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Key techniques of reservoir engineering and injection–production process for CO2 flooding in China's SINOPEC Shengli Oilfield
Journal of CO2 Utilization 11 (2015) 31–40
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Journal of CO2 Utilization journal homepage: www.elsevier.com/locate/jcou
Key techniques of reservoir engineering and injection–production process for CO2 flooding in China’s SINOPEC Shengli Oilfield Guangzhong Lv a, Qi Li b,*, Shijie Wang a, Xiaying Li b a
The Geology Scientific Institution of SINOPEC Shengli Oilfield, Dongying 257015, China State Key Laboratory of Geomechanics and Geotechnical Engineering, Institute of Rock and Soil Mechanics, Chinese Academy of Sciences, Wuhan 430071, China
b
A R T I C L E I N F O
A B S T R A C T
Article history: Received 31 August 2014 Received in revised form 20 December 2014 Accepted 29 December 2014 Available online 4 February 2015
This paper addresses the geological problems and engineering hot points of the CO2 flooding, such as the big vertical span of the beach-bar sand, the strong reservoir heterogeneity, the distribution of residual oil, and the problem of gas channeling. The core identification, log analysis, seismic interpretation, laboratory test and numerical simulation of reservoir engineering are integrated to investigate the geological characteristics of the reservoir in the demonstration zone of SINOPEC Shengli Oilfield. It demonstrates the reservoir is large but it has thin thickness, low porosity and super-low permeability. Due to some great differences between the beach sand and the bar sand, the oil reservoirs of demonstration zone are divided into 2 sand groups, 8 small layers, and 17 sand bodies in total. Then, a 3D geological model and qualitative evaluation system of safety of vertical faults are built. The optimal evaluation method of CO2 flooding and sequestration is established. According to the engineering optimization of the CO2 flooding, the results of a recommendation scheme indicate that the enhance oil recovery can increase by 6.7%, the total injection volume is expected to reach to 563 104 t, and CO2 sequestration rate is 60.5%. Finally, the multi-level umbrella downhole gas separator is designed, and the high gas–oil ratio (GOR) production string and free kill gas injection string are also successfully developed for the CO2-EOR. ß 2015 Elsevier Ltd. All rights reserved.
Keywords: CO2-EOR CCUS Collaborative optimization Injection/production string SINOPEC Shengli Oilfield
1. Introduction China’s energy consumption structure is dominated by coal [1]. The quantity of CO2 emissions from coal combustion is very huge and growing rapidly [2], contributing to the severe pressure to environmental pollution and economic development [3]. Coalfired power plants are the main sources of CO2 emissions and account for about 50% of total emissions. Therefore, coal-fired plants are the main target for carbon emissions reduction [4,5]. On the other hand, as the main battlefield of China’s future oil and gas exploration and development, the low permeability reservoirs are still under a low-level development due to the limit of reservoir conditions [6,7]. However, CO2, as a superior displacing agent, can greatly improve the recovery of such reservoirs [8]. Thus, CO2 Capture, Utilization and Storage (CCUS) from the coal-fired power plants to the flooding and sequestration is expected to be a new large-scale low-carbon technology for fossil energy cycling [9–12]. The CCUS technology not only has good eco-environmental
* Corresponding author. Tel.: +86 2787198126; fax: +86 2787198967. E-mail address: [email protected] (Q. Li). http://dx.doi.org/10.1016/j.jcou.2014.12.007 2212-9820/ß 2015 Elsevier Ltd. All rights reserved.
benefits, but also increases oil production to ensure national energy supply [13,14]. It will very likely to be the future technology choice to reduce CO2 emissions and ensure the energy security of China [15,16]. A large number of domestic and international research and related applications have shown that injection of CO2 into oil reservoirs can greatly enhance oil recovery [17,18]. Meanwhile, oil reservoirs are good confinement for underground gas storage, therefore they can be used to achieve a long-term geological sequestration of CO2 [19]. The utilization of CO2 as the oil displacing agent cannot only increase the recoverable reserves of crude oil, but also achieve the long-term geological sequestration of CO2. The CCUS technology, i.e. herein carbon dioxide enhanced oil recovery (CO2-EOR), can achieve social benefits for reducing CO2 emissions and at the same time it generates huge economic benefits [20]. Therefore, the CCUS technology is expected to be one of the best pathways for combining huge storage and efficient utilization of CO2 [21,22]. The CCUS technology has been extensively studied in many fields and will be implemented all over the world [23–26]. The technology of CO2 flooding with enhanced oil recovery (EOR) is relatively mature in western developed countries and it has become a major EOR method [27–31]. The petroleum reservoir
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Fig. 1. Location map of SINOPEC Shengli Oilfield (After [37]).
engineering and injection–production process are some key aspects of CO2 flooding and sequestration technology for CO2EOR demonstration projects, and they are also the basis for the construction of CO2-EOR demonstration projects at the same time [32]. Compared to other countries, the reservoir conditions in China are relatively poor, deeply buried, and high-viscosity of crude oil [18,33–35]. Therefore, the existing technologies from western developed countries cannot be fully applied to engineering practice in China. The sequestration conditions, capacity and safety aspects of CO2 flooding process usually need further studies and engineering pilot tests [11,16,21,36]. In this paper, key techniques of reservoir engineering and injection–production process are concluded for CO2 flooding in China’s SINOPEC Shengli Oilfield (Fig. 1) [37]. At first, the geological characteristics of one demonstration zone are introduced for CO2 flooding and sequestration. Then, comprehensive geological studies are carried out to establish a fine three-dimensional geological model of the demonstration zone, and fault sealing of the demonstration zone is also investigated. After that, according to laboratory experiments and numerical simulations, a reservoir engineering scheme of CO2 flooding and sequestration in the demonstration zone is evaluated. Based on the design of key toolset, the research of gas seal performance and in-house experimental simulation, an injection–production string is developed to meet protection of reservoirs and security operations. In addition, economical and reliable anticorrosive materials and corrosion inhibitor are invented to match the injection process of chemical agents. Finally, comprehensive anti-corrosion measures are proposed to prolong handling life of the whole injection system.
Fig. 2. Relationship between oil displacement efficiency and miscibility.
miscible pressure) and oil displacement efficiency can be clearly concluded (Fig. 2). It can be seen that oil displacement efficiency increases with miscible ability. The higher the oil displacement efficiency is, the higher the rates of recovery efficiency and CO2 storage are. On the other hand, the relationship between start-up pressure and reservoir permeability is established by CO2 flooding experiments (Fig. 3). The start-up pressure increases with the permeability decreasing. Combined with the practical injection pressure in SINOPEC Shengli Oilfield, Dongying, China, the lower limit of reservoir permeability for CO2 flooding is 0.5 mD. Based on a survey of CO2 flooding all over the world, the screening criteria of CO2 flooding suited for SINOPEC Shengli Oilfield is set up according
2. Screening criteria of CO2 flooding and sequestration In the field of CO2-EOR, the United States has taken some systematic research in the laboratory experiment and engineering operation [38,39]. However, over 81CO2 injection projects with completed EOR technology have been implemented [40]. The factors affecting gas injection and distribution of CO2 reservoir parameters are analyzed. Taking the value of parameters whose cumulative percentage greater than 95% as a screening line, the screening criteria is determined that viscosity of crude oil for CO2 flooding is less than 6 mPa-s, density of crude oil is less than 0.8762 103 kg/m3, saturation of residual oil is greater than 0.25, and depth of CO2 flooding is more than 1000 m. By analyzing the factors affecting gas injection, the relationship between miscible ability (i.e. formation pressure/minimum
Fig. 3. Relationship between start-up pressure and reservoir permeability.
G. Lv et al. / Journal of CO2 Utilization 11 (2015) 31–40 Table 1 Screening criteria of CO2 flooding and geological sequestration. Criteria
Factor Key factors
Miscibility (–)
1 (miscible flooding) 0.8–1 (near miscible flooding) >0.5
Permeability (mD) Reference factors
Viscosity of oil under reservoir conditions (mPa -s or cP) Density of oil under reservoir conditions (103 kg/m) Saturation of residual oil (%) Single storage coefficient (m3/(km2 m)) Reservoir depth (m) Formation temperature (8C)
<12 <0.8762 >25 >39,000 >2,000 <145
to a trade-off between oil recovery and CO2 geological sequestration (Table 1).
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electrical logging characteristics and logging data is used to analyze a variety of factors, such as seismic, tectonic, sedimentary cycles, sedimentary microfacies, and water cut. The strata of the demonstration zone from top to bottom (Table 2) are the Pingyuan formation of the Quaternary system, the Minghuazhen formation and Guantao formation of the upper Tertiary system, the Dongying formation of the lower Tertiary system, and the 1st member, the 2nd member, the 3rd member, the 4th member of the Shahejie formation and Kongdian formation in Cenozoic erathem [41,42]. On basis of contrast principle, criteria layer and marker bed, contrast mode and contrast procedure, the preliminary results are obtained in segmentation step by step. The construction and production dynamics are combined to rationally analyze the comparative results. Fig. 4 is a schematic diagram of sand bodies in the demonstration zone. Based on the sedimentary cycles, the formation of the demonstration zone is subdivided into 2 sand groups and 8 small layers. 3.2. The fine study of geologic structure
3. Geological features of demonstration zone Based on the aforementioned screening criteria of CO2 flooding and geological sequestration, the low permeability reservoirs of SINOPEC Shengli Oilfield are screened for CO2-EOR. The block Gao 89 is ultimately determined as the demonstration zone [6]. 3.1. The contrast and subdivision of fine stratum According to the principle and theory of sequence stratigraphy, sedimentology and petroleum geology, the isochronous correlation is highlighted and then the correct contrast mode is established by the means of seismicity, logging, and drilling. Controlled by the concept model of sedimentary facies, the combination of standard
According to the tectonic framework and structural style, the demonstration zone for CO2-EOR mainly develops a series of north fault terrace structures toward to northeast. The district is a monoclinic structure which is high in the southeast, while low in the northwest, and the formation dip ranges from 48 to 88. The structure is divided into many terraces by a series of parallel faults running northwest and trending northeast. The largest structural gap can reach to 500–700 m. Except that the terrace in northern part is a closed block, others are toward to the northeast, high in southwest and low in northeast, and 28 for the stratigraphic dip. The feature identification and coherence analysis, with combination of horizontal wells and seismic slicing techniques,
Table 2 Stratigraphic sequences of the demonstration zone. Erathem
System
Formation
Cenozoic
Quaternary Upper tertiary
Pingyuan formation Minghuazhen formation Guantao formation Dongying formation Shahejie formation
Lower tertiary
Member
Subsection
Group
1st 2nd 3rd 4th
Upper of the 4th member
Chunshang sand group Chunxia sand group
Lower of the 4th member Kongdian formation
Fig. 4. Schematic plot of contrast of sand bodies in the demonstration zone.
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Fig. 5. Top structure diagram of the demonstration zone.
sedimentary is mainly formed by mudstone and oil shale. Therefore, the lower 1st and 2nd members are the most developed. The thickness of sand body is more than 30 m. The beach sand displays in a sheet, and the sand dam is in ‘‘beaded’’ set inlaid the beach sand, accounted 17.1% in the total thickness. The reservoir distributes stably and shows the characteristics of the ‘‘large’’ and ‘‘thin’’. The average number of sand bodies drilled in a single well is 16. The average thickness of sand body is 1.5 m. The average thickness of dam sand is 3.5 m, while the average thickness of sand beach is only 1.3 m.
are used to detect and divide the fault system. Finally, 118 breakpoints and 70 combination faults in the vertical direction are determined. According to the distribution of faults in horizontal slices, 34 plane combinations of faults are proposed. There are 17 main faults which displacements are more than 50 m. These faults are primarily synsedimentary faults which control the overall framework of the demonstration zone (Fig. 5). 3.3. Sedimentary characteristics of reservoir The sedimentary period of the main sand formation in the demonstration zone is in the early stage of fault depression of lakes and basins. The Luxi uplift (the uplift in western Shandong province, China) in south becomes an extensive denudation area, providing the abundant terrigenous clastic for lakes and basins. At this time, the water body in the lake is wide but not deep, under the marina shallow lake–deep lake environment, which is conducive for the development of beach bar sandstone. Provenance of debris, which came from the south and west, deposited in the bay mouth and dam slope belt, and formed the beach dam after the transformation of the sea and lake shore flow. The distribution of beach dam reservoir is affected by the tectonic movement, climate change, source supply, palaeogeomorphology and water dynamic conditions, etc. The key factor which controlled the sedimentary sand body is the variation of sedimentary environment caused by the change of base level. The sedimentary characteristics vary from the location of the 4th member of the Shahejie formation during cycling in the mid-term base level. The surface of T7 is the transformation space changed rapidly from the minimum capacity of space to the maximum capacity of space. Under this surface, the sand body is dominant and sand dam is the most developed. Above the surface, the water body becomes darker, and the provenance retreats. The
3.4. The physical property of reservoir The buried depth of the reservoir is 2700–3200 m in the demonstration zone. The rock is dense and has poor physical properties. According to the conventional core analysis data of 8 wells in the demonstration zone, the average porosity of the reservoir is 13.1%, the average permeability is 2.1 103 mm2, and the average carbonate content is 19.99%, indicating the demonstration zone belongs to a low porosity and super-low permeability reservoir (Table 3). Through the statistics data of routine core analysis of beach sand and sand dam, the physical properties of beach sand and sand dam are different from each other. There are 66 samples of dam sand with the average porosity of 14.7% and the average permeability of 4.92 103 mm2. The distribution of permeability is scattered, while the samples with the permeability greater than 5 103 mm2 account for 40.8% of the dam sand samples. There are 100 beach sand samples with the average porosity of 9.18% and the average permeability of 0.29 103 mm2. The samples with the permeability less than 1 103 mm2 account for 96.9% of all the beach sand samples, indicating the physical property of dam sand is better than the beach sand, and the dam sand has stronger heterogeneity.
Table 3 Statistics of reservoir properties of demonstration zone. Sand group
S41 S42 Total
Permeability (103 mm2)
Porosity (%)
Carbonate (%)
Num
Max
Min
Avg
Num
Max
Min
Avg
Num
Avg
81 78 159
17.4 20.8 20.8
9 9.2 9
12.4 13.9 13.1
92 89 181
4.89 14.87 14.87
0.1 0.105 0.1
0.67 4.08 2.1
44 76 120
19.13 20.5 19.99
Note: Num, number; Max, maximum; Min, minimum; Avg, average.
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Fig. 6. Plot of three-dimensional (3D) geological model of the demonstration zone.
3.5. Three-dimensional geological model On the basis of comprehensive analysis of drilling data, geological data, logging data and seismic data, the research is carried out about the fracture systems, reservoir characteristics, the secondary logging interpretation of reservoir, the distribution of water and oil. In particular, the appropriate models are investigated through the contrast method about the fine formation to check deterministic model and stochastic model. Meanwhile, compared with the conceptual model, an appropriate three-dimensional geological model (Fig. 6) is established by repeated verification, improvement and optimization based on the previous models. The gridding in the plane is 30 m 30 m and the model extends until to a single sand segments longitudinally. The thickness of each grid is 1 m, and the total number of nodes in the gridding is 3,346,112. 4. Investigation of fault sealing potential There are two sets of stable argillaceous rock formations and two sets of relatively stable argillaceous rock formations on the vertical horizon in the demonstration zone. The two sets of the stable argillaceous rock formations are in the upper 4th member and in the lower 3rd member of the Shahejie formation, respectively. The two sets of relatively stable argillaceous rock formations are in the upper part of the Dongying formation and Guantao formation, respectively. The argillaceous rock in the upper 4th member and in the lower 3rd member of the Shahejie formation directly covered on the upper 4th member before. The distribution of caprock is extraordinary stable, and the large thickness ranges from 460 m to 580 m. Therefore, the risk of CO2 storage mainly comes from vertical sealing of faults. Fault sealing property refers to the ability of fault plane or fault belt to prevent fluid percolation [43]. The factors affected the fault sealing potential have the following main aspects: (1) fault features, including fault geometry, fault depth, faulting space, configuration relationship between two walls of fault, mechanical property of fault, fault extension direction and relationship with the regional stress field, etc. (2) fault plane, for example, the daub property of mudstone in fault plane; (3) characteristics of fault
zone, such as density of fault rock, filler lithology of fault zone, cementation and diagenesis of fault zone, etc. 4.1. Vertical penetration of fault The seismic research demonstrates that there are large differences of vertical penetration among the faults in the demonstration zone (Fig. 5). The two faults, F1 and F2, penetrated into the Guantao formation. If CO2 leaks out, it may cause damage to the local environment [15,44]. The faults penetrated into the upper 3rd member are F4, F5, F6 and F7. The faults penetrated into the lower 3rd member are F3, F8, F9, F13, F14, F17 and F21. The rest 25 faults did not penetrate into the lower 3rd member (Fig. 5). According to the general theory about penetration formation and fault activity time, the higher the penetration is, the longer the activity time of fault is and the worse the corresponding vertical sealing potential of fault is. Viewed from this perspective, most activities of faults in the demonstration zone stopped before the sedimentary of the 2nd member. The earlier the activity stops, the better the longitudinal sealing property is. The stop time of F1 and F2 is in the late time of the Guantao formation deposition, and the longitudinal sealing property is relatively poor [41]. 4.2. The relationship between fault vertical extension and regional stable mud The integrity of the regional caprock is one of the important indicator to evaluate the sealing ability of caprock [45,46]. Generally, intact caprock has the least damage and stronger sealing ability. When caprock is cut by faults, its vertical sealing potential will be affected in different degrees [47]. The configuration relations between faults and two sets of regional caprock can be divided into three modes in the demonstration zone (Fig. 7). Mode 1: the fault does not penetrate into the lower 3rd member. The caprock is above target stratum. The rocks in the upper 4th member and the lower 3rd member of the Shahejie formation have not been completely destroyed. There are still intact sections with certain thickness on the top and vertical sealing ability of fault is still very excellent. The CO2 cannot leak out through such a fault.
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Fig. 7. Three different modes of faults penetrating into regional caprock.
This pattern is the most developed mode in the demonstration zone. 25 faults belong to this pattern, accounting for 66% of the total number of faults. Mode 2: the fault penetrates into the lower 3rd member, but it does not penetrate into the 1st member. The rocks in the upper 4th member and the lower 3rd member are destroyed and its vertical sealing ability becomes weak. However, the overlying argillaceous rocks in the 1st member and upper of the 2nd member have not been destroyed, and the vertical sealing ability is still strong. The vertical sealing ability of fault under such a mode is good enough to reduce the leakage of CO2 through the fault. The mode 2 fault in the demonstration zone is relatively developed, including F3, F4 and F5, F6 and F7, F8, F9, F13, F14, F17 and F21 (Fig. 5), accounting for 30% of the total number of faults. Mode 3: the fault penetrates into the 1st member. The two sets of stable argillaceous rock strata are destroyed and the sealing ability decreases in different degrees compared to the first two modes. The CO2 could theoretically leak into the Guantao formation through the fault. 4.3. The relationship between fault displacement and caprock thickness The vertical sealing ability of fault which does not penetrate into the lower 3rd member is excellent. The CO2 would not leak into the sand above the lower 3rd member. However, it is still needed to investigate whether the CO2 will leak into the sand above the lower 3rd member or even to the surface when the fault do not penetrate the lower 3rd member. Therefore, the research is carried out about the relationship between fault displacement and caprock thickness in the upper 4th member and the lower 3rd member. The argillaceous rock layers with the thinnest thickness is 460 m in the upper 4th member and the lower 3rd member in the demonstration zone. The largest fault is F1 with the maximum vertical fault space of 350 m, and the mudstone docking thickness
of two fault wells is more than 110 m. The mudstone docking section, after the stop of activities, will glue into a mudstone adhesive section under the effect of overburden pressure and high temperature, so it is beneficial for the storage of CO2. To sum up, the vertical sealing ability of fault in the demonstration zone is strong and the possibility for CO2 leakage is tiny. 5. Reservoir engineering optimization 5.1. Optimization methodology The traditional design of CO2-EOR seeks the minimal amount of injected CO2 and the maximum recovery of oil [14]. It can be represented by the formula as following: [ DCO2 EOR ¼ maxðNp Þ minðV CO2 Þ (1) where V CO2 is the volume of CO2 injection (m3). Np is the cumulative oil production (m3), DCO2 -EOR is the design object of CO2-EOR (m3). Obviously, the traditional design scheme for CO2 sequestration is inadequate. Since the main goal is to get a higher recovery and to sequester much more CO2 at the same time. The optimal design uses a dimensionless objective function to balance recovery and utilization of oil reservoir as following: V CO2 Np þ ð1 v1 Þ (2) DCCUSðCO2 -EORÞ ¼ max v1 OOIP PV where v1 is the weight coefficient, which ranges from 0 to 1. OOIP is the geological reserves (m3). PV is the pore volume (m3). DCCUSðCO2 -EORÞ is the dimensionless design object of CO2-EOR. Selecting the appropriate weighting factor is very important. If the goal is the maximum recovery, then v1 = 1; if the goal is the maximize sequestration of CO2, then v1 = 0. In this paper, an equal weighting factor (v1 = 0.5) is applied, indicating the equal
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importance of oil recovery and CO2 sequestration. In practice, the weight coefficient is selected according to the proceeds of oil production and CO2 sequestration. 5.2. Optimization of CO2 flooding and sequestration in demonstration zone According to numerical simulation methods considered characteristics of CO2 miscible flooding flow and related research
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achievements [7,17,18,48,49], main parameters are optimized on well spacing, pressure maintenance, injection pattern, injection rate and injection volume, etc. The optimization techniques of CO2 flooding and sequestration are developed for reservoir engineering design, and the limits of the CO2 flooding technology are depicted in Fig. 8. Fig. 8a is the histogram of recovery ratio in different displacement ways. From this figure, it can be seen that the WAG (Water Alternating Gas) injection pattern is better than that
Fig. 8. Technology optimization of CO2-EOR in the demonstration zone: (a) histogram of recovery ratio in different displacement ways; (b) relationship between DCCUSðCO2 -EORÞ and formation pressure; (c) correlation between DCCUSðCO2 -EORÞ and well patterns; (d) coupling between DCCUSðCO2 -EORÞ and well spacing; (e) Relationship between DCCUSðCO2 -EORÞ and injection rate; (f) Variation of ratio of oil to CO2 with injection volume of CO2.
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of continuous gas drive, and gas drive is straightly better than that of both water flooding and elastic displacement. Considering injection situation of the field, the demonstration zone adopts a continuous gas drive. Fig. 8b plots the relationship between DCCUSðCO2 -EORÞ and formation pressure. The objective function increases with the increased formation pressure. The objective function increases slowly when the formation pressure reaches to 30 MPa. So, this value is taken as the critical value in the demonstration zone. Fig. 8c depicts the correlation between DCCUSðCO2 -EORÞ and well patterns. The numerical simulation results show that the objective function gives the largest value when the inverted 9-spot well pattern is adopted. Fig. 8d plots the coupling between DCCUSðCO2 -EORÞ and well spacing. The objective function decreases with the increased well spacing. Due to low permeability in the demonstration zone, it is difficult to establish an effective displacement system in a large well spacing. The objective function produces the largest value when the well spacing is 350 m. Therefore, the spacing of 350 m is decided to be implemented in the demonstration zone. Fig. 8e plots the relationship between DCCUSðCO2 -EORÞ and injection rate. The objective function increases at first and then decreases with the increase of gas injection velocity. At a low gas injection rate, the injection gas volume is less than the output, contributing to the drop of the pressure and the decrease of the objective function. At a high gas injection rate, it is easy for gas channeling and reducing the recovery efficiency and storage rates, contributing to the decrease of the objective function. The optimal rate of gas injection is 20 t/d in the demonstration zone. Fig. 8f plots the curve of ratio of oil to CO2 with injection volume of CO2. Oil exchange ratio increases firstly and then decreases with the increased gas injection. It is caused by gas breakthrough in the late period. Oil exchange ratio is reduced when CO2 utilization ratio decreases. The biggest injection volume is 0.33 PV in the demonstration zone due to the economic factor. In a conclusion, the best scheme for CO2 flooding and sequestration in the demonstration zone is the 9-spot well pattern, 350 m well spacing, continuous injection, 30 MPa for the formation pressure, 20 t/d for the injection rate, 0.33 PV for the maximum injection volume. 6.7% is the forecast for enhanced oil recovery, 5.63 106 t for total injection volume of CO2, and 60.5% for the CO2 sequestration rate. 6. Injection–production process of CO2 flooding
Fig. 9. Structure diagram of gas injection string.
backwashing. When the annulus fluid which contained corrosion inhibitors is injected into the oil annulus, the anti-washing liquid through the backwash valve directly goes into the oil tubing and finally it goes back to the well-bore through the oil tubing to achieve the purpose of protection of the reservoir; (3) the use of hand-split structure to ensure the replacement of the upper gasinjection string without handling the lower part of the column; (4) the application of multifunction injection valve and disk valve can cancel the kill process on the upper column.
6.1. The safe killing free gas-injection string of CO2 flooding 6.2. Development of production string with high gas-to-oil ratio When gas injection wells transform to production wells or for other reasons the strings need to be replaced, the high expansion of CO2 contributes to a high risk during the construction process. It is urgent to design a safe killing free gas-injection string (Fig. 9). The function of backwash valve in the gas injection string is to connect the oil string and close the annulus during the injection process, and connect the annulus to replace the protective liquid during backwashing. The hydraulic anchor is used to anchor the tubular column. The sealing plug is composed by plug and ‘‘O’’-ring. Combined with the tieback cylinder, the sealing plug connects hand column and column tube, and it plays a key role in sealing. The principle of disk valve is that it can flip to an angle to connect the internal part when the disk pulled by an external force at the upper part. The disk will return to the original state by the spring force to seal the gas of borehole when the external force disappears. There are four features of the safe killing free gas-injection string of CO2 flooding: (1) anchor-type string structure can prevent the creep of column to ensure the normal operation of gas injection. It can protect the upper casing of the throw hand column at the same time; (2) it can replace the protective fluid during
To obtain a sound gas/liquid separation effect, the velocity of downward gas flow in the anchored section must be less than the floating speed of the bubbles in the liquid. The multistage gas anchor adopts an inverted umbrella structure. The gas/liquid mixture can go into the central tube only through the central bore in the bottom of the umbrella. Each umbrella structure is equivalent to a small sedimentation separator. It can realize degassing by utilization of density difference between gas and liquid, and control the descending speed of liquid by changing the number of umbrellas, and ensure the sufficient time for gas to separate from liquid, improving the gas/liquid separation efficiency and the pump efficiency. Considering the diameter of well-bores, if the outer diameter of separation chamber is 96 mm, and inner diameter is 94 mm, and each separation chamber volume is 1.47 104 m3, and a suction stroke volume is 1.06 102 m3, on the assumption that the separation chamber is 2 times the volume of pump stroke, the separation chamber number is 80 mm. With the extension of production, the production wells will appear many problems such as gas channelings, scaling and
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Fig. 10. Structure diagram of production string.
corrosion. The production string is designed with functions of high gas-to-oil ratios, losing hands and turn-off for the convenient of the replacement of strings in the late stage (Fig. 10). The specialized column has four characteristics: (1) equipped with the corrosion pump and the supporting tools in the downhole with anticorrosion performance; (2) the coupons can monitor the corrosive conditions of different materials in the downhole environment; (3) the measuring device of stationary pressure can monitor the gas drive effect in real time; (4) the gas anchors can reduce the oil-togas ratio at the pump inlet, increasing the pump efficiency. 7. Conclusions (1) A series of research is carried out in this paper about the fine stratigraphic correlation, structural interpretation, analysis of reservoir characteristics and distribution of oil and water in the demonstration zone of SINOPEC Shengli Oilfield, Dongying, China, and a 3D geological model is established as the foundation for the optimization of reservoir engineering design for CO2-EOR. (2) The fault sealing analysis is conducted in the demonstration zone. The results illustrate that the vertical sealing ability of faults is strong, and the possibility of CO2 leakage is weak in the vertical direction along faults. Therefore, the safety of subsurface sequestration of CO2 is ensured by the fault sealing potential. (3) Optimization methodology of CO2 flooding and sequestration is established by laboratory experiments, numerical modeling and reservoir engineering techniques. The numerical simulation results indicate that the enhanced oil recovery increased by 6.7%, and the total injection volume of CO2 is expected to reach to 5.63 106 t, and the sequestration rate of CO2 is to be approached 60.5%. (4) The safe killing free gas-injection string and oil-production string are developed with a high gas-to-liquid ratio.
Acknowledgements Funding support of large-scale coal-fired power plant flue gas CO2 capture, flooding and sequestration technology development demonstration (2012BAC24B000 and 2012BAC24B05) under
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Contents lists available at ScienceDirect
Journal of CO2 Utilization journal homepage: www.elsevier.com/locate/jcou
Key techniques of reservoir engineering and injection–production process for CO2 flooding in China’s SINOPEC Shengli Oilfield Guangzhong Lv a, Qi Li b,*, Shijie Wang a, Xiaying Li b a
The Geology Scientific Institution of SINOPEC Shengli Oilfield, Dongying 257015, China State Key Laboratory of Geomechanics and Geotechnical Engineering, Institute of Rock and Soil Mechanics, Chinese Academy of Sciences, Wuhan 430071, China
b
A R T I C L E I N F O
A B S T R A C T
Article history: Received 31 August 2014 Received in revised form 20 December 2014 Accepted 29 December 2014 Available online 4 February 2015
This paper addresses the geological problems and engineering hot points of the CO2 flooding, such as the big vertical span of the beach-bar sand, the strong reservoir heterogeneity, the distribution of residual oil, and the problem of gas channeling. The core identification, log analysis, seismic interpretation, laboratory test and numerical simulation of reservoir engineering are integrated to investigate the geological characteristics of the reservoir in the demonstration zone of SINOPEC Shengli Oilfield. It demonstrates the reservoir is large but it has thin thickness, low porosity and super-low permeability. Due to some great differences between the beach sand and the bar sand, the oil reservoirs of demonstration zone are divided into 2 sand groups, 8 small layers, and 17 sand bodies in total. Then, a 3D geological model and qualitative evaluation system of safety of vertical faults are built. The optimal evaluation method of CO2 flooding and sequestration is established. According to the engineering optimization of the CO2 flooding, the results of a recommendation scheme indicate that the enhance oil recovery can increase by 6.7%, the total injection volume is expected to reach to 563 104 t, and CO2 sequestration rate is 60.5%. Finally, the multi-level umbrella downhole gas separator is designed, and the high gas–oil ratio (GOR) production string and free kill gas injection string are also successfully developed for the CO2-EOR. ß 2015 Elsevier Ltd. All rights reserved.
Keywords: CO2-EOR CCUS Collaborative optimization Injection/production string SINOPEC Shengli Oilfield
1. Introduction China’s energy consumption structure is dominated by coal [1]. The quantity of CO2 emissions from coal combustion is very huge and growing rapidly [2], contributing to the severe pressure to environmental pollution and economic development [3]. Coalfired power plants are the main sources of CO2 emissions and account for about 50% of total emissions. Therefore, coal-fired plants are the main target for carbon emissions reduction [4,5]. On the other hand, as the main battlefield of China’s future oil and gas exploration and development, the low permeability reservoirs are still under a low-level development due to the limit of reservoir conditions [6,7]. However, CO2, as a superior displacing agent, can greatly improve the recovery of such reservoirs [8]. Thus, CO2 Capture, Utilization and Storage (CCUS) from the coal-fired power plants to the flooding and sequestration is expected to be a new large-scale low-carbon technology for fossil energy cycling [9–12]. The CCUS technology not only has good eco-environmental
* Corresponding author. Tel.: +86 2787198126; fax: +86 2787198967. E-mail address: [email protected] (Q. Li). http://dx.doi.org/10.1016/j.jcou.2014.12.007 2212-9820/ß 2015 Elsevier Ltd. All rights reserved.
benefits, but also increases oil production to ensure national energy supply [13,14]. It will very likely to be the future technology choice to reduce CO2 emissions and ensure the energy security of China [15,16]. A large number of domestic and international research and related applications have shown that injection of CO2 into oil reservoirs can greatly enhance oil recovery [17,18]. Meanwhile, oil reservoirs are good confinement for underground gas storage, therefore they can be used to achieve a long-term geological sequestration of CO2 [19]. The utilization of CO2 as the oil displacing agent cannot only increase the recoverable reserves of crude oil, but also achieve the long-term geological sequestration of CO2. The CCUS technology, i.e. herein carbon dioxide enhanced oil recovery (CO2-EOR), can achieve social benefits for reducing CO2 emissions and at the same time it generates huge economic benefits [20]. Therefore, the CCUS technology is expected to be one of the best pathways for combining huge storage and efficient utilization of CO2 [21,22]. The CCUS technology has been extensively studied in many fields and will be implemented all over the world [23–26]. The technology of CO2 flooding with enhanced oil recovery (EOR) is relatively mature in western developed countries and it has become a major EOR method [27–31]. The petroleum reservoir
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Fig. 1. Location map of SINOPEC Shengli Oilfield (After [37]).
engineering and injection–production process are some key aspects of CO2 flooding and sequestration technology for CO2EOR demonstration projects, and they are also the basis for the construction of CO2-EOR demonstration projects at the same time [32]. Compared to other countries, the reservoir conditions in China are relatively poor, deeply buried, and high-viscosity of crude oil [18,33–35]. Therefore, the existing technologies from western developed countries cannot be fully applied to engineering practice in China. The sequestration conditions, capacity and safety aspects of CO2 flooding process usually need further studies and engineering pilot tests [11,16,21,36]. In this paper, key techniques of reservoir engineering and injection–production process are concluded for CO2 flooding in China’s SINOPEC Shengli Oilfield (Fig. 1) [37]. At first, the geological characteristics of one demonstration zone are introduced for CO2 flooding and sequestration. Then, comprehensive geological studies are carried out to establish a fine three-dimensional geological model of the demonstration zone, and fault sealing of the demonstration zone is also investigated. After that, according to laboratory experiments and numerical simulations, a reservoir engineering scheme of CO2 flooding and sequestration in the demonstration zone is evaluated. Based on the design of key toolset, the research of gas seal performance and in-house experimental simulation, an injection–production string is developed to meet protection of reservoirs and security operations. In addition, economical and reliable anticorrosive materials and corrosion inhibitor are invented to match the injection process of chemical agents. Finally, comprehensive anti-corrosion measures are proposed to prolong handling life of the whole injection system.
Fig. 2. Relationship between oil displacement efficiency and miscibility.
miscible pressure) and oil displacement efficiency can be clearly concluded (Fig. 2). It can be seen that oil displacement efficiency increases with miscible ability. The higher the oil displacement efficiency is, the higher the rates of recovery efficiency and CO2 storage are. On the other hand, the relationship between start-up pressure and reservoir permeability is established by CO2 flooding experiments (Fig. 3). The start-up pressure increases with the permeability decreasing. Combined with the practical injection pressure in SINOPEC Shengli Oilfield, Dongying, China, the lower limit of reservoir permeability for CO2 flooding is 0.5 mD. Based on a survey of CO2 flooding all over the world, the screening criteria of CO2 flooding suited for SINOPEC Shengli Oilfield is set up according
2. Screening criteria of CO2 flooding and sequestration In the field of CO2-EOR, the United States has taken some systematic research in the laboratory experiment and engineering operation [38,39]. However, over 81CO2 injection projects with completed EOR technology have been implemented [40]. The factors affecting gas injection and distribution of CO2 reservoir parameters are analyzed. Taking the value of parameters whose cumulative percentage greater than 95% as a screening line, the screening criteria is determined that viscosity of crude oil for CO2 flooding is less than 6 mPa-s, density of crude oil is less than 0.8762 103 kg/m3, saturation of residual oil is greater than 0.25, and depth of CO2 flooding is more than 1000 m. By analyzing the factors affecting gas injection, the relationship between miscible ability (i.e. formation pressure/minimum
Fig. 3. Relationship between start-up pressure and reservoir permeability.
G. Lv et al. / Journal of CO2 Utilization 11 (2015) 31–40 Table 1 Screening criteria of CO2 flooding and geological sequestration. Criteria
Factor Key factors
Miscibility (–)
1 (miscible flooding) 0.8–1 (near miscible flooding) >0.5
Permeability (mD) Reference factors
Viscosity of oil under reservoir conditions (mPa -s or cP) Density of oil under reservoir conditions (103 kg/m) Saturation of residual oil (%) Single storage coefficient (m3/(km2 m)) Reservoir depth (m) Formation temperature (8C)
<12 <0.8762 >25 >39,000 >2,000 <145
to a trade-off between oil recovery and CO2 geological sequestration (Table 1).
33
electrical logging characteristics and logging data is used to analyze a variety of factors, such as seismic, tectonic, sedimentary cycles, sedimentary microfacies, and water cut. The strata of the demonstration zone from top to bottom (Table 2) are the Pingyuan formation of the Quaternary system, the Minghuazhen formation and Guantao formation of the upper Tertiary system, the Dongying formation of the lower Tertiary system, and the 1st member, the 2nd member, the 3rd member, the 4th member of the Shahejie formation and Kongdian formation in Cenozoic erathem [41,42]. On basis of contrast principle, criteria layer and marker bed, contrast mode and contrast procedure, the preliminary results are obtained in segmentation step by step. The construction and production dynamics are combined to rationally analyze the comparative results. Fig. 4 is a schematic diagram of sand bodies in the demonstration zone. Based on the sedimentary cycles, the formation of the demonstration zone is subdivided into 2 sand groups and 8 small layers. 3.2. The fine study of geologic structure
3. Geological features of demonstration zone Based on the aforementioned screening criteria of CO2 flooding and geological sequestration, the low permeability reservoirs of SINOPEC Shengli Oilfield are screened for CO2-EOR. The block Gao 89 is ultimately determined as the demonstration zone [6]. 3.1. The contrast and subdivision of fine stratum According to the principle and theory of sequence stratigraphy, sedimentology and petroleum geology, the isochronous correlation is highlighted and then the correct contrast mode is established by the means of seismicity, logging, and drilling. Controlled by the concept model of sedimentary facies, the combination of standard
According to the tectonic framework and structural style, the demonstration zone for CO2-EOR mainly develops a series of north fault terrace structures toward to northeast. The district is a monoclinic structure which is high in the southeast, while low in the northwest, and the formation dip ranges from 48 to 88. The structure is divided into many terraces by a series of parallel faults running northwest and trending northeast. The largest structural gap can reach to 500–700 m. Except that the terrace in northern part is a closed block, others are toward to the northeast, high in southwest and low in northeast, and 28 for the stratigraphic dip. The feature identification and coherence analysis, with combination of horizontal wells and seismic slicing techniques,
Table 2 Stratigraphic sequences of the demonstration zone. Erathem
System
Formation
Cenozoic
Quaternary Upper tertiary
Pingyuan formation Minghuazhen formation Guantao formation Dongying formation Shahejie formation
Lower tertiary
Member
Subsection
Group
1st 2nd 3rd 4th
Upper of the 4th member
Chunshang sand group Chunxia sand group
Lower of the 4th member Kongdian formation
Fig. 4. Schematic plot of contrast of sand bodies in the demonstration zone.
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Fig. 5. Top structure diagram of the demonstration zone.
sedimentary is mainly formed by mudstone and oil shale. Therefore, the lower 1st and 2nd members are the most developed. The thickness of sand body is more than 30 m. The beach sand displays in a sheet, and the sand dam is in ‘‘beaded’’ set inlaid the beach sand, accounted 17.1% in the total thickness. The reservoir distributes stably and shows the characteristics of the ‘‘large’’ and ‘‘thin’’. The average number of sand bodies drilled in a single well is 16. The average thickness of sand body is 1.5 m. The average thickness of dam sand is 3.5 m, while the average thickness of sand beach is only 1.3 m.
are used to detect and divide the fault system. Finally, 118 breakpoints and 70 combination faults in the vertical direction are determined. According to the distribution of faults in horizontal slices, 34 plane combinations of faults are proposed. There are 17 main faults which displacements are more than 50 m. These faults are primarily synsedimentary faults which control the overall framework of the demonstration zone (Fig. 5). 3.3. Sedimentary characteristics of reservoir The sedimentary period of the main sand formation in the demonstration zone is in the early stage of fault depression of lakes and basins. The Luxi uplift (the uplift in western Shandong province, China) in south becomes an extensive denudation area, providing the abundant terrigenous clastic for lakes and basins. At this time, the water body in the lake is wide but not deep, under the marina shallow lake–deep lake environment, which is conducive for the development of beach bar sandstone. Provenance of debris, which came from the south and west, deposited in the bay mouth and dam slope belt, and formed the beach dam after the transformation of the sea and lake shore flow. The distribution of beach dam reservoir is affected by the tectonic movement, climate change, source supply, palaeogeomorphology and water dynamic conditions, etc. The key factor which controlled the sedimentary sand body is the variation of sedimentary environment caused by the change of base level. The sedimentary characteristics vary from the location of the 4th member of the Shahejie formation during cycling in the mid-term base level. The surface of T7 is the transformation space changed rapidly from the minimum capacity of space to the maximum capacity of space. Under this surface, the sand body is dominant and sand dam is the most developed. Above the surface, the water body becomes darker, and the provenance retreats. The
3.4. The physical property of reservoir The buried depth of the reservoir is 2700–3200 m in the demonstration zone. The rock is dense and has poor physical properties. According to the conventional core analysis data of 8 wells in the demonstration zone, the average porosity of the reservoir is 13.1%, the average permeability is 2.1 103 mm2, and the average carbonate content is 19.99%, indicating the demonstration zone belongs to a low porosity and super-low permeability reservoir (Table 3). Through the statistics data of routine core analysis of beach sand and sand dam, the physical properties of beach sand and sand dam are different from each other. There are 66 samples of dam sand with the average porosity of 14.7% and the average permeability of 4.92 103 mm2. The distribution of permeability is scattered, while the samples with the permeability greater than 5 103 mm2 account for 40.8% of the dam sand samples. There are 100 beach sand samples with the average porosity of 9.18% and the average permeability of 0.29 103 mm2. The samples with the permeability less than 1 103 mm2 account for 96.9% of all the beach sand samples, indicating the physical property of dam sand is better than the beach sand, and the dam sand has stronger heterogeneity.
Table 3 Statistics of reservoir properties of demonstration zone. Sand group
S41 S42 Total
Permeability (103 mm2)
Porosity (%)
Carbonate (%)
Num
Max
Min
Avg
Num
Max
Min
Avg
Num
Avg
81 78 159
17.4 20.8 20.8
9 9.2 9
12.4 13.9 13.1
92 89 181
4.89 14.87 14.87
0.1 0.105 0.1
0.67 4.08 2.1
44 76 120
19.13 20.5 19.99
Note: Num, number; Max, maximum; Min, minimum; Avg, average.
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Fig. 6. Plot of three-dimensional (3D) geological model of the demonstration zone.
3.5. Three-dimensional geological model On the basis of comprehensive analysis of drilling data, geological data, logging data and seismic data, the research is carried out about the fracture systems, reservoir characteristics, the secondary logging interpretation of reservoir, the distribution of water and oil. In particular, the appropriate models are investigated through the contrast method about the fine formation to check deterministic model and stochastic model. Meanwhile, compared with the conceptual model, an appropriate three-dimensional geological model (Fig. 6) is established by repeated verification, improvement and optimization based on the previous models. The gridding in the plane is 30 m 30 m and the model extends until to a single sand segments longitudinally. The thickness of each grid is 1 m, and the total number of nodes in the gridding is 3,346,112. 4. Investigation of fault sealing potential There are two sets of stable argillaceous rock formations and two sets of relatively stable argillaceous rock formations on the vertical horizon in the demonstration zone. The two sets of the stable argillaceous rock formations are in the upper 4th member and in the lower 3rd member of the Shahejie formation, respectively. The two sets of relatively stable argillaceous rock formations are in the upper part of the Dongying formation and Guantao formation, respectively. The argillaceous rock in the upper 4th member and in the lower 3rd member of the Shahejie formation directly covered on the upper 4th member before. The distribution of caprock is extraordinary stable, and the large thickness ranges from 460 m to 580 m. Therefore, the risk of CO2 storage mainly comes from vertical sealing of faults. Fault sealing property refers to the ability of fault plane or fault belt to prevent fluid percolation [43]. The factors affected the fault sealing potential have the following main aspects: (1) fault features, including fault geometry, fault depth, faulting space, configuration relationship between two walls of fault, mechanical property of fault, fault extension direction and relationship with the regional stress field, etc. (2) fault plane, for example, the daub property of mudstone in fault plane; (3) characteristics of fault
zone, such as density of fault rock, filler lithology of fault zone, cementation and diagenesis of fault zone, etc. 4.1. Vertical penetration of fault The seismic research demonstrates that there are large differences of vertical penetration among the faults in the demonstration zone (Fig. 5). The two faults, F1 and F2, penetrated into the Guantao formation. If CO2 leaks out, it may cause damage to the local environment [15,44]. The faults penetrated into the upper 3rd member are F4, F5, F6 and F7. The faults penetrated into the lower 3rd member are F3, F8, F9, F13, F14, F17 and F21. The rest 25 faults did not penetrate into the lower 3rd member (Fig. 5). According to the general theory about penetration formation and fault activity time, the higher the penetration is, the longer the activity time of fault is and the worse the corresponding vertical sealing potential of fault is. Viewed from this perspective, most activities of faults in the demonstration zone stopped before the sedimentary of the 2nd member. The earlier the activity stops, the better the longitudinal sealing property is. The stop time of F1 and F2 is in the late time of the Guantao formation deposition, and the longitudinal sealing property is relatively poor [41]. 4.2. The relationship between fault vertical extension and regional stable mud The integrity of the regional caprock is one of the important indicator to evaluate the sealing ability of caprock [45,46]. Generally, intact caprock has the least damage and stronger sealing ability. When caprock is cut by faults, its vertical sealing potential will be affected in different degrees [47]. The configuration relations between faults and two sets of regional caprock can be divided into three modes in the demonstration zone (Fig. 7). Mode 1: the fault does not penetrate into the lower 3rd member. The caprock is above target stratum. The rocks in the upper 4th member and the lower 3rd member of the Shahejie formation have not been completely destroyed. There are still intact sections with certain thickness on the top and vertical sealing ability of fault is still very excellent. The CO2 cannot leak out through such a fault.
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Fig. 7. Three different modes of faults penetrating into regional caprock.
This pattern is the most developed mode in the demonstration zone. 25 faults belong to this pattern, accounting for 66% of the total number of faults. Mode 2: the fault penetrates into the lower 3rd member, but it does not penetrate into the 1st member. The rocks in the upper 4th member and the lower 3rd member are destroyed and its vertical sealing ability becomes weak. However, the overlying argillaceous rocks in the 1st member and upper of the 2nd member have not been destroyed, and the vertical sealing ability is still strong. The vertical sealing ability of fault under such a mode is good enough to reduce the leakage of CO2 through the fault. The mode 2 fault in the demonstration zone is relatively developed, including F3, F4 and F5, F6 and F7, F8, F9, F13, F14, F17 and F21 (Fig. 5), accounting for 30% of the total number of faults. Mode 3: the fault penetrates into the 1st member. The two sets of stable argillaceous rock strata are destroyed and the sealing ability decreases in different degrees compared to the first two modes. The CO2 could theoretically leak into the Guantao formation through the fault. 4.3. The relationship between fault displacement and caprock thickness The vertical sealing ability of fault which does not penetrate into the lower 3rd member is excellent. The CO2 would not leak into the sand above the lower 3rd member. However, it is still needed to investigate whether the CO2 will leak into the sand above the lower 3rd member or even to the surface when the fault do not penetrate the lower 3rd member. Therefore, the research is carried out about the relationship between fault displacement and caprock thickness in the upper 4th member and the lower 3rd member. The argillaceous rock layers with the thinnest thickness is 460 m in the upper 4th member and the lower 3rd member in the demonstration zone. The largest fault is F1 with the maximum vertical fault space of 350 m, and the mudstone docking thickness
of two fault wells is more than 110 m. The mudstone docking section, after the stop of activities, will glue into a mudstone adhesive section under the effect of overburden pressure and high temperature, so it is beneficial for the storage of CO2. To sum up, the vertical sealing ability of fault in the demonstration zone is strong and the possibility for CO2 leakage is tiny. 5. Reservoir engineering optimization 5.1. Optimization methodology The traditional design of CO2-EOR seeks the minimal amount of injected CO2 and the maximum recovery of oil [14]. It can be represented by the formula as following: [ DCO2 EOR ¼ maxðNp Þ minðV CO2 Þ (1) where V CO2 is the volume of CO2 injection (m3). Np is the cumulative oil production (m3), DCO2 -EOR is the design object of CO2-EOR (m3). Obviously, the traditional design scheme for CO2 sequestration is inadequate. Since the main goal is to get a higher recovery and to sequester much more CO2 at the same time. The optimal design uses a dimensionless objective function to balance recovery and utilization of oil reservoir as following: V CO2 Np þ ð1 v1 Þ (2) DCCUSðCO2 -EORÞ ¼ max v1 OOIP PV where v1 is the weight coefficient, which ranges from 0 to 1. OOIP is the geological reserves (m3). PV is the pore volume (m3). DCCUSðCO2 -EORÞ is the dimensionless design object of CO2-EOR. Selecting the appropriate weighting factor is very important. If the goal is the maximum recovery, then v1 = 1; if the goal is the maximize sequestration of CO2, then v1 = 0. In this paper, an equal weighting factor (v1 = 0.5) is applied, indicating the equal
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importance of oil recovery and CO2 sequestration. In practice, the weight coefficient is selected according to the proceeds of oil production and CO2 sequestration. 5.2. Optimization of CO2 flooding and sequestration in demonstration zone According to numerical simulation methods considered characteristics of CO2 miscible flooding flow and related research
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achievements [7,17,18,48,49], main parameters are optimized on well spacing, pressure maintenance, injection pattern, injection rate and injection volume, etc. The optimization techniques of CO2 flooding and sequestration are developed for reservoir engineering design, and the limits of the CO2 flooding technology are depicted in Fig. 8. Fig. 8a is the histogram of recovery ratio in different displacement ways. From this figure, it can be seen that the WAG (Water Alternating Gas) injection pattern is better than that
Fig. 8. Technology optimization of CO2-EOR in the demonstration zone: (a) histogram of recovery ratio in different displacement ways; (b) relationship between DCCUSðCO2 -EORÞ and formation pressure; (c) correlation between DCCUSðCO2 -EORÞ and well patterns; (d) coupling between DCCUSðCO2 -EORÞ and well spacing; (e) Relationship between DCCUSðCO2 -EORÞ and injection rate; (f) Variation of ratio of oil to CO2 with injection volume of CO2.
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of continuous gas drive, and gas drive is straightly better than that of both water flooding and elastic displacement. Considering injection situation of the field, the demonstration zone adopts a continuous gas drive. Fig. 8b plots the relationship between DCCUSðCO2 -EORÞ and formation pressure. The objective function increases with the increased formation pressure. The objective function increases slowly when the formation pressure reaches to 30 MPa. So, this value is taken as the critical value in the demonstration zone. Fig. 8c depicts the correlation between DCCUSðCO2 -EORÞ and well patterns. The numerical simulation results show that the objective function gives the largest value when the inverted 9-spot well pattern is adopted. Fig. 8d plots the coupling between DCCUSðCO2 -EORÞ and well spacing. The objective function decreases with the increased well spacing. Due to low permeability in the demonstration zone, it is difficult to establish an effective displacement system in a large well spacing. The objective function produces the largest value when the well spacing is 350 m. Therefore, the spacing of 350 m is decided to be implemented in the demonstration zone. Fig. 8e plots the relationship between DCCUSðCO2 -EORÞ and injection rate. The objective function increases at first and then decreases with the increase of gas injection velocity. At a low gas injection rate, the injection gas volume is less than the output, contributing to the drop of the pressure and the decrease of the objective function. At a high gas injection rate, it is easy for gas channeling and reducing the recovery efficiency and storage rates, contributing to the decrease of the objective function. The optimal rate of gas injection is 20 t/d in the demonstration zone. Fig. 8f plots the curve of ratio of oil to CO2 with injection volume of CO2. Oil exchange ratio increases firstly and then decreases with the increased gas injection. It is caused by gas breakthrough in the late period. Oil exchange ratio is reduced when CO2 utilization ratio decreases. The biggest injection volume is 0.33 PV in the demonstration zone due to the economic factor. In a conclusion, the best scheme for CO2 flooding and sequestration in the demonstration zone is the 9-spot well pattern, 350 m well spacing, continuous injection, 30 MPa for the formation pressure, 20 t/d for the injection rate, 0.33 PV for the maximum injection volume. 6.7% is the forecast for enhanced oil recovery, 5.63 106 t for total injection volume of CO2, and 60.5% for the CO2 sequestration rate. 6. Injection–production process of CO2 flooding
Fig. 9. Structure diagram of gas injection string.
backwashing. When the annulus fluid which contained corrosion inhibitors is injected into the oil annulus, the anti-washing liquid through the backwash valve directly goes into the oil tubing and finally it goes back to the well-bore through the oil tubing to achieve the purpose of protection of the reservoir; (3) the use of hand-split structure to ensure the replacement of the upper gasinjection string without handling the lower part of the column; (4) the application of multifunction injection valve and disk valve can cancel the kill process on the upper column.
6.1. The safe killing free gas-injection string of CO2 flooding 6.2. Development of production string with high gas-to-oil ratio When gas injection wells transform to production wells or for other reasons the strings need to be replaced, the high expansion of CO2 contributes to a high risk during the construction process. It is urgent to design a safe killing free gas-injection string (Fig. 9). The function of backwash valve in the gas injection string is to connect the oil string and close the annulus during the injection process, and connect the annulus to replace the protective liquid during backwashing. The hydraulic anchor is used to anchor the tubular column. The sealing plug is composed by plug and ‘‘O’’-ring. Combined with the tieback cylinder, the sealing plug connects hand column and column tube, and it plays a key role in sealing. The principle of disk valve is that it can flip to an angle to connect the internal part when the disk pulled by an external force at the upper part. The disk will return to the original state by the spring force to seal the gas of borehole when the external force disappears. There are four features of the safe killing free gas-injection string of CO2 flooding: (1) anchor-type string structure can prevent the creep of column to ensure the normal operation of gas injection. It can protect the upper casing of the throw hand column at the same time; (2) it can replace the protective fluid during
To obtain a sound gas/liquid separation effect, the velocity of downward gas flow in the anchored section must be less than the floating speed of the bubbles in the liquid. The multistage gas anchor adopts an inverted umbrella structure. The gas/liquid mixture can go into the central tube only through the central bore in the bottom of the umbrella. Each umbrella structure is equivalent to a small sedimentation separator. It can realize degassing by utilization of density difference between gas and liquid, and control the descending speed of liquid by changing the number of umbrellas, and ensure the sufficient time for gas to separate from liquid, improving the gas/liquid separation efficiency and the pump efficiency. Considering the diameter of well-bores, if the outer diameter of separation chamber is 96 mm, and inner diameter is 94 mm, and each separation chamber volume is 1.47 104 m3, and a suction stroke volume is 1.06 102 m3, on the assumption that the separation chamber is 2 times the volume of pump stroke, the separation chamber number is 80 mm. With the extension of production, the production wells will appear many problems such as gas channelings, scaling and
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Fig. 10. Structure diagram of production string.
corrosion. The production string is designed with functions of high gas-to-oil ratios, losing hands and turn-off for the convenient of the replacement of strings in the late stage (Fig. 10). The specialized column has four characteristics: (1) equipped with the corrosion pump and the supporting tools in the downhole with anticorrosion performance; (2) the coupons can monitor the corrosive conditions of different materials in the downhole environment; (3) the measuring device of stationary pressure can monitor the gas drive effect in real time; (4) the gas anchors can reduce the oil-togas ratio at the pump inlet, increasing the pump efficiency. 7. Conclusions (1) A series of research is carried out in this paper about the fine stratigraphic correlation, structural interpretation, analysis of reservoir characteristics and distribution of oil and water in the demonstration zone of SINOPEC Shengli Oilfield, Dongying, China, and a 3D geological model is established as the foundation for the optimization of reservoir engineering design for CO2-EOR. (2) The fault sealing analysis is conducted in the demonstration zone. The results illustrate that the vertical sealing ability of faults is strong, and the possibility of CO2 leakage is weak in the vertical direction along faults. Therefore, the safety of subsurface sequestration of CO2 is ensured by the fault sealing potential. (3) Optimization methodology of CO2 flooding and sequestration is established by laboratory experiments, numerical modeling and reservoir engineering techniques. The numerical simulation results indicate that the enhanced oil recovery increased by 6.7%, and the total injection volume of CO2 is expected to reach to 5.63 106 t, and the sequestration rate of CO2 is to be approached 60.5%. (4) The safe killing free gas-injection string and oil-production string are developed with a high gas-to-liquid ratio.
Acknowledgements Funding support of large-scale coal-fired power plant flue gas CO2 capture, flooding and sequestration technology development demonstration (2012BAC24B000 and 2012BAC24B05) under
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