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Geological assessment for CO2 storage in the Bahaiwan Basin, East China

The storage potential of selected sites within the Bahaiwan Basin was evaluated, the storage capacity estimated and the selection criteria considered for the COACH project. This paper examines the two methods used during the project for calculation of the storage capacity in the Shengli oilfield complex within the Bahaiwan Basin. Both methodologies were used to quantify the potential CO2 storage capacity of the depleted oil hydrocarbon reservoirs of the Shengli oilfield complex. They can both be considered as "simple" equation models which try to capture an "approximation" of a possible storage capacity. Nevertheless, between these models several differences exist. The CSLF methodology works with replacement of oil, gas or formation water, but does not incorporate dissolution of CO2 in formation water. The EOR methodology of CUPB developed from methodology of Tanaka et al. on the other hand includes dissolution of CO2 into the formation water, but does not consider the time period needed for the dissolution. © 2010 Elsevier Ltd. All rights reserved


Introduction
The challenge of climate change demands reduction in global carbon dioxide (CO 2 ) mission. Carbon capture and storage (CCS) technology can be used to trap and store carbon dioxide gas emitted by coal-burning plants and this can potentially reduce the world's total CO 2 emission by about one quarter by 2050 [1,2,3]. Experience from the storage sites of Sleipner in the Norwegian North Sea, In Salah in Algeria, Nagaoka in Japan, Frio in USA and other sites shows that geological structures can safely accommodate C O 2 produced and captured from large CO 2 point sources. CCS is one of the solutions to reduce carbon emissions and serves as a bridging technology towards a carbon free energy market.
China has large coal reserves [4], and is not about to give up on this reliable source of fossil fuel. Hence a large production of CO 2 can be expected to continue for many years. China has also favourable geology which could facilitate permanent storage in onshore areas within deep saline formations [5,6]. In an extensive collaborative research effort between Chinese and European scientists, the COACH project (Cooperation Action within CCS China-EU) was successful in building the expertise, evaluating the capture technologies and mapping transportation routes for CO 2

Methodology
A regional level assessment of selected potential storage sites for CO 2 in the Bahaiwan Basin (Bohai Basin) was carried out for the COACH project. The storage capacity was estimated in each case using a simplified version of the Carbon Sequestration Leadership Forum (CSLF) methodology [8,9,10]. The storage reservoir properties, sealing formation properties, reservoir injectivity and other relevant parameters were also considered. For all sites considered, publicly available data were used. PetroChina also provided data for the Dagang oilfield province and the China University of Mining and Technology carried out experiments on coal samples to improve the accuracy of the storage assessment in unmineable coal seams in the Kailuan mining area.
The aim of CO 2 storage is the permanent removal of C O 2 from the atmosphere. The European Union has supported current research on CO 2 capture and storage methods for more than a decade, with emphasis on capture techniques, transport and geological storage. The results of the research on geological storage are summarised in a comprehensive manual by Chadwick et al. [11]. Internationally recognised standards for capacity assessments were established by the Carbon Sequestration Leadership Forum (CSLF) in 2004-2005 [8] and a task force on capacity estimation standards has been active since presenting comprehensive definitions, concepts and methods [9,10]. These capacity standards were reviewed for the COACH project by Poulsen et al. [12] and were used for the work on permanent CO 2 storage estimates in China [6,13,14,15].
Potential C O 2 storage sites in the Bahaiwan Basin (East China) ( Fig. 1) were investigated [6,12,15]. Some potential oilfields, saline aquifers and unmineable coal beds have been assessed. The CSLF -based methodology [8,9,10] was applied to evaluate storage potential. Within the investigated area, COACH localised and described a pilot scheme that could prove the concept of Carbon Capture and Storage (CCS) and CO 2 -Enhanced Oil Recovery (CO 2 -EOR) in this region of China [6,15], which fulfil the basic storage site selection criteria: 1. Sufficient depth of reservoir to ensure that CO 2 reaches its highly dense phase but not so deep that permeability and porosity is too low. 2. Integrity of seal to hinder CO 2 escape. 3. Sufficient CO 2 storage capacity. 4. Effective petrophysical reservoir properties to ensure CO 2 injectivity such that the site is economically viable and that sufficient CO 2 can be stored.

Comparison of methods
Various methods are available for calculation of C O 2 storage capacity in a geological environment [16,17,18,19]. The methods used in the COACH project [12] were based on Bachu et al. [9,10] and used in the COACH database to estimate the storage capacity of hydrocarbon fi elds. Estimates made by the China University of Petroleum Beijing (CUPB) applied an adapted version of the Tanaka et al [18] method for computing the storage capacity in the Shengli oilfield complex [13].
The two methods proposed by the CSLF task force [8] and the EOR methodology of CUPB developed from methodology of Tanaka et al. [13] are basically identical in their approach. Both methods are based on a volumetric approach and are applicable to site, regional and basin-scale C O 2 storage capacity estimates. Both can be considered as 'simple' equation models, which try to calculate an 'approximation' of a possible storage capacity. The methods gave almost equivalent results (Table 1) when applied to the Shengli oilfield complex [13,15].
The long term behaviour of CO 2 in a storage site depends on a number of parameters: reservoir, caprock, fluids and time [11]. The solubility of CO 2 in formation water varies with the salinity of the formation water, the temperature and pressure of the formation. The dissolution of CO 2 in pure water increases with increasing pressure (and thus increasing depth) up to approximately 7 Mpa. On the other hand the CO 2 solubility in formation water decreases with increasing temperature and salinity and thus (normally) decreases with depth [20]. The result is that in general, the solubility of CO 2 in formation water decreases with increasing salinity of the formation water [19]. Nevertheless, at geological storage depth of 800 m or below, a significant amount of CO 2 will dissolve and be trapped in the formation water. However, the geological time period for these processes needs to be taken into account.
There are, however, some differences in the approach to CO 2 behaviour in the storage site. The CSLF method [8] works with replacement of oil, gas or formation water but does not directly incorporate dissolution of CO 2 into the formation water. The method of Tanaka et al. [18], on the other hand, operates with a free phase of C O 2 and takes into account dissolution of CO 2 in the formation water, but it does not consider the time period needed for C O 2 dissolution [12].

CSLF Methodology
The work with establishing internationally recognised standards for capacity assessments was initiated by the Carbon Sequestration Leadership Forum (CSLF) in 2004-2005 and a CSLF Task Force has been active since. The paper "Estimation of CO 2 Storage Capacity in Geological Media -Phase 2" [8,9,10,21] published by the CSLF presents comprehensive definitions, concepts and methodologies to be used in estimating CO 2 storage capacity.
The methodology used for hydrocarbon fi elds yields theoretical storage capacity according to the methodology described by CSLF [8]. A number of scientifically based assessments are necessary in order to address the geological storage capacity resulting from the various trapping methods. The formation volume factor used for oil varies regionally and locally depending on the oil type. The formation volume factor used for gas should vary with depth as a function of pressure and temperature. Similarly the CO 2 density also varies with depth as a function of pressure and temperature. To reach effective storage capacity CSLF introduce a number of capacity coefficients representing mobility, buoyancy, heterogeneity, water saturation and aquifer strength, respectively and all reducing the storage capacity. There are however only few studies for estimating the values of these capacity coefficients including Vangkilde-Pedersen et al. [22], which was used to estimate this coefficient for the COACH project.

EOR methodology of CUPB and methodology of Tanaka et al. [18]
The storage capacity in the dissolution model of Tanaka et al. [18] is given as the displaceable volume plus dissolved volume of CO 2 in water in situ. During injection, part of the formation water is displaced by CO 2 , and part o f the C O 2 is dissolved in the remainder o f the formation water (Fig. 2). Like other two-phase systems, the saturation of injected CO 2 in the formation depends on how the injected CO 2 passes through the formation, as gravity and viscous fingering phenomena will affect the sweep efficiency of CO 2 strongly [19]. The Tanaka et al. [18] methodology is further developed [13] for calculating CO 2 storage in combination with EOR.
The sweep efficiency of CO 2 depends on formation thickness, vertical permeability distribution and mobility ratio of the injected CO 2 and formation water [18,23]. The mobility of a fluid in a porous medium is defined as the ratio of the effective permeability to the viscosity of the fluid [18,23]. The solubility of CO 2 in formation water varies due to the salinity of the formation water and the temperature and pressure of the formation [18,23]. As a general rule of thumb, the solubility of CO 2 in formation water decreases with increasing salinity of the formation water [19]. The volumes of CO 2 that can be stored underground have been studied by various institutes in Japan based on the cumulative production of oil and gas. Oil and gas occupy only the top portion of the reservoir in an anticlinal structure and the remaining lower part is filled with water. The volume of the water portion may be tens of times greater than the oil and gas portion and can be used for CO 2 storage.
For aquifer reservoirs in anticlinal structures and oil and gas reservoirs and neighbouring aquifers in anticlinal structures that are well sealed by cap rocks, the technology of CO 2 flood and underground natural gas storage can be applied to estimate the volumes of CO 2 that can be stored. As described above, the model suggested by Tanaka et al. [18] uses the following equation for underground CO 2 storage in oil and gas reservoirs and neighbouring aquifers, and in aquifers in anticlinal structures: CO 2 storage capacity = (displaceable volume) + (dissolved volume of CO 2 in water in situ). (1) The assum ption for this equation is that the CO 2 injected is in its highly dense phase. The saturation of injected CO 2 in the formation depends on the permeability of the formation and the property of the formation water (see above). The injected CO 2 often passes through only a limited part of the formation as given by the sweep efficiency. In the Tanaka methodology the CO 2 saturation and sweep efficiency are estimated from the performance of a pilot test of CO 2 flood and underground natural gas storage respectively and they assume the following values: ! Sweep efficiency: 50% ! CO 2 saturation: 20% ! Water saturation: 80% (The water dissolves CO 2 under the reservoir conditions.) Other data necessary for the calculation are the structural area, effective thickness, porosity, etc., which are typically obtained from structural contour maps and wells.

Comparison of calculation
The hydrocarbon field storage capacity following the CSLF methodology is given as the displaceable volume of oil and gas multiplied with storage capacity factors: CO 2 storage capacity = (CO 2 density) × (recovery factor) × (volume) × (efficiency factor) # CO 2 storage capacity = (CO 2 density) × (displaceable volume) × (1) # (4) CO 2 storage capacity = (CO 2 density) × (displaceable volume) (5) where: ! MCO 2 : hydrocarbon field storage capacity ! ∀CO 2 r: CO 2 density at reservoir conditions (best estimate) ! URp: proven ultimate recoverable oil or gas ! B: oil or gas formation volume factor ! Seff Storage efficiency factor (here it is fixed as 1 (100 %)) The storage capacity in the dissolution model of Tanaka et al. [18] is given as the displaceable volume plus dissolved volume of CO 2 in water in situ: CO 2 storage capacity = (displaceable volume) + (dissolved volume of CO 2 in water in situ) (7) Here both the displaceable volume and the dissolved volume are depending on the sweep efficiency factor (i.e. the percentage of the total oil reservoir or pore volume which is within the area being swept of oil by a displacing fl uid, as in a natural or artificial gas drive or water injection fi eld), which again depends on formation thickness, vertical permeability distribution and mobility ratio of the injected CO 2 and formation water.  [13] for calculating CO 2 storage in combination with EOR. The equation of EOR methodology of CUPB is [13]: (8) where: ! M (CO2) = total storage capacity of CO 2 (m 3 ) ! M 1 = storage capacity of CO 2 dissolved in oil and water in oil bearing reservoir ! M 2 = storage capacity of CO 2 dissolved in water-bearing formation in contact with the oilfield ! M 3 = storage capacity of C O 2 in the displaceable volume of oil bearing reservoir during CO 2 flooding ! M 4 = storage capacity of CO 2 from reaction with reservoir rock M (CO2) = E f ×A or ×h or ×ö or ×[S o ×R o(CO2) ＋(1-S o )×R w(CO2) ]＋h wf ×A wf ×ö wf ×S w ＋V co2o +V co2w +M 4 (9) where: ! E f = overall sweep efficiency (fraction), E f = 5-25% ! A or = area of oil bearing reservoir (m 2 ) ! h or = thickness of oil bearing reservoir (m) ! ö or = porosity of oil bearing reservoir(fraction) ! S o = oil saturation in oil bearing reservoir (fraction) ! R o (CO2) = CO 2 solubility in oil (fraction) ! R w(CO2) = CO 2 solubility in water(fraction) ! A wf = area of water formation (m 2 ) ! h wf = thickness of water formation (m) ! ö wf = porosity of water formation (fraction) ! S w = CO 2 solubility in formation water (fraction) ! V co2o = volume of C O 2 for displacing the oil produced during CO 2 flooding ! V co2w = volume of CO 2 for displacing the water produced during CO 2 flooding The calculation of EOR methodology of CUPB expects a relative high dissolution of CO 2 into formation water and oil [13]. The average dissolved CO 2 in oil and water in oil bearing reservoir (M 1 ) is 16%, the average CO 2 dissolved in water-bearing formation (M 2 ) is 75%, and the average CO 2 stored by displace oil and water in oil bearing reservoir during CO 2 flooding (M 3 ) is 9%. The last storage factor (M 4 ) is not considered, as these data is not available for the reservoirs in the Shengli Oilfield and is regarded as a long-term storage factor [13].

The dissolution of CO2 in aquifers
The aim of geological CO 2 storage is the permanent removal of the injected CO 2 from the atmosphere. The buoyancy of the injected supercritical CO 2 leads to an upward gravity driven fl ow of CO 2 towards the top of the reservoir to form a plume below the caprock. The brine density increases with increasing CO 2 dissolution. Due to the low solubility of CO 2 in the brine, a large volume of brine is necessary to dissolve a given amount of CO 2 . (CO 2 -liquid or supercritical -and water are immiscible, but CO 2 can dissolve in water). A downward gravity driven flow induced by the increased density of CO 2 saturated brine is necessary to contact this large volume of brine and therefore determines the long-term dissolution rate [24]. Two mechanisms mainly contribute to dissolution at the gas-water contact: in the beginning of CO 2 storage diffusion dominates, while later convective mixing dominates.
In the beginning, before the plumes of saturated brine have reached the bottom, the overall dissolution rate is essentially constant due to rapid convective overturn. At late times the saturated brine forms a gravity current propagating outward from the CO 2 source. Simple models of constant density gravity currents predict a power-law decay of the overall dissolution rate. Direct numerical simulations show similar decay but at slightly lower rates [24].
Comparing diffusion model simulations of the mixing of carbon dioxide (CO 2 ) and methane (CH 4 ) in reservoirs Oldenburg et al. [25] found, that for CO 2 storage in depleted natural gas reservoirs, the injected CO 2 will migrate to levels under the CH 4 layer of the reservoir by buoyancy flow). Once a gravitationally stable configuration is attained, CO 2 and CH 4 mixing will continue on a longer time scale by molecular diffusion.
A study by Leonenko et al., [26] shows much faster dissolutions rates. They studied the engineering techniques for CO 2 geological storage, and found that the site selection and placement of the injection wells were not the only variables for storage capacity. They found, that with brine injection at 1 Mt/year, about 63% of the CO 2 will be dissolved in 200 years forming a plume of saturated brine that moves outwards from the stored CO 2 plume top. In the absence of brine injection there is negligible CO 2 dissolution after initial injection during the same time period. They found that it is possible to accelerate the dissolution of CO 2 in brines by pumping brines from regions where it is under-saturated into regions occupied by CO 2 during storage. For horizontally confined reservoir geometry, they found that it is possible to dissolve essentially all injected CO 2 within 300 years. Similar analysis by Tchelepi [27] indicates that dissolution trapping can be enhanced significantly by convective mixing in aquifers depending on thickness and perm eability.
The rate at which CO 2 dissolves into the brine is a key constraint both in different methodologies and in the different sites where CO 2 is geologically stored. The Tanaka et al. [18] methodology is based on storage of free CO 2 of which a large proportion is dissolved CO 2 in the formation water. The methodology does not take into account the time period needed for the dissolution of CO 2 in the formation water, nor the pressure or temperature at the injection point. A comparison to Sleipner and other sites in operation shows that interaction between the mechanisms are complex and evolves in time, and depend on local conditions such as porosity, permeability, temperature and pressure [28].

Conclusions
The two methodologies for calculation of CO 2 storage capacity the CSLF [8] and the EOR methodology of CUPB [13] developed from the Tanaka et al. [18] both aim to quantify the potential CO 2 storage capacity of depleted oil hydrocarbon reservoirs. Therefore, both can be considered as "simple" equation models which try to capture an "approximation" of a possible storage capacity. Nevertheless, several differences exist between these models. The EOR methodology of CUPB is operating with both a free phase CO 2 plume and CO 2 dissolved in the brine, while the CSLF method does not consider dissolution of CO 2 .
Understanding the dissolution process coupled to time, porosity and permeability, is important for predicting CO 2 storage capacity. Local and site-specific storage capacity estimates should be based on numerical modelling that takes into account the dynamic aspect of CO 2 injection and the CO 2 plume evolution.