsira formations The location of the two aquifer formations used in this study is illustrated in Fig. 1.
The Johansen formation is a promising candidate for permanent storage of CO2 conveniently located near the coast only 70 km from Mongstad, a major CO2 source at the west coast of Norway. The lower Jurassic Johansen formation of the Dunlin Group consists of an east-west dipping sand stone formation with several large vertical faults in the north-south direction, some with a throw of several hundred meters. The north-western part of the formation lies around 600 m below the oil and gas bearing formations in the Troll field. The main faults also penetrates the Troll oil and gas field where they are sealing (part of the trap) and it is therefore assumed that there is no lateral communication over the faults in the Johansen formation. The shallow part of the formation is less than 40 km from Mongstad and the formation deepen towards west to a depth of 3200 m over a distance of around 60 km. The thickness of the sandy part of the formation varies from a few meters in the eastern part to around 150 m in central and western parts. The Utsira formation is one of the large aquifers in the North Sea (areal extent 24,000 km2 ). In the southern part, large areas of the formation have a thickness of more than 200 m. The formation thins out to the east. More than 10 million tonne of CO2 has already been injected into the southern part of the formation during the Sleipner injection project since 1996 (see e.g., Chadwick et al., 2006; Arts et al., 2008). The behaviour of the injected CO2 has been extensively monitored and this has revealed geological information about the internal structure and transport properties of the formation. The main capillary seal, the Nordland formation, is expected to provide safe storage, and all monitoring results to date support this assumption.
Fig. 1. Location of aquifers and areas for detailed model studies (pink polygons). The southern area is part of the Utsira aquifer, while the northern area is part of the Johansen aquifer. Hypothetical pipelines from CO2 point sources at Kårstø and Mongstad are shown, each ending at the location of the injection wells in the model studies. Depth is in m, and the axes show UTM31-coordinates. (For interpretation of the references to color in text, the reader is referred to the web version of the article.)
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
2. Compressibility and pressure increase Assuming that the formation targeted for CO2 injection is a closed entity with a given initial pore volume, the injection of CO2 will result in a compression of the existing formation fluids and an increase in pore volume due to rock compressibility. The resulting average increase in pressure is proportional to the in situ volume of the injected phase. This can be expressed as p =
Vinj Vpor ct
,
(1)
where Vinj is the in situ volume of injected phase, Vpor is the total pore volume and ct is the total compressibility. The total compressibility is given by the sum of the fluid compressibility, cw , and the rock compressibility, cr , and is expressed by ct = cw + cr . The compressibility of formation water is mainly a function of temperature, salinity and depth and does not vary very much between formations. The typical range of compressibility for the Johansen and Utsira formation water is between cw = 3 × 10−5 and cw = 4 × 10−5 bar−1 . The rock compressibility, however, varies with an order of magnitude between the unconsolidated sand in Utsira, cr = 3.5 × 10−4 bar−1 , and the consolidated sand in Johansen, cr = 4 × 10−5 bar−1 . For the Utsira formation the rock compressibility value used for the model studies in this paper is based on measured values from the formation (Springer et al., 2002). For the Johansen formation the compressibility has been estimated with the Hall correlation (e.g., Bradley, 1987). With these compressibility values, injection of CO2 corresponding to 1% of the pore volume will give an approximate average pressure increase of 25 bar for the Utsira formation and 150 bar for the Johansen formation. As the formation pressure increases, the probability of a mechanical failure of the cap rock also increases. Moss et al. (2003) have compared the reservoir pressures with the lithostatic pressure gradient in several of the formations in the North Viking Graben in the North Sea and found that in general the maximum observed formation pressure corresponds to approximately 80% of the lithostatic pressure. This can be interpreted as the pressure limit where microfractures open in the caprock, allowing fluids to leak through and suppressing further pressure build-up in the formation. The increase in pressure in Eq. (1) can be interpreted as the pressure increase at every point in the formation after pressure equilibrium has been reached. The local pressure increase will be much higher since the pressure increase needs some time to diffuse into the formation away from the injection well. Outside of the CO2 plume the fluid flow will be single phase, and the time scale of the pressure diffusion is given by T=
L2 , Dh
where Dh =
k ct
557
be to use long (horizontal) injection wells or to use several injection wells. However, since the region of elevated pressure increase for large scale injection operations will extend further than current limits on horizontal well lengths, this option will not be sufficient for pressure control, although it may be selected for other reasons (e.g., to minimise the risk of re-production of CO2 ). The EU directive on geological storage of CO2 (EU Directive, 2009) states that in case more than one storage site is located in the same hydraulic unit, the potential pressure interactions between the storage operations should not risk compromising the seal in any part of the unit. One promising storage design option for avoiding pressure increases that may compromise the formation seal or interfere with other interests such as other storage operations is to produce water out of the storage formation in sufficient amounts to control the pressure increase. This methodology has been investigated in several publications (e.g., Yang, 2008; Lindeberg et al., 2009) and is being considered for the Gorgon CO2 aquifer injection project (Flett et al., 2008). The present paper investigates this option for the two model cases. It is suggested to let the water production wells be passive producers, i.e., the wells produce only from the increase in formation pressure and not by active pumping. This will give increased production rates when the pressure in the formation increases and a decrease in production rate with increasing distance from injection wells. The production wells should be placed as close as possible to the injectors without risking production of CO2 . This can be achieved by placing the production well down-dip and perforate the well in the lower part of the formation (see Fig. 2). The produced water may represent an environmental challenge in itself, since most candidate aquifer formations for CO2 storage will contain water with salinity too high for release at the surface. The notable exception to this is storage sites under the sea bottom, where the salinity of the formation water may actually be lower than seawater. On-shore the saline formation water may be de-salinated and used for agriculture or for industrial purposes (Newmark et al., 2010). In this paper it is assumed that the water can be released in the ocean (after suitable treatment). 3. Simulation models The formation water viscosity, CO2 solubility and formation volume factor used in the simulations are based on Numbere et al. (1977), Diamond and Akinfiev (2003a,b) and Enick and Klara (1990). The injection gas is assumed to be pure CO2 with properties taken from correlations prepared by Span and Wagner (1996) and Vukalovich and Altunin (1969).
(2)
is the hydraulic diffusivity, which depends on the mobility of the fluid (k/), the porosity and the total compressibility. From welltest theory it is known that the fluid pressure gradient in the well region depends on the injection rate and the length of the contact between well and formation, in addition to the reservoir properties. Thus, two available options to reduce local pressure increase would
3.1. Johansen simulation model The most promising part of the Johansen formation for CO2 storage is the part west of the main north-south fault. The eastern part slopes upward toward the coast and has no proven seal along the eastern boundary. The western part slopes upward to the north-west, away from the main fault, but contains at least one
Fig. 2. Schematic view of placement of injection and production wells during CO2 injection. Note that the injection well may also be constructed as a horizontal well to increase the contact between well and formation.
558
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
between 0.15 and 0.29, with the porosity within a zone degrading towards south as the depth of the formation increases. Horizontal permeability in the sand varies between 300 and 1500 mD and is correlated to the porosity. The vertical to horizontal permeability ratio is set to 0.1, typical for consolidated sediments. An outline of the simulation model is shown in Fig. 3 (for further details on the simulation model see Bergmo and Lindeberg, 2007 and Bergmo et al., 2009a). 3.2. Utsira simulation model
Fig. 3. Outline of the Johansen simulation model in the north-western part of the formation. The colouring shows the depth of the top surface of the formation, in meters. The coordinates are given in UTM31-coordinates. The location of the injection wells are shown in Fig. 5. (For interpretation of the references to color in text, the reader is referred to the web version of the article.)
large fault and several smaller faults directed mainly in a northsouth direction. These faults extend up to the Troll hydrocarbon reservoir overlying parts of the Johansen formation. The present study assumes that the faults are sealing. Sensitivity studies on the fault transmissibility and possible consequences for the hydrocarbon production from Troll have been conducted in another project (Bergmo and Lindeberg, 2007). Mapping of the reservoir properties of the western parts of the Johansen formation through interpretation of well logs is most extensive to the north. Few wells penetrate the southern part, but it is assumed that the reservoir properties degrade toward the south as the formation deepens. The main part of the modelling reported in the present paper for the Johansen formation is performed on the north-western part shown in Fig. 3. The region selected for detailed studies is bounded to the west, north and east by faults that are assumed sealing. Communication with the rest of the formation is along the southern boundary of the simulation model. Pore volume multipliers are applied at this boundary to give the simulation model a total pore volume equal to the full formation. This boundary condition will effectively move the average distance to the large communicating volume closer, and will give a more slowly increasing pore pressure in the near-well region than if the volumes were placed at their true distance. A simulation on a more coarsely gridded model of the whole formation is included for comparison of the pressure development using a single injection well. The simulation model for the detailed study is gridded with an average lateral grid size of 200 m by 200 m, for a total model extension of 44 km (N-S) by 33 km (E-W). Since the same model was also used for detailed long-term migration studies (reported in Bergmo and Lindeberg, 2007 and Bergmo et al., 2009a) the gridding was relatively uniform throughout the model, and no near-well grid refinement was used. An interpretation of the geological layering was used to create 18 simulation grid layers, giving a total of some 230 thousand grid blocks. The height of the grid blocks varies from around 2–3 m in the layers close to the top (sand), to around 10 m in the sand layers below. Porosity in the sand layers varies
The part of Utsira considered for detailed modelling of CO2 deposition in the present study is located at the south-eastern edge of the Utsira formation. The outline of the model area is illustrated in Fig. 4. The extent of the simulation model is 53 km east-west in the southern part (68 km total), and 80 km total north-south. The simulation model has approximately 370 thousand grid blocks with an areal size of 400 m by 400 m, and 10 grid layers. The simulation grid was also used for long-term CO2 migration studies (reported in Bergmo and Lindeberg, 2007 and Bergmo et al., 2008, 2009b), and therefore lateral gridding was uniform rather than with grid refinement around the wells. The simulation model was given a uniform porosity of 0.35. The permeability was set to 1000 mD in the lateral directions and 100 mD in the vertical direction to mimic the reduced vertical transport properties caused by the intra-sand shales observed on well logs from the Utsira formation. Further details on the simulation model can be found in Bergmo and Lindeberg (2007) and Bergmo et al. (2008, 2009b). The current interpretation of the Utsira formation in the southern part is that it thins out to the east and south. The communication with the rest of the formation will be along the western and northern boundary of the detailed model. Pore volume multipliers were used along these boundaries to give the simulation model a total pore volume equal to the full Utsira formation. As for the Johansen formation, this will give a slightly slower increase in the pore pressure around the injection well(s) than if the pore volume were placed at the correct distance from the well. The simulations on the detailed model will therefore be too optimistic with respect to the amount of CO2 that can be injected while keeping the pressure increase below a given level. 3.3. Injection scenarios For each of the storage sites the placement of the wells was selected to minimise the transport length to the onshore CO2 supply points, while at the same time being positioned where the reservoir properties were favourable. For the southern Utsira study area it was also desired to select an injection point where the long-term migration would be relatively well contained. The scenarios for annual CO2 injection rates were dictated by scenarios for the establishment of CO2 transportation hubs onshore at Mongstad and Kårstø, respectively, for the Johansen and Utsira case studies. In these scenarios, CO2 will be collected from several sources and transported to the storage formations. The development of the transportation hubs would proceed in stages, Table 1 CO2 injection profile for injection into Johansen. Total injection period is 50 years and injection starts January 2012. Period, year
2012–2013 2014 2015–2061
CO2 injection rate tonne/day
Mtonne/year
13,426 18,797 29,192
4.90 6.87 10.66
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
559
Fig. 4. Outline of the simulation model located at the southern part of the Utsira formation. The colouring shows the interpreted thickness (in meters) of the formation in the southern part of the Utsira formation. Injection well locations are marked with filled circles, while open circles mark the position of the water production wells. (For interpretation of the references to color in text, the reader is referred to the web version of the article.)
and the annually stored amounts would therefore increase in steps. A summary of the injection scenarios is given in Tables 1 and 2. The total simulated injected amounts over a 50-year injection period are 0.518 Gtonne for the Johansen aquifer and 1.04 Gtonne for the Utsira aquifer. For each of the main cases, a number of well configurations were tested, to investigate the effect of CO2 injection operation design on the formation pore pressure increase. For the Johansen study, three main configurations were tested: 1. Two injection wells with no water production. 2. Two injection wells and one water production well at the southern boundary of the model (approximately 13 km from the nearest injection well). 3. Two injection wells and one water production midway between the southern boundary and the nearest injection well. In addition, two simulations were run to investigate the effect of the boundary conditions of the detailed model region on the pressure development in the formation. To achieve this, a model of the full formation was used, with larger grid block sizes and fewer grid layers. A cut-out of this model corresponding to the detailed Table 2 CO2 injection profile for injection into Utsira. Total injection period is 50 years and injection starts January 2012. Period, year
2012–2014 2015–2016 2017–2061
CO2 injection rate tonne/day
Mtonne/year
31,653 46,613 59,293
11.6 17.0 21.7
model area was also created. Since interpreted geometry and total pore volume of the formation in the full field model does not match exactly the data used to generate the detailed model, the results of these two additional simulations cannot be compared directly to the simulations on the detailed model. For the Utsira study, three well configurations were tested: 1. Single injection well with no water production. 2. Three injection wells to distribute the pressure increase over a larger area and reduce the maximum pressure increase. 3. Three injection wells and three water production wells. In addition a simulation was run on a model of the full Utsira formation with a single injection well to investigate the effect of the implementation of the boundary between the regional detailed model and the full formation. 4. Simulation results 4.1. Johansen formation During the injection period, the flow of gas is mainly dominated by the radial spread around the injection points, displacing formation water and only to a small extent dissolving in the contacted water. Fig. 5 shows the distribution of the injected CO2 after 50 years for the case with two injection wells and a water production well at the boundary of the maximum CO2 extent. The location of the production well in the case where it is located at the southern boundary of the model is also shown. The formation pressure increases significantly in the near-well region in the case with no water production, reaching 85 bar pressure increase at the top of the formation near the injection wells
560
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
Fig. 7. Comparison of pressure increase (in bars) after 50 years of injection between full field model and a sector model with pore volume multipliers along the southern boundary. Pressure increase in the near-well region and a control volume surrounding the injection well is significantly larger when the full field is modelled, due to lower connectivity to the distant pore volumes.
Fig. 5. Simulation model of the Johansen formation showing distribution of the injected CO2 after 50 years and location of injection wells (two northern wells) and the water production wells. The red colour shows grid blocks where CO2 exists as a separate phase. Grid blocks with no CO2 are coloured blue and intermediate colours show grid blocks where CO2 exists dissolved in water but not as a separate phase. At most one production well is active in each scenario. (For interpretation of the references to color in text, the reader is referred to the web version of the article.)
after 50 years of injection. Fig. 6 shows the pressure increase for the three investigated well configurations for the Johansen injection case, given as the pressure increase near the top of the formation close to the injection well and the average pressure increase for the whole formation volume. The safe pore pressure, estimated as 0.8 times the lithostatic pressure, gives a limit on the safe pressure increase below the cap rock at the injection site of 116 bar. Even the worst-case well configuration tested, with no pressure control, gives a pressure increase below this limit. However, given that the implementation of boundary conditions may give optimistic estimates of pressure increase, reference simulations were run with a model of the full formation. The available full-field model has a lower estimate for the total pore volume of the formation, and also uses a different interpretation of the formation topography in the region for the detailed model. Therefore, the simulations on the full-field model cannot be compared directly to the detailed model simulations, but is compared to a sector model corresponding to the extent of the detailed model, and with similar boundary conditions. The results are illustrated in Fig. 7. It is seen that for this sector model, representing
the communication to the rest of the formation by pore volume mulitipliers will significantly overestimate the effective communication. The pressure increase is therefore underestimated in the sector model. From this we conclude that the detailed model also underestimates the pressure increase in the near-well region. The difference in the pressure increase at the top of the formation is close to 30 bar between the two simulations on the reference models. If this is scaled with the difference between the pressure increase in the sector models (detailed simulation model vs. sector of full-field model) the results indicates a maximum pressure increase of 110 bar in the near-well region when no water is produced from the formation. Thus, it is very likely that some kind of pressure control will be needed if the given injection schedule shall be implemented. As seen in Fig. 6, the pressure increase in the region near the injection wells is lower when formation water is allowed to escape through water production wells. But pressure increase is still large if the production well is placed close to the southern boundary of the model area. Note that the above comparison of simulations with the reference full field model shows that the efficiency of the southern water production well is probably underestimated with the boundary conditions used. If the water production well is moved closer to the injection wells, to the point where the CO2 plume just reaches the production well after 50 years of injection, the pressure increase is much lower. Fig. 8 shows the pressure increase for the case with a water production well halfway to the southern boundary of the detailed simulation model. It is noted that it will be a challenge to locate wells to maximise pressure control and at the same time avoid reproduction of injected CO2 . Even if the Johansen formation is dipping, the slope is not large enough to keep CO2 from spreading down-dip towards the water production well. The effectiveness of water production as a pressure control option depends on how much water is produced for a given injected amount of CO2 . The distance between the injection wells is a major influencing factor. Moving the production well further away from the injection wells reduce the difference between the well pressure and the hydrostatic pressure, and thus reduce the possible water production rate for a passively producing well. The produced water volume for the two well configurations with water production wells is compared to the injected CO2 volume in Fig. 9. 4.2. Utsira formation
Fig. 6. Local pressure increase below the cap rock of Johansen close to the injection wells and average pressure increase in the formation both as a function of years after start of injection.
For the Utsira formation, estimated safe pressure increase in the near-well region is 45 bar. The simulation results show that
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
561
Fig. 8. Pressure increase (in bars) after 50 years in the detailed simulation model for the well configuration with the lowest maximum pressure increase; two injection well and a water production well halfway to the southern boundary of the model.
the configuration with a single injection well is close to this critical limit, although the assumption of completely sealed formation boundaries means that this estimate will be probably be too high. Distributing the injected volume over three injection wells is seen to reduce the maximum pressure increase, but the average pressure increase in the near-well region is not much reduced. Fig. 10 shows the local pressure increase and the field-average pressure increase in the Utsira formation in the investigated scenarios. The weak topography of the Utsira aquifer (as small as a few meters per kilometer in the near-well region) makes placement of water production wells in this formation particularly challenging.
Fig. 9. Comparison of the reservoir volumes of injected CO2 and produced water in the Johansen storage scenario.
The injected gas will spread nearly radially out from an injection well. If a single injection/production well pair is used, the production well must be placed more than 13 km away from the injection well to avoid re-production of CO2 . This distance makes the pressure control for passive production wells too ineffective. With more than one injection well the size of the plume around each well will be smaller, and the production wells can be moved closer to the injection wells and therefore be more effective in controlling pressure increase. Lindeberg et al. (2009) have shown how it is possible in a large-scale deployment of CO2 injection and water produc-
Fig. 10. Local pressure increase below the cap rock of Utsira close to the injection wells and average pressure increase in the formation (dashed lines) both as a function of years since start of injection. (The pressure fluctuations in the first year are caused by the well control algorithm in the reservoir simulator.)
562
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
Fig. 11. Simulated pressure increase (in bars) in the southern part of Utsira after 50 years of injection through a single well. In the left plot the full Utsira formation is modelled, while in the right plot only the detailed model area is included, and the communication with the rest of the formation is modelled by increasing the pore volume at the boundary to the west and north.
tion to limit reproduction of injected CO2 to a small fraction of the injected volume by just sealing off any production wells violating CO2 concentration thresholds. A reference simulation with a single injection well on a model of the full formation have been performed to check the effect of implementing pore volume multipliers along the boundary of the detailed simulation model to represent the volume of the full formation. As seen in Figs. 11–13 the simulated pressure increase match fairly well in the near-well region. The match is better than in the Johansen case, probably because the wells are further away from the boundary where the pore volume multipliers are used. With some tuning it is probably feasible to use this method with even better accuracy. Fig. 14 shows the pressure increase map for the case with three injection wells and three water production wells. Comparing this with the right plot of Fig. 11 we see that the region of highest pressure increase is much more confined, in particular towards the north. In the Utsira injection scenario relatively less water is being produced as illustrated in Fig. 15. This has the expense that the large
Fig. 13. Comparison of pressure increase (in bars) after 50 years of injection between full field model and a sector model with pore volume multipliers along the western and northern boundary.
Utsira formation is pressurised 4–5 bar at end of injection even with water production. 5. Discussion and conclusions
Fig. 12. Difference between simulated pressure increase (in bars) for the two simulations in Fig. 11, inside the region of the detailed model.
In both simulation cases local pressure increase under the seal is close to the estimated safe limit if no water production is employed. Increasing the number of injection wells will reduce the maximum pressure increase. Controlling formation pressure by allowing water to be produced from passive water production wells will further reduce the pressure build-up in particular in the near-well region but also in the formation as a whole. Passive water production is considered in this study. While this production method may save costs in the production and operation of the wells, this requires that the aquifer pressure exceeds the hydrostatic pressure near the production well. A residual pressure increase will therefore propagate past the production wells and into the far parts of the aquifer. The cost of this full-aquifer pressurisation in terms of detrimental effects for future storage operations or other underground resources should be balanced against the increased cost of more active water extraction such as pumping. It is seen that even with passive water production the produced water volume is a significant fraction of the reservoir volume of
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
563
Fig. 14. Pressure increase contours for the Utsira case with three injection wells and three water production wells after 50 years of injection.
the injected CO2 . For a large injection operation the produced volumes will be on the order of 1 km3 water produced per Gtonne CO2 injected. Both the Utsira and Johansen formations are located far from the shore in the North Sea and it is assumed that an emission permit for the formation water with 3–5% salinity can be obtained. To utilise more than 1–2% of the available pore space massive water production from the formation will be necessary to constrain pressure build-up to within safe limits and to avoid interference with other potential storage projects in the same hydraulic unit. Results from the reference simulations on the full field models indicate that if no water is produced pressure increase in the far parts of the formations is still significant. After 50 years the eastern parts of the Johansen formation have a pressure increase of 20–25 bar, and the pressure increase 80 km north of the injection wells in Utsira is 2 bar.
Fig. 15. Comparison of the reservoir volumes of injected CO2 and produced water in the Utsira storage scenario with three injection wells and three water production wells.
Acknowledgements This publication has been produced with support from the BIGCCS Centre, performed under the Norwegian research program Centres for Environment-friendly Energy Research (FME). The authors acknowledge the following partners for their contributions: Aker Solutions, ConocoPhilips, Det Norske Veritas AS, Gassco AS, Hydro Aluminium AS, Shell Technology AS, Statkraft Development AS, Statoil Petroleum AS, TOTAL E&P Norge AS, and the Research Council of Norway (193816/S60). References Arts, R.J., Chadwick, A., Eiken, O., van Thibeau, S., Nooner, S., 2008. Ten years’ experience of monitoring CO2 injection in the Utsira Sand at Sleipner, offshore Norway. First Break 26, 65–72. Bergmo, P.E., Grimstad A.-A., Lindeberg, E., 2008. Storage of CO2 in the southern part of the Utsira formation (16/11). SINTEF Petroleum Research Report 54.5949.00/01/08, Confidential. Available through Norwegian Petroleum Directorate. Bergmo, P.E., Grimstad, A.-A., Lindeberg, E., 2009a. Exploring geological storage sites for CO2 from Norwegian gas power plants: Johansen formation. In: Proceedings GHGT-9, Washington 2009, pp. 2945–2952. Bergmo, P.E., Grimstad, A.-A., Lindeberg, E., 2009b. Exploring geological storage sites for CO2 from Norwegian gas power plants: Utsira South. In: Proceedings GHGT-9, Washington 2009, pp. 2953–2959. Bergmo, P.E., Lindeberg, E., 2007. Near coastal sites for storing CO2 from Mongstad and Kårstø. SINTEF Petroleum Research Report 52.5928.00/01/07, Confidential. Available through the Norwegian Petroleum Directorate. Birkholzer, J.T., Zhou, Q., Tsang, C.F., 2009. Large-scale impact of CO2 storage in deep saline aquifers: a sensitivity study on the pressure response in stratified systems. Int. J. Greenhouse Gas Control 3 (2), 181–194. Birkholzer, J.T., Zhou, Q., 2009. Basin-Scale Hydrogeologic Impacts of CO2 Storage: Capacity and Regulatory Implications. Int. J. Greenhouse Gas Control 3 (6), 745–756. Bradley, H.B., 1987. Petroleum Engineering Handbook, pp. 26–28. Chadwick, A., Arts, R., Eiken, O., Williamson, P., Williams, G., 2006. Geophysical monitoring of the CO2 plume at Sleipner, North Sea: an outline review. In: Lombardi, S., Altunina, L.K., Beaubien, S.E. (Eds.), Advances in the Geological Storage of Carbon Dioxide: International Approaches to Reduce Anthropogenic Green-
564
P.E.S. Bergmo et al. / International Journal of Greenhouse Gas Control 5 (2011) 555–564
house Gas Emissions. Springer, Dordrecht, The Netherlands, pp. 303–314 (NATO Science Series IV: Earth and Environmental Sciences, 2006). Diamond, L.W., Akinfiev, N.N., 2003a. Solubility of CO2 in water from −1.5 to 100 ◦ C and from 0.1 to 100 MPa: evaluation of literature data and thermodynamic modelling. Fluid Phase Equilib. 208 (2003), 265–290. Diamond, L.W., Akinfiev, N.N., 2003b. Solubility of CO2 in water from 0 to 100 ◦ C and from 0.1 to 100 MPa: evaluation of literature data and thermodynamic modelling. Fluid Phase Equilib. 208, 265–290. Enick, R.M., Klara, S.M., 1990. CO2 solubility in water and brine under reservoir conditions. Chem. Eng. Commun. 90, 23–33. Flett, M., Beacher, G., Brantjes, J., Burt, A., Dauth, C., Koelmeyer, F., Lawrence, R., Leigh, S., McKenna, J., Gurton, R., Robinson, W.F., Tankersley, T., 2008. Gorgon project: subsurface evaluation of carbon dioxide disposal under Barrow Island. In: Paper SPE 116372 Presented at the 2008 SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia. EU Directive, 2009. Directive 2009/31/Ec Of The European Parliament And Of The Council of 23 April 2009 Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC, 2008/1/EC and Regulation (EC) No. 1013/2006. L140, Official Journal of the European Union on the geological storage of carbon dioxide and amending Council Directive 85/337/EEC, European Parliament and Council, pp 114–135. Holloway, S., Bateman, K., Barbier, J., Doherty, P., Fabriol, H., Harrison, R., Heederik, J.P., van der Meer, L.G.H., Czernichowski-Lauriol, I., Lindeberg, E.G.B., Pearce, J.M., Summerfield, I.R., Rochelle, C., Sanjuan, B., Schartzkopf, T., Kaarstad, O., Berger, B., 1996. The underground disposal of carbon dioxide. Final Report of JOULE II Project No. CT92-0031. Non Nuclear Energy R&D Programme. IPCC, 2005. IPCC special report on carbon dioxide capture and storage. In: Metz, B., Davidson, O., de Coninck, H.C., Loos, M., Meyer, L.A. (Eds.), Prepared by Working Group III of the Intergovernmental Panel on Climate Change. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442pp. Lindeberg, E., Vuillaume, J.F., Ghaderi, G., 2009. Determination of the CO2 storage capacity of the Utsira formation. Energy Procedia 1, 2777–2784. http://www.sciencedirect.com/science/journal/18766102.
Moss, B., Barson, D., Rakhit K., Dennis, H., 2003. Formation pore pressures and formation waters. In: Evans, D., Graham, C., Armour, A., Bathurst, P. (Eds. and Coordinators). Millennium Atlas: Petroleum Geology of the Central and Northern North Sea, pp. 317–329 (Chapter 18). Newmark, R.L., Friedmann, S.J., Carroll, S.A., 2010. Water challenges for geologic carbon capture and sequestration. Environ. Manage. 45 (4), 651–661. Nicot, J.P., 2008. Evaluation of large-scale carbon storage on fresh-water section of aquifers: a Texas study. Int. J. Greenhouse Gas Control 2 (4), 582–593. Numbere, D., Brigham, W.E., Standing, M.B., 1977. Correlations for Physical Properties of Petroleum Reservoir Brines. Petroleum Research Institute, Stanford University, p. 8. Odenberger, M., Kjärstad, J., Johnsson, F., 2008. Ramp-up of CO2 capture and storage within Europe. Int. J. Greenhouse Gas Control 2 (2008), 417–438. Span, R., Wagner, W., 1996. A new equation of state for carbon dioxide covering the fluid region from the triple-point temperature to 1100 K at pressures up to 800 MPa. J. Phys. Chem. Ref. Data 25 (6), 1509–1596. Springer, N., Høier, C., Lindgren, H., 2002. Mineralogical and petrophysical properties of Utsira sand before and after reaction with CO2 saturated formation water. SACS Project, Phase II, GEUS Rapport 2002/42. Vangkilde-Pedersen, T., Lyng Anthonsen, K., Smith, N., Kirk, K., Neele, P., van der Meer, B., Le Gallo, Y., Bossie-Codreanud, D., Wojcickie, A., Le Nindre, Y.-M., Hendriks, C., Dalhoff, F., Christensenh, N.P., 2009. Assessing European capacity for geological storage of carbon dioxide – the EU GeoCapacity project. Energy Procedia, vol. 1(1), February 2009, pp. 2663–2670. Greenhouse Gas Control Technologies 9, Proceedings of the 9th International Conference on Greenhouse Gas Control Technologies (GHGT-9), 16–20 November 2008, Washington DC, USA. Vukalovich, M.P., Altunin, V.V., 1969. Thermophysical Properties of Carbon Dioxide. Collet’s Publishers Ltd., London & Wellingborough, p. 419. Yang, Q., 2008. Dynamic modelling of CO2 injection in a closed saline aquifer in the Browse Basin, Western Australia. In: Paper SPE 115236 Presented at the 2008 SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia.