CO2 storage potential and trapping mechanisms in the H-59 block of Jilin oilfield China

International Journal of Greenhouse Gas Control 49 (2016) 267–280

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CO2 storage potential and trapping mechanisms in the H-59 block of Jilin oilfield China Liang Zhang a,∗ , Xin Li a , Bo Ren b , Guodong Cui a , Yin Zhang c , Shaoran Ren a , Guoli Chen d , Hua Zhang d a

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, TX 78712, USA c College of Engineering and Mines, University of Alaska Fairbanks, Fairbanks 755880, USA d Jilin Oilfield Company, PetroChina, Songyuan 138000, China b

a r t i c l e

i n f o

Article history: Received 21 October 2015 Received in revised form 8 March 2016 Accepted 10 March 2016 Available online 22 March 2016 Keywords: CCS project CO2 storage capacity Reservoir simulation CO2 trapping form CO2 distribution

a b s t r a c t A CO2 EOR and storage pilot test have been conducted in the H-59 block of Jilin oilfield China for well seven years. It is important to track the CO2 storage and distribution in the reservoir, which can provide valuable guidance for the operation in the next stage of the project. In this paper, the CO2 storage capacity in the H-59 block was calculated by considering various CO2 trapping mechanisms, and the distribution and trapping status of the stored CO2 were evaluated by using the reservoir simulation method. The effective CO2 storage capacity in the H-59 block is estimated to be 26.37 × 104 ton by incorporating the CO2 sweep efficiency and neglecting the mineral trapping. Up to June 2014, 21.08 × 104 ton of CO2 has been injected with over 95% stored. The geological structure of the H-59 block controls most of the injected CO2 moving only along the horizontal direction in the thin oil layers. The shape and size of the CO2 plume are mainly determined by the reservoir heterogeneity, well pattern and injected CO2 amount. According to the assessment results, the CO2 sweep efficiency within each well group varies from 20% to 80%. About 42.68–60.15% of the stored CO2 has been trapped at supercritical state accompanied with 24.85–41.8% and 15% of the stored CO2 dissolved in residual oil and water, respectively. The H-59 block still has a potentially remaining capacity of 6.25 × 104 ton of CO2 for the future storage. Necessary engineering measures might be taken to further increase the sweep and displacement efficiencies of CO2 to achieve this purpose. © 2016 Elsevier Ltd. All rights reserved.

1. Introduction Large amounts of CO2 discharged into the atmosphere has led to serious global warming. Effective measures should be taken to reduce the carbon emissions. CO2 Capture and Storage (CCS) technology has been regarded as a feasible option to store CO2 underground for permanent sequestration at a large scale, where CO2 is first captured from industrial gas sources, and then transported to suitable geological sites for storage. The injected CO2 can be trapped in reservoirs through various mechanisms to achieve a long-term safe storage (I.P.C.C., 2005)(Intergovernmental Panel on Climate Change), 2005). Since the 1990s, many CO2 storage demonstration projects have been conducted, such as Sleipner, Weyburn, In Salah, K-12B, Snohvit projects (Ren et al., 2010; Arts et al., 2004; Maldal and Tappel, 2004; Preston et al., 2005; Van der

∗ Corresponding author. E-mail addresses: [email protected], [email protected] (L. Zhang). http://dx.doi.org/10.1016/j.ijggc.2016.03.013 1750-5836/© 2016 Elsevier Ltd. All rights reserved.

Meer et al., 2005; Rutqvist et al., 2010). Hydrocarbon reservoirs and deep saline aquifers are the favorable sites for CO2 storage. Particularly, the oil and gas reservoirs are the preferable selections because of their self-proven sealing conditions and potential economic benefits obtained from enhanced oil or gas recovery (EOR or EGR) process by CO2 injection ((Intergovernmental Panel on Climate Change), 2005;Ren et al., 2010; Al-Hasami et al., 2005). Moreover, the oil and gas reservoirs will become more attractive if they are associated with large connected aquifers which can provide a great additional capacity for CO2 storage (Zhang et al., 2011, 2015a). CO2 EOR has been successfully applied in the oilfield for over 40 years. According to the 2014 worldwide EOR survey, 152 CO2 EOR projects are conducted around the world with about 14.70 million tons of oil produced through CO2 injection each year. The United States carries out most of these projects and contributes 93% of the oil production (Koottungal, 2014; Qin et al., 2015). Generally, CO2 EOR can increase oil recovery factor by 8–15%, and 1 m3 of additional oil needs 2.4–3 ton of CO2 injected. Hence, more than

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List of symbols MCO2 theory Theoretical CO2 storage capacity in oil reservoir, 104 tons MCO2 structure Structure trapping capacity of CO2 , 104 tons MCO2 dissolution Dissolution trapping capacity of CO2 , 104 tons MCO2 diswater Dissolution trapping capacity of CO2 in residual water, 104 tons oil dis MCO2 Dissolution trapping capacity of CO2 in residual oil, 104 tons MCO2 mineral Mineral trapping capacity of CO2 , 104 tons MCO2 effective Effective CO2 storage capacity in oil reservoir, 104 tons MCO2 eff structure Effective CO2 structure trapping capacity, 104 tons MCO2 effdis Effective CO2 dissolution trapping capacity, 104 tons MCO2 effdiswat Effective CO2 dissolution trapping capacity in residual water, 104 tons oil Effective CO dissolution trapping capacity in effdis MCO2 2 residual oil, 104 tons MCO2 eff mineral Effective CO2 mineral trapping capacity, 104 tons Original oil in place, 104 tons OOIP Vr Rock volume in oil reservoir underground, 104 m3 V␸ Pore volume in oil reservoir underground, 104 m3 Voi Initial oil volume in oil reservoir underground, 104 m3 Vwi Initial water volume in oil reservoir underground, 104 m3 Vop Recovered oil volume by CO2 injection underground, 104 m3 Vwr Residual water volume in oil reservoir underground, 104 m3 Vor Residual oil volume in oil reservoir underground, 104 m3 Vwr eff Residual water volume in the CO2 sweep area underground, 104 m3 Vor eff Residual oil volume in the CO2 sweep area underground, 104 m3 VCO2 str CO2 volume trapped at supercritical state in oil reservoir, 104 m3 RFBT Oil recovery factor when the CO2 breakthrough in the production wells, fraction RF%HCPV Oil recovery factor after CO2 breakthrough in the production wells, fraction ␸a Reservoir porosity and average porosity, respectively, % Soi , Swi Initial average oil saturation and initial average water saturation, respectively, fraction ores , osurf Oil densities at reservoir and surface, respectively, ton/m3 Bo Oil volume factor CO2res CO2 density at reservoir, ton/m3 SCO2 water Solubility of CO2 in formation water, ton/m3 SCO2 oil Solubility of CO2 in crude oil, ton/m3 Rctp Carbon trapping potential in unit volume of rock, ton/m3 k1 Areal coverage factor of well pattern (well pattern coverage area/OOIP coverage area) k2 Areal sweep efficiency of CO2 within well pattern coverage area 35–44 million tons of CO2 are injected each year in the USA (Stevens et al., 1999; Ren et al., 2010). With the CCS technology advance

in recent 20 years, the high-purity CO2 captured from man-made gas sources (such as chemical and power plants) is recommended for the EOR. Since July 2000, the world’s first largest CO2 EOR and storage project have been implemented in the Weyburn oilfield Canada by use of the CO2 captured from the lignite-fuelled Great Plains synfuels plant in the USA. Up to 1.2–1.8 million tons of CO2 is injected each year. Based on the preliminary assessment results, the theoretical storage capacity in the Weyburn oilfield is 45.15 million tons of CO2 . About 26 million tons of CO2 will be stored in the reservoir associated with 130 million bbls of crude oil recovered during the 20 years of operation (Preston et al., 2005; IEA, 2005). In recent years, China has also taken various actions to reduce the carbon emissions. Many international and domestic projects have been conducted to push the CCS development in China. Oil companies in China have paid much more attentions on CCS technology. The project scale of CO2 EOR has been enlarged, rather than at a small pilot test using commercial liquid CO2 for a short-term injection. The CO2 EOR and storage project conducted in the Jilin oilfield is the first large-scale CCS project in China (Zhang et al., 2014, 2015b,c; Ren et al., 2011, 2015a,b, 2016). The oilfield is located in the Songliao Basin in the northeast China (see Fig. 1a). The Daqingzijing region has been selected as the target site for CO2 injection based on its geological conditions and EOR potential. The project is aimed to evaluate the technical and economic feasibility of CO2 EOR and storage in the widespread tight and light oil reservoirs in China at an industrial scale. The project contains three phases (see Fig. 1b). The first phase is a small pilot test conducted in the north part of the H-59 block. It is comprised of 5 injectors and 19 producers in an inverted seven-point well pattern with the spacing of 250–300 m (see Fig. 1c). The injected CO2 is from the nearby Changshen 4 well which produces natural CO2 gas with a high purity up to 97 mol%. The second phase is an enlarged test in another block of H-79 with 18 injectors and 60 producers involved. Then CO2 injection will be extended to other blocks of Daqingzijing region with more than 200 well groups. The Changling natural gas field (see Fig. 1b) close to the H-79 block has a CO2 concentration of 21–23 mol%. The CO2 separated from the natural gas stream is used for the second and full-scale phases of CO2 EOR and storage operation. CO2 storage potential and trapping mechanisms in reservoirs are important factors for CO2 storage, which provides the basis for the storage capacity verification, the storage safety assessment, and the injection and monitoring scheme adjustment in the next stage of the project. The H-59 pilot test in the Jilin CCS project has been conducted since April 2008. Enough reservoir static and dynamic data are available for studying the CO2 storage and distribution in the H-59 block. This is the objective of the work. In this paper, the CO2 storage capacity is assessed by considering various CO2 trapping mechanisms. The distribution and trapping states of CO2 in the reservoir are evaluated by using the conventional reservoir simulation. Then the material balance of CO2 storage, the remaining CO2 storage potential, and the uncertainty of CO2 distribution in the H-59 block are discussed. These results are expected to provide valuable guidance for the CO2 EOR and storage projects in the Jilin oilfield and other oil reservoirs.

2. Geological characteristics of the H-59 block The Daqingzijing region is located in the center of the Changling sag in the south of the Songliao Basin. Changling sag is composed of two sub-sags: the southern Heidimiao sub-sag and the northern Qian’an sub-sag. The Daqingzijing region is located in the uplift area between the two sub-sags. The Daqingzijing region consists of more than 20 separate blocks mainly divided by faults. Most of these blocks are low permeability oil reservoirs buried at depth from 1800 m to 2500 m. The net thickness ranges from 2 m to 20 m. The

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269

Fig. 1. CO2 EOR and storage project in the Jilin oilfield in the northeast China.

main oil-bearing formations are located in the Qingshankou Group which was formed in the age of Cretaceous and deposited in a delta front environment (see the Qing I–III formations in Fig. 2a). Mature sand bodies are well developed in these oil reservoirs. The above cap rock is 500–550 m thick with stable distribution. It is composed of mudstone layers and shale intercalations, which divides the upper and lower groups into different hydrodynamic systems (Xu et al., 2009). The H-59 block is located on the west side of the central fault belt of Daqingzijing region (see Fig. 2a). It covers approximately an area of 3.1 km2 and the original oil in place is about 160 × 104 ton. The five well groups in the north of the block were selected for the pilot test, which covers an area of about 1.8 km2 and contains about 86 × 104 tons of light oil. The oil reservoir is buried at the depth of 2000–2400 m, with a small downward inclination angle of 2–4◦ from west to east. It is surrounded by four normal faults extending from north to south with a length of 1–3 km (see Fig. 1c). The total thickness of oil-bearing layers ranges from 11.2 m to 18.2 m, including the main layers 7, 12, 14, 15 in the Qing-I formation

of the Qingshankou Group. These main oil pay zones take 78% of OOIP (see Fig. 2b). The average porosity and permeability of the reservoir are 12.7% and 3.5 mD, respectively. The reservoir temperature is 98.9 ◦ C, and the original reservoir pressure is 24.15 MPa. The CO2 minimum miscible pressure (MMP) of the crude oil is 22.3 MPa by using the slim tube test. The oil viscosity and density at reservoir conditions are 1.85–2.18 mPa s and 0.7615–0.7686 g/cm3 , respectively. The initial oil saturation in the reservoir is lower than 50% (45% on average). The original gas-oil ratio is 35 m3 /ton corresponding to a bubble point of 7.31 MPa. The salinity of the formation water is between 10229 and 19320 mg/L (Zhang et al., 2014). In addition, the core analysis results show that the reservoir lithology of the H-59 block is mainly siltstone associated with a small fraction of fine sandstone and muddy siltstone. The main mineral components of sandstone grains are quartz (18–29 wt%), feldspar (24.5–37.5 wt%) and debris (26.8–30.7 wt%). The main mineral components of cementing material between the sandstone grains are mudstone (6–21 wt%) and limestone (3–34 wt%) as well as a small amount of siliceous matters (1–3 wt%) (Cheng, 2012).

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Fig. 2. Geological profiles of Daqingzijing region and the H-59 block.

3. CO2 storage potential in the H-59 block

3.1. Theoretical CO2 storage capacity

Assessment of CO2 storage capacity in the H-59 block is very important for verifying the storage effectiveness and safety. Reservoir simulation can be used for relatively precise capacity assessment when detailed reservoir data are available. Another simple assessment methodology based on the material balance are mostly used in the screening period as limited data are accessible (Shaw and Bachu, 2002; Bachu and Shaw, 2003, 2005; Bachu et al., 2004, 2007; Goodfield and Woods, 2001; Hendriks et al., 2004; Zhang et al., 2009a, 2011; Shen et al., 2009). The physical considerations of both methodologies are similar. The voided pore space caused by production process is mainly considered for CO2 storage in oil reservoirs. In addition to the injected CO2 filled in the pore space which is previously occupied by the produced oil and water, some of the injected CO2 will be dissolved in residual oil and formation water. Further, some dissolved CO2 may react with the rock minerals to form the mineral precipitation.

In this study, the CO2 storage capacity in the H-59 block was calculated by using the material balance approach, which considers various trapping forms of CO2 . To facilitate the mathematical formulation of the storage capacity, it is assumed that the CO2 storage capacity is composed of the capacities contributed by each trapping mechanisms (Chadwick et al., 2008). Hence, the theoretical storage capacity of CO2 in the H-59 block can be evaluated in the following three aspects based on the geological conditions and fluid properties of the target reservoir. theory

MCO

2

= Mstructure +Mdissolution +Mmineral CO CO CO 2

2

2

(1)

where MCO2 theory is the theoretical CO2 storage capacity in the oil reservoir, 104 tons; MCO2 structure is the structure trapping capacity of CO2 , 104 tons; MCO2 dissolution is the dissolution trapping capacity of CO2 , 104 tons; MCO2 mineral is the mineral trapping capacity of CO2 , 104 tons.

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3.1.1. Structure trapping capacity Many methods can be used to calculate the CO2 structure trapping capacity. They might be only applicable for the specific reservoir types under specific CO2 injection processes (Shaw and Bachu, 2002; Bachu et al., 2004; Goodfield and Woods, 2001; Hendriks et al. 2004). Before CO2 injection, the H-59 block only had a very short-term water flooding after primary recovery, and the cumulative oil recovery factor was just about 5%. Therefore, the water flooding history can be neglected and the H-59 block can be treated as a reservoir with CO2 injection after the primary recovery. The method proposed by Shaw and Bachu (2002) can be therefore used to estimate the structure trapping capacity of CO2 in the target reservoir. This method assumes that the injected CO2 will occupy all the pore space of produced oil before CO2 breakthrough in production wells. Only a part of produced oil pore space can be used for CO2 storage when water-alternating-gas (WAG) flooding is adopted after CO2 channeling occurs. The formula of the structure trapping capacity is shown as follows:

compared with the pressure effect. At typical reservoir conditions, CO2 solubility in oil is generally between 0.05–0.35 ton/m3 , while at the original reservoir conditions of H-59 block, the solubility of CO2 in oil is 0.2156 ton/m3 which is 4.3 times of the CO2 solubility in formation water (see the red star marked in Fig. 3b). Assuming CO2 can be dissolved in all the residual formation water and crude oil, then the theoretical dissolution trapping capacity of CO2 in the H-59 block can be calculated by using the following formula (3). About 25.93 × 104 tons of CO2 can be dissolved in the fluids in the H-59 block. The residual oil contributes 18.40 × 104 tons of CO2 and the residual water offers the rest part.

Mstructure = [RFBT +0.6 (RF%HCPV −RFBT )] OOIP × Bo × CO CO

tion water, ton/m3 ; SCO2 oil is the solubility of CO2 in the crude oil, ton/m3 .

2 res

2

/osurf (2)

where RFBT is the oil recovery factor when CO2 breakthroughs in production wells, fraction; RF%HCPV is the oil recovery factor after CO2 breakthrough in production wells, fraction; OOIP is the original oil in place, 104 tons; Bo is the oil volume factor; osurf is the oil density at surface, ton/m3 ; CO res is the CO2 density at reservoir, 2

ton/m3 . The main reservoir and fluid properties of the H-59 block (referring to the five well groups for CO2 injection) are summarized in Table 1. Based on the preliminary results of reservoir simulation conducted before CO2 injection, the oil recovery factor before CO2 breakthrough in production wells was assumed to be 0.17 (2008–2013), while the finial recovery factor was assumed to be 0.28 at the end of WAG flooding (2013–2018). By using formula (2), the structure trapping capacity of CO2 in the H-59 block is estimated to be 15.53 × 104 ton. According to the material balance equation and assuming an incompressible reservoir, the volumes of rock, pore and various types of fluids in the H-59 block at initial reservoir conditions have been further calculated and shown in Table 2. The related formulas used for calculation are also listed in the table. 3.1.2. Dissolution trapping capacity CO2 can be dissolved in the formation water and crude oil. The Duan & Sun model was used to calculate the CO2 solubility in the formation water of H-59 block (SCO2 water ). This model considers the effect of different mineral ions on CO2 solubility under wide application conditions with the temperature between 0 and 260 ◦ C, the pressure between 0 and 200 MPa, and salinity between 0 and 4 mol NaCl/kg H2 O (Duan and Sun, 2003; Duan et al., 2006). The average salinity of the formation water in the H-59 block is 14607.8 mg/L, and the ionic compositions are listed in Table 3. The calculated CO2 solubility in the formation water at different temperatures and pressures is shown in Fig. 3a. It can be seen that at a low pressure (5–20 MPa), the solubility of CO2 in the formation water would decrease as temperature rises. However, when the pressure is over 25 MPa, the CO2 solubility would increase after the temperature exceeds 70–80 ◦ C. The typical CO2 solubility in the formation water is between 0.04–0.08 ton/m3 . At the original reservoir conditions of the H-59 block, the solubility of CO2 in the formation water is 0.0502 ton/m3 (see the red star marked in Fig. 3a). The prediction model of N2 , CO2 and CH4 solubility in the oil phase proposed by Xue et al. (2005) was selected to calculate the CO2 solubility in the crude oil of H-59 block (SCO2 oil ). The model is simple and only needs several inputs. As seen in Fig. 3b, temperature has the opposite effect on the CO2 solubility in the crude oil

oil Mdissolution = Mdiswater +Mdisoil = Vwr × Swater CO2 +Vor × SCO2 CO CO CO 2

2

2

(3)

where MCO2 effdiswater is the dissolution trapping capacity of CO2 in

residual water, 104 tons; MCO2 effdisoil is the dissolution trapping capacity of CO2 in residual oil, 104 tons; Vwr is the residual water volume in oil reservoir, 104 m3 ;Vor is the residual oil volume in oil reservoir, 104 m3 ; SCO2 water is the solubility of CO2 in forma-

3.1.3. Mineral trapping capacity When CO2 dissolves in water, carbonate ion (CO3 2− ) is generated and can react with divalent cations and lead to carbonate precipitation. Therefore, CaCO3 , MgCO3 and FeCO3 are regarded as the main mineral trapping types. Those non-carbonate minerals that release Ca2+ , Mg2+ and Fe2+ through dissolution reactions are called the minerals with carbon trapping potential. The carbon trapping potential of minerals (Rctp ) can be estimated by calculating the amount of CO2 consumed when all the Ca2+ , Mg2+ and Fe2+ in non-carbonate minerals in unit volume of rock are transferred to carbonate precipitations (Xu et al., 2001; Zhang, 2011). Table 4 lists the mineral compositions and carbon trapping potentials of the rock in the H-59 block. The reservoir rock of H-59 block contains considerable quartz, feldspar (including K-feldspar and plagioclase), a certain amount of calcite, ankerite, and a little pyrite and clay minerals (including kaolinite, illite, chlorite, and montmorillonite). Although clay minerals just take a little part of rock minerals, they usually have a great impact on reservoir and formation water physical/chemical properties. As shown in Table 4, only the chlorite and illite have carbon trapping potentials in the H-59 block, and the carbon trapping potential in unit volume of rock is 8.4744 × 10−3 tons/m3 . Then a mineral trapping capacity of 17.58 × 104 tons of CO2 in the H-59 block is obtained by using the following formula (4). Mmineral = Vr × Rctp CO 2

(4)

where Vr is the reservoir rock volume, 104 m3 ; Rctp is the carbon trapping potential in unit volume of rock, ton/m3 . 3.1.4. Theoretical storage capacity Based on the above formulation and calculation, the theoretical CO2 storage capacity in the H-59 block would be 59.04 × 104 tons by summing the theoretical capacities of structural, dissolution and mineral trapping (Table 5). The structure trapping stores 26.30% of the capacity, while the dissolution trapping contributes 43.92% (12.75% and 31.17% dissolved into residual water and oil, respectively), and the mineral trapping takes the rest of 29.78%. Table 5 also lists the effective CO2 storage capacities which will be analyzed in the following part. 3.2. Effective CO2 storage capacity The complexity of displacement process and geological features can reduce the effective storage potential of CO2 in oil reservoirs.

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Table 1 Reservoir and fluid properties of the H-59 block (the five well groups for CO2 injection). Parameter

Value

Parameter

Value

Cover area, km2 Buried depth, m Reservoir thickness, m Average thickness, m Dip angle, ◦ Reservoir temperature, ◦ C Reservoir pressure, MPa Porosity, % Average porosity ␸a , % Permeability, md Average permeability, mD OOIP (the five well groups), 104 tons Initial average oil saturation Soi , fraction

1.8 2000−2400 11.2–18.2 14.3 2–4 98.9 24.15 8–15 12.7 0.24–9.85 3.5 86 0.45

Initial average water saturation Swi , fraction Oil viscosity at reservoir, mPa s Oil density at reservoir ores , ton/m3 Oil density at surface osurf , ton/m3 Oil volume factor Bo Gas-oil ratio (GOR), m3 /ton Salinity, mg/L Average salinity, mg/L pH value of formation water CO2 density at reservoir CO2res , ton/m3 CO2 -oil MMP, MPa RFBT , fraction RF%HCPV , fraction

0.55 1.85–2.18 0.7615–0.7686 0.8503 1.1723 35 10229–19320 14607.8 6.8 0.555 22.3 0.17 0.28

Table 2 Rock, pore and fluid volumes in the H-59 block at reservoir conditions. Volumes of rock and fluid

Value

Calculation formula

Rock volume Vr , 104 m3 Pore volume V␸, 104 m3 Initial oil Voi , 104 m3 Initial water Vwi , 104 m3 Oil recovered by CO2 injection Vop , 104 m3 Residual oil Vor , 104 m3 CO2 trapped at supercritical state VCO2 str , 104 m3 Residual water Vwr , 104 m3

2074.7 263.5 118.6 144.9 33.21 85.37 27.98 150.1

Vr = V␸ /␸a V␸ = Voi /Soi Voi = OOIP × Bo /osurf Vwi = V␸ × Swi Vop = Voi × RF%HCPV Vor = Voi × (1 − RF%HCPV ) structure Vstr /CO2res CO2 = MCO2 Vwr = V␸ −Vor − Vstr CO 2

Table 3 Average ionic composition in the formation water of H-59 block. Mineral ion

Na+

K+

Ca2+

Mg2+

Cl−

SO4 2−

HCO3 −

CO3 2−

Al3+

concentration, mg/L concentration, mmol/kg

3560.44 154.80

1478.95 37.92

117.77 2.94

16.61 0.69

5446.16 153.41

2955.64 30.79

576.22 9.15

185.05 2.98

270.97 10.04

Fig. 3. CO2 solubility in formation water and crude oil of H-59 block. Table 4 Mineral compositions and carbon trapping potentials of the H-59 block. Mineral

Composition, vol% (based on rock matrix) range

Quartz 30.17–54.67 Plagioclase 27.64–53.15 K-feldspar 1.57–10.10 Ankerite 0−25.67 Calcite 0−19.24 Siderite 0−2.08 0.19–2.68 Chlorite Kaolinite 0.03–0.48 Illite 0.49–6.71 Carbon trapping potential Rctp , ton CO2 /m3

Composition, vol% (based on rock)

Carbon trapping potential, ton CO2 /m3 mineral

Carbon trapping potential, ton CO2 /m3 rock

Chemical formula

37.83 34.84 4.56 4.64 2.84 0.09 0.68 0.12 1.70

0 0 0 0 0 0 1049.20 × 10−3 0 78.81 × 10−3 8.4744 × 10−3

0 0 0 0 0 0 7.1346 × 10−3 0 1.3398 × 10−3

SiO2 NaAlSi3 O8 KAlSi3 O8 Ca[Fe/Mg](CO3 )2 CaCO3 FeCO3 [Fe/Mg]5 Al2 Si3 Ol0 (OH)8 Al2 (Si2 O5 )(OH)4 K0.6 Mg0.25 Al1.8 (Al0.5 Si3.5 O10 )(OH)

average 43.33 39.91 5.22 5.32 3.25 0.10 0.78 0.14 1.95 rock

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Table 5 CO2 storage capacity of the H-59 block. Trapping mechanism

Structure

Residual water

Residual oil

Mineral

Total

Theoretical capacity, 104 tons Effective capacity, 104 tons

15.53 15.53

7.53 4.19

18.40 6.65

17.58 0

59.04 26.37

Fig. 4. Production history of the H-59 block.

Fig. 5. Geological model of the H-59 block.

American experiences have indicated that only 60% of injected CO2 can be stored in oil reservoirs if no reinjection is considered after CO2 breakthrough in production wells (Shaw and Bachu, 2002; Gozalpour et al., 2005; Zhang et al., 2009a; Ren et al., 2010). During the CO2 EOR and storage process, the effective storage capacity is subject to the CO2 sweep efficiency and project duration. Only the reservoir volume swept by the injected CO2 can be used for geological storage. Therefore, the effective storage capacity of CO2 is mainly controlled by the areal coverage factor (k1 ) of the well pattern (i.e., the ratio between well pattern coverage area and OOIP coverage area) and the volumetric sweep efficiency (k2 ) of CO2 within the

well pattern. The H-59 block is a thin-layer oil reservoir, the vertical sweep efficiency can be, therefore, assumed to be 1. The parameter k1 is a constant if the well pattern is pre-determined while the parameter k2 will increase as CO2 injection proceeds. Considering this, the maximum areal sweep efficiency of CO2 would be a reasonable approximation for k2 . Similar to the components of theoretical CO2 storage capacity, the effective CO2 storage capacity can be calculated as follows.

effmineral Meffective = Meffstructure +Meffdis CO CO CO +MCO 2

2

2

2

(5)

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Table 6 Cumulative injection and production data in the H-59 block (up to June 2014). Reserve and production data

Fluid type

Value

Original reserve, 104 tons Cumulative injection data, 104 tons Cumulative production data, 104 tons

Crude oil Formation water Water injection CO2 injection Oil production Water production CO2 production Residual oil Residual water Stored CO2

86.00 144.90 10.96 21.08 12.64 11.93 0.96 73.36 143.93 20.12

Current reserve, 104 tons

where MCO2 effective is the effective storage capacity, 104 tons; is the effective structure trapping capacity, 104 tons; MCO2 effdis is the effective dissolution trapping capacity, 104 tons;MCO2 effmineral is the effective mineral trapping capacity, 104 tons. The capacities of these three types of trapping mechanisms are calculated below. 3.2.1. Effective structure trapping capacity The oil recovery factor has been used in the calculation of theoretical structure trapping capacity of CO2 . This means that the swept volume of CO2 in oil reservoir has been automatically accounted for. Thus, the effective CO2 structure trapping capacity is equal to the theoretical calculation in this study (MCO2 structure = MCO2 effstructure = 15.53 × 104 tons). 3.2.2. Effective dissolution trapping capacity As mentioned above, in practice, the injected CO2 only dissolves in the residual water and oil in the swept zone. The effective dissolution trapping capacity of CO2 can be calculated by using the following formulas (6–8). water oil eff Meffdis = Meffdiswater +Meffdisoil = Veff wr × SCO2 +Vor × SCO2 CO CO CO

(6)

Veff or = Voi × (k1 k2 − RF%HCPV )

(7)

str eff Veff wr = V␾ × k1 k2 -−VCO − Vor

(8)

2

2

2

2

where MCO2 effdiswater and MCO2 effdisoil are the effective CO2 dissolution trapping capacities in residual water and oil, respectively, 104 tons. Vwr eff and Vor eff are the volumes of residual water and oil in the CO2 sweep area, respectively, 104 m3 ; V␸ is the pore volume in the oil reservoir, 104 m3 ;Voi is the initial oil volume in the oil reservoir, 104 m3 ;k1 is the areal coverage factor of well pattern; k2 is the areal sweep efficiency of CO2 within the well pattern; VCO2 str is the CO2 volume trapped at supercritical state in the oil reservoir, 104 m3 . The parameters k1 and k2 are important factors for the calculation of residual water and oil volumes in the CO2 sweep area. For the H-59 block in this study, 0.9 was estimated for k1 based on the ratio between the internal coverage area of the five well groups and the coverage area of OOIP (see Fig. 1c). For the k2 , the reservoir simulation conducted by Cui and Fu (2011) has showed that the sweep efficiency for the CO2 miscible flooding varies between 25 and 50% under different CO2 injection strategies (i.e., pure CO2 injection, CO2 slug injection and WAG injection) when an inverted five-point well pattern is adopted. However, the H-59 block uses an inverted seven-point well pattern. Hence, a larger CO2 sweep efficiency of 60% for k2 was considered, which assumes an ideal miscible flooding is achieved. Based on the above formulas, the effective dissolution trapping capacity of CO2 in the H-59 block is determined to be 10.84 × 104 tons;the residual water and oil stores 4.19 × 104 and 6.65 × 104 tons of CO2 , respectively.

3.2.3. Effective mineral trapping capacity Geochemical reaction in the oil reservoir induced by CO2 injection is a complicated process, which involves aqueous reactions, mineral dissolution, and precipitation. Many studies have been conducted to investigate the mineral trapping capacity of CO2 in oil reservoirs and saline aquifers. The results show the mineral compositions of reservoir rock may change dramatically because of the geochemical reactions. A small fraction of CO2 is retained by mineral trapping even after a long-term storage process. The mineral trapping in the clean sandstone reservoir typically accounts for about 1–2% of the total CO2 storage capacity, even in the dirty sandstone and carbonate reservoirs. This fraction might increase to 5–20% after several thousand years of storage (Zhang, 2011; IEA, 2005; Xu et al., 2001; Holloway et al., 2004; Portier and Rochelle, 2005; Andre et al., 2007; Bachu et al., 2007). By contrast, the mineral trapping can be negligible for the short period of CO2 injection (in an order of decades). Therefore, the effective mineral trapping capacity of CO2 in the H-59 block is set to be zero (MCO2 effmineral = 0) although the theoretical trapping potential might be considerable. Based on the above calculation, the effective CO2 storage capacity in the H-59 block is estimated to be 26.37 × 104 ton (Table 5). It is only 45% of the theoretical storage capacity. The discrepancy is attributed to the neglected mineral trapping capacity and reduced dissolution capacity.

4. Current CO2 storage amount and distribution in the H-59 block 4.1. Production history and current CO2 storage amount (up to June 2014) For the H-59 block, the oil production started in 2004 with 4 years of primary recovery. Then water injection was adopted, but its performance was bad because of poor water injectivity and reservoir heterogeneity. In April 2008, CO2 injection was initiated in the selected five well groups in the northern part of the H-59 block. Most of the production wells were shut down for 5 months, and meanwhile, CO2 injection was continued with the rate of 30–50 tons/d per well. This facilitates to recover the reservoir pressure quickly and achieve miscible flooding. The average reservoir pressure was restored to be 20.3 MPa in March 2009. Then all the production wells resumed production. According to the initially designed injection scheme, WAG operation or water injection would start after 5 years of pure CO2 injection. However, because of an early CO2 breakthrough in certain producers, aperiodic and non-simultaneous WAG operations were started in some injectors to improve the sweep efficiency in May 2009. The water-gas ratio was usually between 1:2 and 1:5 (at the reservoir conditions). In a WAG cycle, water injection was lasted for 1–4 months at the rate of 30–40 m3 /d (1000–4800 m3 pore volume per slug), and then CO2 was injected for 2–12 months at the rate of 30–50 tons/d per well (4000–24000 m3 pore volume per CO2 slug). As shown in Fig. 4a, the oil production rate of the H-59 block (five well groups) increased significantly after CO2 injection started. The GOR trend changed in opposite to the oil production. CO2 early breakthrough occurred after one year of injection, and the CO2 content in the produced gas fluctuates between 30 and 90%. The GOR was maintained at a small level between 50 and 250 m3 /m3 because of the WAG operation. Water cut was high even at the beginning of production. As WAG injection proceeded, the water cut gradually increased from 40% to 70%. In addition, the average reservoir pressure of H-59 block increased after CO2 injection, and it keeps around 15–20 MPa during the study period. The injection and production history of the H-59 block is shown in Fig. 4b and the cumulative data to date are listed in Table 6. Up

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Table 7 Component properties in the fluid model. Component

CO2

N2 -C1

C2-C6

C7+

Critical pressure, MPa Critical temperature, ◦ C Critical volume, cm3 /mol Molecular weight, g/mol Partial molar volume in aqueous phase, cm3 /mol Oil composition, mol% Henry constant, MPa

7.280 30.42 94.00 44.01 36.09 0.343 510

4.420 18.35 97.89 17.30 35.91 18.71 /

4.124 38.71 21.45 48.88 76.73 15.389 /

1.535 73.54 87.69 24.56 37.70 65.558 /

to June 2014, more than 21.08 × 104 tons of CO2 has been injected which is equivalent to 32.03% of hydrocarbon pore volume (HCPV). Nearly 95.45% of the injected CO2 (30.57% of HCPV, 20.12 × 104 tons) has been stored in the oil reservoir with the rest of CO2 produced. About 12.64 × 104 tons of crude oil has been cumulatively produced via CO2 injection, with the oil recovery factor increased from 5% to 14.70%. 10.96 × 104 tons of water has been injected during WAG operation with 11.93 × 104 tons of water produced meanwhile.

4.2. Distributions and amounts of CO2 trapped at various forms 4.2.1. Reservoir simulation and history matching A reservoir simulation study has been conducted to predict the CO2 distribution in the H-59 block (CMG, 2012). The 3D geological model of the H-59 block was built based on the geological data. The corner point grid was used with the grid number of 77 × 80 × 25 = 154000 and an average grid size of 25 × 25 m. The grid layers 5, 10, 12, 13 and 21 in the geological model correspond to the real reservoir layers 7, 12, 14, 15 and 23. The distributions of porosity, permeability and initial oil saturation in the geological model were generated through stochastic modeling based on the well data and previous understanding (see Fig. 5). The reservoir pressure and temperature are 24.15 MPa and 98.9 ◦ C, respectively. Four oil components (namely, CO2 , N2 C1, C2 C6 , and C7 + ) were defined in the fluid model (see Table 7). The solubility of CO2 in the formation water was calculated by Duan & Sun model (Duan and Sun, 2003; Duan et al., 2006), and a Henry constant of 510 MPa was used in the PVT simulation. The CO2 dissolution in the crude oil was simulated by using EOS model. The geochemical reactions were neglected as discussed before. The relative permeability curves in the simulation were measured by the steady-state method, which is shown in Fig. 6. Production history matching is a routine procedure of obtaining an accurate distribution of CO2 in the oil reservoir. The OOIP and reservoir pressure of the H-59 block were firstly fitted by mainly adjusting the effective thickness (within −30%), and the compressibility coefficient of the reservoir (within 100%). Then the production data of the H-59 block were fitted carefully by mainly adjusting the relative permeability curves (only change the shape of curves rather than the endpoints) and the local permeability (increased or reduced several times and even more) based on the previous understanding of reservoir properties. A fitting error of 1.17% was finally achieved for OOIP. All the CO2 and water can be injected into the reservoir during simulation, which is also consistent with the field injection data (see Fig. 7a). The cumulative and daily production of oil and water were also matched well (see Fig. 7b), and nearly 90% of production wells reached the fitting standard with an error within 5%. Although the fitted breakthrough time of CO2 in the production wells fell behind the real time, the fitted final cumulative production of CO2 was very close to the field data. It’s hard to match the CO2 production especially for thin-layer oil reservoir with serious heterogeneity, which will be discussed later.

Fig. 6. Relative pemeability curves.

4.2.2. Distributions of CO2 trapped at various forms Many factors can affect the distribution of injected fluid in the oil reservoir, such as the geological structure, reservoir heterogeneity, layer thickness, fluid properties, well pattern and injection scheme. The H-59 block is composed of many thin oil-bearing layers with stable interlayers sandwiched between them. This structural feature determines that most of the injected CO2 would move only along the horizontal direction in the thin oil layers. This further affects the distribution of CO2 trapped in the different forms in the H-59 block. The current CO2 saturation distributions in the several selected oil layers of the H-59 block are shown in Fig. 8. The stored CO2 at supercritical state is mainly located within each well group around the injector, which exhibits different sizes and shapes. The main oil layers 7, 14 and 15 have good reservoir properties (larger net thickness and wider sand-body distribution). Therefore, they achieve a better CO2 sweep efficiency varying from 20% to 80% for different well groups. However, the layer 23 has a bad CO2 sweep efficiency because of its isolated lenses and thin pay-zone. Therefore, most of the injected CO2 migrates along the main oil layers of the H-59 block (accounting for over 80%). This has also been reflected by the CO2 injectivity of each injector. The CO2 bearing area within each

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Fig. 7. History matching of cumulative injection and production of the H-59 block.

Fig. 8. CO2 saturation and permeability distributions in different layers of H-59 block (up to June 2014).

well group has a good consistency with the injected CO2 amount in each injector. For example, about 25.81% and 23.20% of the total injected CO2 have been injected via the injectors H59-4-2 and H596-6, respectively, and a larger CO2 bearing area is observed in these two well groups. It should be indicated that the above analysis is based on the situation of no serious CO2 channeling into production wells. In addition, the injected CO2 tends to spread in the updip direction of the reservoir. This is mainly attributed to the good reservoir properties in the high position of the block. The small reservoir angle of 2–4◦ from east to west may also play the similar effect in the local region. Overall, the shape of CO2 displacement front is mainly affected by the reservoir heterogeneity and the well

pattern, both of which determine the flow resistance and direction during CO2 migration. Hydraulic fractures in the production wells are incorporated in the geological model of the H-59 block, but their effects on CO2 final distribution are not observed in this simulation. One reason is that the CO2 sweep area is much larger than that impacted by the hydraulic fracture. Another reason might be the large grid size effect which smears the detailed information of CO2 movement around the production wells. Similar to the distribution of free CO2 , the CO2 dissolved in crude oil and formation water only exist in the area swept by the injected CO2 . However, due to the CO2 dissolution and diffusion in oil and water phase, the area with dissolved CO2 is usually larger than that with supercritical CO2 . Taking the layer 12 for example (Fig. 9),

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Fig. 9. Oil saturation and CO2 mole faction in the remaining fluids of H-59 block (layer 12, up to June 2014).

the mole fraction of CO2 in the remaining water is 0.0227, while the mole fraction of CO2 in the remaining oil is 0.4–0.8. The distributions of CO2 dissolution in both oil and water are larger than that of supercritical CO2 , as the comparison between Fig. 8 and Fig. 9. Especially, the distribution of dissolved CO2 across the well groups of H59-8-4, H59-4-2 and H59-6-6 overlapped around the well H59-6-4. 4.2.3. Amounts of CO2 trapped at various forms According to the reservoir simulation results, the amounts of CO2 trapped in various forms in the H-59 block are shown in Fig. 10a. The CO2 injection started in 2008, the amounts of CO2 trapped in different forms increased almost linearly with time. In 2012, the injection rate of CO2 started to decrease, the amount of CO2 trapped at the supercritical state, therefore, grew slower. Meanwhile, more CO2 tended to be dissolved in the residual water and oil. Additionally, the proportions of CO2 trapped in various forms changed rapidly at the beginning of CO2 injection but kept at a relatively stable level after one year (see Fig. 10b). Up to June 2014, about 20.12 × 104 tons of CO2 has been stored in the oil reservoir, of which the structure trapping takes 60.15%, and the CO2 dissolved in residual oil and water account for 24.85% and 15.00%, respectively. 5. Discussions 5.1. Material balance analysis of stored CO2 In addition to the reservoir simulation method, the material balance principle can also be used for a simply analysis on the distribution and trapping status of CO2 stored in the H-59 block. As shown in Table 6, up to June 2014, 73.36 × 104 tons of crude oil, 143.93 × 104 tons of formation water, and 20.12 × 104 tons of CO2 remain in the reservoir of H-59 block. As a result of the small reservoir compressibility (of 5 × 10−7 1/kPa), the reservoir pore volume reduction induced by pressure decline from 24.15 to 20 MPa can be neglected. If further neglecting the fluid expansion induced by CO2 dissolution in the contacted oil and water, the pore volumes of the remaining oil and water in the H-59 block are estimated to be 101.14 × 104 m3 and 143.93 × 104 m3 , respectively. Hence, only 18.43 × 104 m3 of pore volume is used to store CO2 at the supercritical state. At current reservoir conditions, the CO2 solubility in the crude oil and formation water are 0.1785 tons/m3 and 0.0467 tons/m3 , respectively, and the CO2 density is 0.466 ton/m3 . Therefore, the amount of CO2 trapped at supercritical state is about 8.59 × 104 tons, and the rest of 11.54 × 104 ton of CO2 would be dissolved in the residual oil and water. Assuming the same probability of these oil and water contacting the injected CO2 , about 46.2% of

the remaining oil and water should be used for CO2 dissolution. It can be further derived that 41.8% and 15.53% of the stored CO2 are dissolved in crude oil and formation water, respectively. The rest of 42.68% CO2 is trapped at supercritical state. These data are different from the reservoir simulation results (see Table 8). In the field, the injected CO2 in the reservoir may contact more oil and water under the combined effect of WAG operation and reservoir heterogeneity before serious gas channeling occurs. However, in the reservoir simulation, the CO2 sweep area is relatively smaller and uniform because of the limited accuracy of heterogeneity description on the H-59 geological model. Moreover, a CO2 sweep efficiency of 54.10% (k1 k2 ) in the reservoir at present can be further obtained from the formula (7) (where, Vor eff = 101.13 × 104 × 46.2% = 46.73 × 104 m3 , Voi = 118.6 × 104 m3 , RF%HCPV = 14.7%). This value is very close to that used in the effective capacity assessment (k1 = 0.9, k2 = 0.6, k1 k2 = 0.54), which may indicate that the CO2 sweep efficiency in the H-59 block to date has reached a high level at present. At next stage, the displacement efficiency of CO2 should be increased while maintaining or enhancing the current CO2 sweep efficiency. Some pertinent measures, such as increasing the reservoir pressure and the bottom-hole pressure of producers, can be taken to improve the miscible effect of CO2 in the reservoir. This process may increase the proportion of structure trapping from 42.68% to 58.89% as calculated in the effective storage capacity part (see Table 8). The material balance analysis verifies the credibility of proportions of CO2 trapped at various forms calculated by simple analytical model and reservoir simulation. 5.2. The remaining capacity for CO2 storage According to the assessment results, the effective CO2 storage capacity in the H-59 block is expected to be 26.37 × 104 tons. This is a relatively reliable result calculated by using the well-established assessment methodology, which considers the manner of gas injection, the effective sweep volume of gas flooding, and the different CO2 trapping mechanisms. Although other methods are still based on the material balance principle (Shaw and Bachu, 2002; Bachu and Shaw, 2003, 2005; Bachu et al., 2004, 2007; Goodfield and Woods, 2001; Hendriks et al., 2004; Zhang et al., 2009a, 2011; Shen et al., 2009), the assessment method used in this paper would be more accurate. This is because the incorporation of oil recovery factor is more physically reasonable than direct correlating reservoir properties with CO2 storage potential. Numerous valuable studies have been tried to explore the impact of reservoir properties (such as well pattern, oil viscosity and density, miscible effect) on oil recovery. These correlations have been used to predict the

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Fig. 10. Amounts and proportions of CO2 trapped in various forms in the H-59 block. Table 8 Effective storage capacity, current storage amount and proportions of CO2 trapped at various forms. CO2 amount and capacity

Value, 104 tons

Current storage amount (up to June 2014) Effective storage capacity

20.12

a b c

26.37

Proportion, % Structure

Residual oil

Residual water

60.15a 42.68b 58.89c

24.85a 41.80b 25.22c

15.00a 15.52b 15.89c

Predicted according to the history matching results of reservoir simulation. Calculated based on the material balance equation. Calculated according to the effective storage capacities of various CO2 trapping mechanisms.

oil recovery factor in the lab, field or simulation results (Stevens et al., 1999; Hendriks et al., 2004; Zhang et al., 2009b; Mohammadi et al., 2014). This makes the oil recovery factor-based CO2 storage capacity assessment much more easily realizable and convenient. It should be noted that the introduced parameters k1 and k2 in this assessment method are only suitable for the thin-layer oil reservoirs such as the H-59 block. The determination of these two parameters should be careful under the specific case, as they largely affect the assessment results of effective CO2 storage capacity in the oil reservoir. As shown in Table 8, comparing the current storage amount of 20.12 × 104 tons with the effective storage capacity, the remaining 6.25 × 104 ton might be for the future CO2 storage in the H-59 block. The proportions of CO2 trapped in various forms calculated according to the effective storage capacity are coincidentally close to those from reservoir simulation, this is likely to be caused by different factors as mentioned above. Although CO2 channeling occurred in the production wells at the early injection, this is different from the calculation assumptions of effective CO2 storage capacity, however, the subsequent WAG operation conducted in the H-59 block has effectively controlled the gas channeling and maintained the GOR in the production wells at a small level of no more than 250 m3 /tons. Most of the injected CO2 has been stored in the reservoir. This performance can bring the operator confidence to achieve the remaining storage capacity as CO2 injection proceeds, and necessary engineering measures should be taken to further improve the CO2 storage amount in the target reservoir. 5.3. Prediction reliability of CO2 distribution It is very hard to build an exact geological model for reservoir simulation of gas injection, especially for the H-59 block consisting of many thin oil-bearing layers with serious heterogeneity partly induced by the hydraulic fracturing. The movement of CO2 in oil reservoir is sensitive to the reservoir heterogeneity, and this effect is pronounced by the higher mobility of CO2 than both water and

oil. All the above features of reservoir and fluids, especially the fractures and high-permeability channels in the reservoir, brings huge difficulty in CO2 production fitting. As seen in Fig. 11a, although the simulated cumulative production of CO2 is close to the field data, the simulated breakthrough time of CO2 in production wells falls behind the real time. Moreover, the simulated daily CO2 production increases gradually which is very different from the relatively stable daily CO2 production in the field (the results in Fig. 11a and Fig. 7 are based on the same model). As a result, a relatively smaller CO2 sweep area and a larger proportion of CO2 trapped at supercritical state were obtained in the simulation. Despite these, the predicted CO2 distribution in the target reservoir still has a reference value, because only 5% of the injected CO2 had been produced till June 2014, and the endpoint of CO2 cumulative production data in the simulation was fitted well. The geological model of the H-59 block should be updated periodically as the understanding to the reservoir is deepened, in order to continually improve the prediction accuracy of CO2 distribution and trapping status in the target oil reservoir by using simulation method. To do this, some reservoir monitoring data can be used to improve the description of the heterogeneity in the reservoir, such as the gas tracer test. It is useful to assess the connectivity between injection and production wells and identify the main high permeability streaks and fractures in the reservoir (see Fig. 11b). More attentions should be paid on the hydraulic fractures. The hydraulic fractures would interact with the natural fractures and may effectively increase the connectivity between wells with small spacing. The effect of hydraulic fractures on early gas channeling in the reservoir needs more investigation. 6. Conclusions (1) The CO2 storage capacities in the H-59 block are evaluated at different levels by using different methodologies. The theoretical CO2 storage capacity was calculated by assuming most of the pore space occupied by produced oil filled with CO2 at the supercritical

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Fig. 11. Early breakthrough of CO2 in the production wells due to serious reservoir heterogeneity.

state. Meanwhile, the residual oil and water are used for CO2 dissolution and the minerals with carbon trapping potential add to the storage potential. The effective CO2 storage capacity considers the CO2 sweep efficiency (through parameters k1 and k2 ) and neglects the mineral trapping for the case of thin-layer oil reservoirs. Using the established methods, the theoretical storage capacity of CO2 in the H-59 block is estimated to be 59.04 × 104 tons while the effective storage capacity is 26.37 × 104 ton. (2) Up to June 2014, 21.08 × 104 tons of CO2 has been injected into the H-59 block with over 95% stored. The CO2 plume shape and size are determined by the geological structure, reservoir heterogeneity, well pattern and CO2 injected amount. The WAG operation has effectively decreased the CO2 channeling with the sweeping efficiency of CO2 ranging from 20% to 80%. Reservoir simulation and material balance analysis indicate that 42.68–60.15% of the stored CO2 has been trapped at the supercritical state, while 24.85–41.8% has been dissolved in the remaining oil with the rest of 15% dissolved in the formation water.

(3) Comparing the current storage amount with the total effective storage capacity, there is still a gap of 6.25 × 104 tons of CO2 for the future storage in the H-59 block. The CO2 sweep efficiency in the H-59 block is speculated to reach a high level under the WAG scheme, therefore, improving the displacement efficiency of CO2 in the reservoir should be considered in the next stage to close the gap.

Acknowledgements This research is supported by the National Major S&T Project (No. 2011ZX05016-005). Permission to publish this paper by Jilin Oilfield Company, PetroChina, is gratefully acknowledged. This research is also partially financed by Qingdao basic research program for young scholars (No. 13-1-4-254-jch), Shandong Natural Science Foundation (No. ZR2013EEQ032) and the Fundamental Research Funds for the Central Universities (No. 15CX05036A).

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