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Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil
Journal of Petroleum Science and Engineering 167 (2018) 241–248
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Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil
T
Kongyang Wang, Wei Yan∗, Jingen Deng∗∗, Hao Tian, Wenbo Li, Yangang Wang, Luyao Wang, Sutao Ye State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum, Beijing, 102249, China
A R T I C LE I N FO
A B S T R A C T
Keywords: Heavy oil Thermal recovery Pyrolysis H2S and CO2 generation Partial pressure
Thermal recovery is a conventional technology for heavy oil development. During thermal oil recovery the reservoir could generate H2S and CO2. They will potentially threat the safety of downhole tubing regarding the sweet or sour corrosion. In some Bohai heavy oil fields CO2 and H2S under thermal recovery conditions lead to some corrosion problems of the tubing and equipment. Therefore, to determine the corrosive gas generation capacity is crucial for anti-corrosion design of downhole tubing and casing. Heavy oil samples from Bohai, China were experimentally studied for their pyrolysis characteristics using high-temperature-high-pressure autoclaves. The gases were collected when autoclaves cooled down to the in situ formation temperature. Effects of temperature, water chemistry and core mineral on corrosive gas generation were investigated. The results show that total pressure increase significantly when temperature reached 250°C-280 °C under the single heavy oil condition. The additional water facilitates the reaction process, after more SO42− added in the mimic formation water, higher H2S content is obtained. Under the condition of multiphase of oil, formation water and cores, both of the H2S and CO2 content increase obviously, and the cores' effect on CO2 is greater than H2S. Anti-corrosion design usually concerns only the highest corrosive gas concentration without further analysis. The highest concentration does not always correspond to the best corrosive gases generation capacities of heavy oil. Comprehensive analysis of both the total pressure of reaction process and the quality of the reaction heavy oil is carried out, then the corrosive gases volume per unit mass of heavy oil is calculated. These can determine the strongest corrosive formation environment and the maximum gases generation capacities of heavy oil.
1. Introduction In the recent era, conventional fossil fuel depletion and the alternative energy source is a crucial problem all over the world. Some studies paid attention to the experiments of the alternative source like biofuels to solve the problem of conventional fossil fuel depletion (Dhinesh et al., 2016a; Annamalai et al., 2016; Parthasarathy et al., 2016). On the other hand, besides focusing on finding alternative source (Isaac et al., 2016; Dhinesh et al., 2016b, 2017), the development of unconventional fossil fuel resources may be a new solution. Crude oil is a fossil fuel formed by organic, thermal, and bacterial processes that transform sediments into hydrocarbons, water and carbon dioxide. It becomes an unconventional petroleum resourceheavy oil, if environmental conditions are appropriate (Chang and Robinson, 2006). Based on American Petroleum Institute (API) gravity and viscosity values, crude oil can be divided into light oil, medium oil,
∗
heavy oil and extra heavy oil (Smalley, 2000; Hart et al., 2015). The key properties of heavy oil are density, viscosity, and chemical composition. Here are several methods for heavy oil thermal recovery injection, including cyclic steam stimulation (CSS), also known as Huff and Puff (Shah et al., 2010; Haan and Lookeren, 1969), steam flooding/steam drive or steam stimulation (Zhao et al., 2014), steam-assisted gravity drainage (SAGD) (Zhao et al., 2015; Butler, 1985; Butler and Stephens, 1981), and in-situ combustion (ISC) or fire flooding (Chu, 1977, 1982; Guo et al., 2016a). All the methods will directly or indirectly heat the heavy oil reservoir. Under the conditions of mentioned thermal recovery methods, heavy oil decomposes to produce corrosive gases such as H2S and CO2. It is important to know the origin of H2S and CO2, which is toxic and corrosive. According to the reference, three causes of H2S production are: (1) Bacterial sulfate reduction (BSR), (2) Thermochemical sulfate reduction (TSR), (3) Thermal decomposition of Sulfide (TDS) (Mi et al.,
Corresponding author. Corresponding author. E-mail addresses: [email protected] (W. Yan), [email protected] (J. Deng).
∗∗
https://doi.org/10.1016/j.petrol.2018.03.100 Received 7 December 2017; Received in revised form 19 March 2018; Accepted 27 March 2018 Available online 12 April 2018 0920-4105/ © 2018 Elsevier B.V. All rights reserved.
Journal of Petroleum Science and Engineering 167 (2018) 241–248
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affected by water or core added to the reaction. Analysis of corrosive gas concentration and volume per unit mass of heavy oil is made to identify the condition of maximum corrosive gas generation capacity. The gas generation capacity of Bohai heavy oil is compared under different temperatures and SO42− concentration. And we conducted repeat-heat experiments to simulate cyclic steam stimulation (CSS) process used in Bohai oil fields.
2017; Zhu et al., 2010; Aali and Rahmani, 2012). These reactions also generate a large amount of CO2. The inorganically genetic H2S is produced primarily by TSR, water will participate in the reaction following the reaction equations below (Wang, 2008): 2CaSO4+4C+2H2O = 4CO2↑+Ca(OH)2+Ca(SH)2
(1)
Ca(SH)2+ CO2→CaCO3+ H2S↑
(2)
CaSO4+4H2 = Ca(OH)2+ H2S↑+2H2O
(3)
FeS2(pyrite)+HCl→FeCl3+ H2S↑
(4)
2. Experimental 2.1. Apparatus
The organically genetic H2S is generally related to Mercaptan and thioether, Mercaptan is prone to reacting with other substances to generate H2S following the reaction equations below (Wang, 2008): 2CuCl2+4RSH = RSSH+2RSCu+4HCl
(5)
RCH2CH2SH→H2S↑+RCH = = CH2
(6)
The stainless-steel autoclave (FYXD, Haian, China) with an internal volume of 2L, has been designed for a maximum operating temperature of 380 °C [653 K] and a pressure of 33 MPa [4786 psi]. The stainlesssteel autoclave was placed in an electrically heated furnace with electronic regulation and high heating power, permitting the vessel to be heated from ambient temperature to the experiment temperature condition within a few hours. A thermocouple was placed inside the vessel to record the temperature during the test. The apparatus was equipped with pressure gauge and a valve system to control the gas inlet and outlet. Different tests can be carried out with the stainless-steel autoclave being dynamic or stagnant. Because the in-situ heavy oil pyrolysis reactions could be recognized as static reactions, thus, the following laboratory tests were performed under stagnant condition. The stainless-steel autoclave was connected with an exhaust gas treatment device. When the test is finished, the air in the exhaust gas treatment device is swept by the exhaust gas and then gathered by gas packing (Tedlar PVF gas packing, Dalian Delin Gas packing Co.,Ltd, China). Other exhaust gases will be treated with NaOH solution before letting into the air (Fig. 1).
Mercaptan can provide high recovery of H2S and heavy oil will be cracked easily by catalyst (Alaei et al., 2017). Thioether is produced when the oxygen atom in an ether molecule is replaced by a sulfur atom, the structural formula is R-S-R′. Some thermal decomposition of thioether reaction equations are like below (Wang, 2008): C19H19SC19H19→C9H19SH + C9H18
(7)
C19H19SH →H2S↑+ C9H18
(8)
C2H5SC2H5→H2S↑+CH3CH3
(9)
C2H5SC2H5→C2H5SH + C2H4
(10)
C2H5SH→H2S↑+C2H4
(11)
2.2. Materials
These reactions of H2S and CO2 generation are related to the properties of the heavy oil itself, different regions may cause great difference, regarding reaction temperature, SO42− ions concentration in formation water and mineral in formation, and the effect of formation water (Lin et al., 2016). Thermal recovery methods will inject steam to reduce the viscosity of heavy oil which the temperature ranges from 180 to 350 °C (Liu et al., 2016; Romanov and Hamouda, 2011; Szasz and Thomas, 1965). The mercaptan (R-SH) is completely decomposed when the temperature reaches 300 °C, so the experiment chose the temperature condition of 280 °C and 350 °C to compare the effect of temperature on the corrosive gas generation. The combined effect of corrosive gas, high temperature and salty water has a great potential threat on the production tubing integrity of heavy oil (Zhong et al., 2013; Xiang et al., 2017; Guo et al., 2016b). For now, corrosive gas concentration is used to indicate the capacities of heavy oil, but this engineering method may come with error when the gas is of low concentration. The conditions of the highest measured concentrations of H2S or CO2 in laboratory may not always represent the best corrosive gas generation ability for a heavy oil sample (Pahlavan and Rafiqul, 1995). The experiment under this condition may show a false concentration of corrosive gases. Therefore, to determine the quantity of corrosive gas formation properly and accurately is significant for downhole tubing design during the heavy oil thermal recovery. For this case, a new comprehensive method considering gas concentration and gas volume per unit mass of heavy oil has been proposed. In this paper, pyrolysis experiments are conducted under three kinds of conditions (oil, oil + water, oil + water + rock) and two situations in different temperature and SO42− concentration. By using a certain amount of single heavy oil (200g), formation water(50g) and cores (100g) from Bohai bay block, China. The relationship between temperature and pressure during the reaction process is recorded, which is
The heavy oil samples were all collected from the Guantao formation (1000–1035 m) of Bohai bay block, China. They were from the exploratory wells and Guantao formation (1000–1035 m) temperature is about 64.6 °C. The properties of the heavy oil were given in Table 1 and the samples for the experiment were shown in Fig. 2(a) and b. Heavy oil viscosity is more than 10000 mPa s and density is more than 1 g/cm3. Sulfur content is about 0.43%, indicating that the sample itself is easy to produce H2S. Chemical properties are stable, not as easy to volatilize as light oil. All experimental oil samples are heavy oil. The main chemical composition of the heavy oil in this formation consists of 31% saturated hydrocarbon, 27% aromatic hydrocarbon, 21% asphalt and 21% non-hydrocarbon (Shan, 2001; Kong et al., 2009). Because of the high viscosity of heavy oil, after it was poured into the autoclave, the residual oil in the cup was around 10g, so a total mass of about 210g heavy oil was needed. Three core samples were collected from the same in-situ formation with heavy oil. The core samples were used in the heavy oil aquathermolysis and TSR experiment to compare the capacity of the heavy oil to generate corrosive gas under different conditions. The core and mimic formation water influence on gas generation were considered in the tests. The elements content analysis of each core samples is quantified by using a microscope and software QUANTAX7.0 (TM3030, HITACHI & Bruker, Japan). And the mineral contents of each three core samples are quantified using an X-ray diffractometer (Miniflex II, Rigaku, Japan). The elements and mineral contents analysis of all the samples are listed in Tables 2 and 3, respectively. Formation water samples were collected from eight different sampling points of exploratory wells, and analyzed by the Drilling Engineering Research Institute Bohai Experimental Center. The formation water ion concentration for this experiment by the Institute is shown in Table 4. For the #3 test, the SO42− ion concentration was 10 times higher than others. 242
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Fig. 1. Schematic of the experimental setup.
2.3. Procedures
3. Results and discussions
The testing matrix is shown in Table 5. Device installation and gas detection are similar to diesel engine combustion experiments (Lalvani et al., 2015; Balasubramanian et al., 2017). When the desired reaction samples were placed in the stainless-steel autoclave, the apparatus was assembled as shown in Fig. 1. Then, heat the stainless-steel autoclave to 70 °C and nitrogen was continuously injected in it to pressurize the system at 4 MPa to remove any residual air in the stainless-steel autoclave. After half an hour stop injecting nitrogen to close the outlet valve and inlet valve for a few hours to observe the pressure change, if the pressure does not change much, it means that the apparatus's air tightness is good and then discharged nitrogen to 0.1Mpa. During each experiment, samples were heated in the stainless-steel autoclave under a constant voltage (150 V) for a stable heating rate. When the inside temperature of the stainless-steel autoclave get 350 °C, it will remain at constant temperature by controlling the heating system. After the reaction was completed, the temperature of the autoclave was cooled down to 70 °C. Then, the outlet valve will be opened to guarantee that the gases are discharged from the stainless-steel autoclave to the gas sampling bag by the high pressure in the autoclave. Between the sampling bag and the stainless-steel autoclave, a desiccant is needed to dry the gas. Mixture Gas is analyzed by gas chromatography to obtain the percentage of each component (6890N, Agilent Technologies Inc, American). The experiment (#3) used 2000 mg/L SO42− to check the effect of H2S generation by SO42− ion concentration. The experiment (#5) was heated repeatedly, and the difference in gas composition between the former experiment and latter one that was heated repeatedly was examined. #7 experiment temperature stayed at 350 °C for at least 48 h because it is close to the formation temperature after steam injection. Another experiment, #6, is set at 280 °C for at least 48 h so that it can be compared to the effect of temperature on the reaction. Three core plugs were weighed after crushing and cleaning, then added the three experiments (#6,7,8). Each group used about 200g heavy oil, 100g core, 50g formation water (if the experimental conditions need to add).
3.1. Pressure and temperature The relationship between temperature and time of each experiment was recorded every half an hour, as well as the pressure and time. Once the temperature or pressure was stable, data is recorded hourly. The temperature generally needs 8–10 h to reach 350 °C under steady heating voltage (150 V) control, and the pressure change will be slightly slower than the temperature. The relationship of temperature, pressuretime is shown as Fig. 3 a, b, c. In this study, we call the initial temperature when pressure started rising fast as threshold temperature. Under the single heavy oil condition, the threshold temperature is between 250 and 280 °C. However, after the water was added into the experiment, the threshold temperature for aquathermolysis reaction decreased to 200-210 °C; and the threshold temperature of aquathermolysis + TSR was 190–200 °C. This phenomenon means that formation water promotes heavy oil to generate more gas and makes the decomposition reaction more easily. Thermal decomposition under aqueous condition reaction equation are like below (Chen et al., 2009): RCH2CH2SCH3+2H2O → RCH3+CO2 +H2S + H2+CH4
(12)
Comparing the single heavy oil reactions thermal decomposition like (6)–(11) (Wang, 2008), under aqueous condition, the reaction does not need the same energy as the single oil decomposition, so heavy oil decomposes more light gases like H2 and CH4. The gas composition test results show that the CH4 content is over 80%. For the experiments of aquathermolysis + TSR, the threshold temperature decreased by about 10 °C, but the total pressure was higher than others. Because rock cores contains an average of 1.4% calcite and 2.4% dolomite, those minerals generate a large amount of CO2. The threshold temperatures in all of the test were shown in Fig. 4. The product pictures of each reaction reflect the characteristics under three different conditions, as shown in Fig. 5. The decomposition product of single heavy oil after reaction are low in strength and loose,
Table 1 Properties of the heavy oil. Oil sample
Density (20 °C)
viscosity (50 °C)
Wax Content
Colloidal asphaltene
Freezing point
Sulfur content
guantao
1.004–1.011 g/cm3
37196–74462 mPa s
0.88–2.23%
28.60–44.35%
22–30 °C
0.42–0.44%
243
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Fig. 2. Heavy oil samples for the experiment. (a) Original oil samples obtained from the oil field, and (b) 200g heavy oil samples taken out of the bucket.
the corrosion gas partial pressure of the downhole string environment, the formulas are (Yan et al., 2016):
Table 2 The elements contents analysis of the core samples. element (wt%)
Core Sample#1
Core Sample#2
Core Sample#3
Carbon Oxygen Silicon Aluminium Iron Potassium Sodium Magnesium Sulfur Calcium Chlorine
52.96 33.02 8.452 2.649 0.88 0.83 0.68 0.26 0.12 0.11 0
48.13 34.33 10.58 3.26 0.79 1.17 0.88 0.26 0.13 0.42 0
47.05 36.01 12.35 1.74 0.48 0.52 0.80 0.19 0.27 0.32 0.21
#1 #2 #3
(13)
pCO2 = pb ∗CO2 %
(14)
pb: Bubble pressure mol. % H2S: concentration of H2S (mol/mol) mol. %CO2%: concentration of CO2 (mol/mol) pH2S: Partial pressure of Hydrogen sulfide pCO2: Partial pressure of carbon dioxide It has been found that the highest concentration of H2S is under the condition of single heavy oil, but it is generally believed that the aqueous condition and formation core will produce more H2S. This phenomenon has also occurred in other experimental results (Pahlavan and Rafiqul, 1995), in which the production of H2S increased with increasing temperature and time, but the concentration of H2S with these three conditions (oil, oil + water, oil + water + rock) diminished. And the CO2 concentration with these three conditions increased. These results are all in good agreement with our study. The reason of this situation can be explained as follows, one is many experiments gas collection are at room temperature, in the cooling process a part of H2S may be redissolved in heavy oil or water, in this study gas collection is conducted at 70 °C (the same as situ formation). Moreover, H2S generation in all of the reactions is little, so even a small percentage change in another large amount of gases, like:CH4, will lead to a greater impact on H2S concentration results; like formula (12) and blow (Lin et al., 2016; Shan, 2001; Worden and Smalley, 1996):
Table 3 The mineral contents analysis of the core samples. Core Sample
pH2 S = pb ∗H2 S %
mineral contents (%) quartz
Potash feldspar
Plagioclase
Calcite
dolomite
Siderite
TCCM
52.2 50.4 72.5
27.5 21.3 14.4
9.6 18.3 6.4
0.4 2.7 1.1
2.2 2.2 2.6
1.1 0 0
7.0 5.1 3.0
Table 4 The formation water ion concentration. ion
Na+
K+
Mg2+
Ca2+
Cl−
SO42-
HCO3−
CO32-
mg/L
1310.72
125.86
62.78
303.65
2489.43
213.13
344.82
0.00
hydrocarbons + SO42− →C1-5+C6++H2S + CO2+H2O + tar(aquathermolysis + TSR) (15)
so they can be taken out completely from the stainless-steel autoclave (Fig. 5(a)). And the reaction products' surface of aqueous condition appears with gloss, and a lot of bubble pit could be found (Fig. 5(b)). It also reflected that under aqueous condition heavy oil generates more gas than single heavy oil. After adding the cores, the final productions are hard and brittle, it is difficult to take them out of the stainless-steel autoclave entirely. The products fragments pictures after broken are shown in Fig. 5(c).
The H2S generation reactions will also generate other gases, especially in the aqueous condition like (12) and (15), and the mineral calcite and dolomite will generate CO2 and no H2S, some heavy oil reaction will generate CH4 or other C1-5 gases. So if the increase in the volume of H2S is disproportionate to other gases, the situation of total pressure will be lower while the H2S concentration is higher. For heavy oil + water + core, more gases like CH4 or CO2 will be generated. Total pressure is increased, while the H2S concentration is decreased, so the highest H2S concentration condition does not correspond with the best H2S generation capacity. Using the highest H2S concentration to calculate the anti-corrosive parameter will make the environment harsher than the actual formation. So here we propose an analytical method to identify this situation by calculating the gas volume that produced from the unit mass heavy oil. The H2S and CO2 volume per unit mass of heavy oil under 0 °C and atmospheric pressure can be calculated as following:
3.2. H2S and CO2 production analysis The H2S and CO2 contents are analyzed in all of the tests. The result of H2S and CO2 percentages under different environmental variables and the total pressure of the reactions are compared (Table 6). The H2S and CO2 concentrations of laboratory measurement are usually combined with the heavy oil bubble point pressure to calculate 244
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Table 5 Experimental matrix. No.
experimental sample
Temperature (°C)
Surrounding gas
experimental purposes
#1 #2 #3
Heavy oil Heavy oil Heavy oil + Formation Water (high SO42−) Heavy oil + Formation water Heavy oil + Formation water (heated repeatedly) Heavy oil + Formation water + core Heavy oil + Formation water + core Heavy oil + Formation water + core
350 350 350
N2 N2 N2
thermolysis thermolysis aquathermolysis
350
N2
aquathermolysis
350
N2
aquathermolysis
280
N2
aquathermolysis + TSR
350
N2
aquathermolysis + TSR
350
N2
aquathermolysis + TSR
#4 #5 #6 #7 #8
T
VH2S =
PTotal ∗H2 S%∗Vautoclave ∗ T273
623
(16)
atm∗m oil T
VCO2 =
PTotal ∗CO2 %∗Vautoclave ∗ T273
623
atm∗m oil
(17)
PTotal: Total pressure of test under 350 °C (623 K) H2S%: H2S concentration CO2%: CO2 concentration Vautoclave: volume of autoclave T273,623: 0 °C (273 K), 350 °C (623 K) atm:0.1Mpa moil: the mass of heavy oil, g; VH2S: H2S volume per unitmass of heavy oil VCO2: CO2 volume per unitmass of heavy oil The result of gas volume that produced of the per unit mass heavy oil as shown Table 7. All of the test results are shown in Fig. 6(a) and (b). The X-axis represents the total pressure of the reaction. The Y-axis represents the concentration of H2S(Fig. 6(a)) or CO2 (Fig. 6(b)). The circle size represents the volume of gas produced per unit mass (gas production capacity). The H2S analysis results (Fig. 6(a)) show that the condition of highest H2S concentration (#1) is not corresponding to the best H2S generation capacity (#7). The CO2 analysis results show that experiment#1,2 is opposite to the H2S experiment. It means when the total pressure is small, the high H2S concentration is because of a smaller amount of other gases. To identify this situation, we can calculate the
Fig. 4. Threshold temperature of each groups. #1#2 heavy oil (200g), #3 heavy oil (200g) formation water (50g, 2000 mg/L SO42−, 10times than the ion concentration in normal formation water),#4 heavy oil (200g) formation water (50g),#7#8 heavy oil (200g) formation water(50g)and core (100g).
amount of H2S generated per unit mass heavy oil, that is, using the size of circle (Fig. 6) to determine under which condition can the reaction generate the most amount of H2S. According to Fig. 6 the aquathermolysis + TSR condition or the #7, #8condition can generate the most H2S. Additionally, the two groups under the aqueous condition (#3 and #4) show that the high SO42− ion concentration in the formation water will make the reaction generate more H2S gas.
Fig. 3. Relationship of temperature, pressure-time. (a) thermolysis, experiments#1, #2 with only heavy oil (200g); (b) Aquathermolysis, experiments#3 (10times SO42−), #4 with heavy oil (200g) and formation water(50g); (c) Aquathermolysis + TSR, experiment#7, # 8 with heavy oil (200g) and formation water(50g) and core (100g). 245
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Fig. 5. Reaction products of #1 heavy oil (200g) thermolysis (a), #4 heavy oil (200g) formation water(50g) aquathermolysis (b), #8 heavy oil (200g) formation water(50g) and core (100g) aquathermolysis + TSR (c) conditions.
almost all the reactions will generate CO2, so CO2 have the same changing rate with the total gases, from the circle size we can get the same conclusion.
Table 6 Results of H2S&CO2 generation for each groups. Number
experimental sample
Temperature (°C)
Total pressure
Gas concentration (ppm)
#1
Heavy oil
350
11.91
#2 #3
Heavy oil Heavy oil+ Formation Water (high SO42−) Heavy oil+ Formation water Heavy oil+ Formation water + core Heavy oil+ Formation water + core
350 350
14.18 20.05
H2S 835 282 419
CO2 3808 14814 32008
350
19.42
300
27643
350
23.94
731
63590
350
23.09
600
60660
3.3. Effect of temperature
#4 #7
#8
The experiments (#6, #7, #8) used the same weight of heavy oil (200g), core (100g) and formation water(50g). Then those samples are heated to different temperatures (280 °C, 350 °C), the result of the three experiments can identify the capacity of corrosive gas generation by temperature. It is clear that an abundant amount of hydrocarbon gas and a small amount of H2S will be generated during aquathermolysis + TSR of heavy oil. The heavy oil aquathermolysis + TSR reaction total gases pressure is 13.7Mpa when the condition is 280 °C, less than the total pressure of 23.9Mpa and 23.1Mpa in 350 °C.The results of generated gas analysis, as shown in Tables 8 and 9, shows that the light hydrocarbon gases like CH4 content increased significantly, indicating that the decomposition of heavy oil is more complete. The CO2 and H2S concentration by heavy oil aquathermolysis + TSR of 280 °C is 28000 ppm and 300 ppm, which will increase to 63,600 ppm and 700 ppm when 350 °C.
Table 7 Gas volume of the unit mass heavy oil. Number
H2S CO2
Volume of per mass (ml/g) #1
#2
#3
#4
#7
#8
3.4. Effect of repeat heating
0.46 2.1
0.18 9.5
0.37 28.1
0.26 23.9
0.78 68.1
0.61 62.2
For the experiment #4, we used 200g of heavy oil and 50g of formation water for 48h heating and then discharged and measured the composition of the reaction gases. After cooling down the stainless-steel autoclave to room temperature, it was reheated to 350 °C for 24 h. That is the experiment #5, for the two experiments gas composition is shown in Table 10. For the total pressure of #4, the first reaction reached 19.4Mpa, and the total pressure of the second reaction after it is only 14.6Mpa at the same temperature of 350 °C. It indicated that the total amount of gas produced by the reheating reaction was decreased. The two experiments' gas analysis results show that although the reactants are reduced, the gas components are not affected by reheating. That is to say, for each of the steam injection heat, the corrosive environment is basically the same. Because the percentage of the various gas components does not change much and the bubble pressure is a natural property of heavy oil, the corrosion gas partial pressure of the downhole string environment using formula (13-14) is also basically the
Fig. 6. Results of H2S &CO2 generation characteristics for each groups. (a) the volume of H2S gas produced per unit mass by #12 heavy oil (200g), #3 heavy oil (200g) formation water (50g, 2000 mg/L SO42−, 10times than the ion concentration in normal formation water),#4 heavy oil (200g) formation water (50g),#7#8 heavy oil (200g) formation water(50g)and core (100g); (b) the volume of CO2 gas produced per unit mass by #12 heavy oil (200g), #3 heavy oil (200g) formation water (50g, 2000 mg/L SO42−, 10times than the ion concentration in normal formation water),#4 heavy oil (200g) formation water (50g),#7#8 heavy oil (200g) formation water(50g)and core (100g) volume.
Table 8 Concentration of H2S&CO2 gas by different temperature. Number
The CO2 total pressure, CO2 concentration and the CO2 volume per unit mass of heavy oil have a good consistency with the anticipation under experimental conditions. Because CO2 generation is much more than the H2S so the impact of other gases is small. On the other hand,
#6 #7 #8
246
Temperature (°C)
280 350 350
Gas concentration (ppm)
Volume of per mass (ml/ g)
H2S
CO2
H2S
CO2
300 731 600
28000 63590 60660
0.16 0.78 0.61
17.7 68.1 62.2
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unit mass of heavy oil can identify the false high concentration situation to find the best gas generation capacity of Bohai heavy oil. It's important for anti-corrosive design. 3) Under the aquathermolysis plus TSR condition, temperature is the most important factor affecting gas generation. The concentration of H2S (CO2) increased from 300 (28000) ppm to731 (63590) ppm, when the temperature increased from 280 °C to 350 °C. The total gas pressure at 280 °C is only half of that at 350 °C. After converted to the same temperature and pressure (0.1MPA 0 °C), the 350 °C H2S produced is about five times higher than that of 280 °C (0.16 ml/g to 0.78 ml/g) and the 350 °C CO2 produced is about four times higher than that of 280 °C (17.7 ml/g to 68.1 ml/g). 4) After 48 h of the first test, the stainless-steel autoclave temperature dropped from 350 °C to room temperature and then reheated to 350 °C again for 24 h, the final total pressure under the same condition is reduced by 5Mpa, but the composition of the various components of the gases is roughly the same as the first reaction, meaning that the whole reaction is a stable process.
Table 9 Composition of generation gas by different temperature. gas composition
280 °C#6
350 °C#7
350 °C#8
Hydrogen Oxygen Methane Carbon monoxide Carbon dioxide Ethylene Ethane Hydrogen sulfide Propane Propylene Isobutane N-butane Anti-butene Isobutylene Cis butene Isopentane
4.14 0.76 57.95 0.13 2.80 0.05 20.63 0.03 10.26 0.18 1.94 0.86 0.03 0.05 0.03 0.05
6.89 0.11 81.92 0.36 6.36 0 4.01 0.07 0.17 0 0.02 0.02 0 0 0 0.02
4.94 0.48 85.64 0.37 6.07 0 2.37 0.06 0.06 0 0 0.01 0 0 0 0
Notes
Table 10 Composition of generation gas by repeat heated. gas composition
350 °C#4
350 °C#5 (repeat heated)
Hydrogen Oxygen Methane Carbon monoxide Carbon dioxide Ethylene Ethane Hydrogen sulfide Propane Propylene Isobutane N-butane Anti-butene Isobutylene Cis butene Isopentane Pentene Hexane C6+
5.62 0.81 86.43 0.23 2.76 0 3.83 0.03 0.03 0 0 0 0 0 0 0.04 0.44 0.19 0.08
7.22 1.22 84.16 0.29 4.24 0 2.84 0.02 0.02 0 0 0 0 0 0 0.04 0.43 0.19 0.08
The authors declare no competing financial interest. Acknowledgements Thanks for the support of China National Offshore Oil Corporation Tianjin Branch in the process of this research. Partially of this work was supported by the National Natural Science Foundation of China (Grant No. 51504267 and 51521063). References Aali, J., Rahmani, O., 2012. H2S—origin in south pars gas field from Persian gulf, Iran. J. Petroleum Sci. Eng. s 86–87 (3), 217–224. Alaei, M., Bazmi, M., Rashidi, A., Rahimi, A., 2017. Heavy crude oil upgrading using homogenous nanocatalyst. J. Petroleum Sci. Eng. 158, 47–55. Annamalai, M., Dhinesh, B., Nanthagopal, K., Sivaramakrishnan, P., Lalvani, J.R., Parthasarathy, M., et al., 2016. An assessment on performance, combustion and emission behavior of a diesel engine powered by ceria nanoparticle blended emulsified biofuel. Energy Convers. Manag. 123, 372–380. Balasubramanian, D., Arumugam, S.R.S., Subramani, L., Mani, A., 2017. A numerical study on the effect of various combustion bowl parameters on the performance, combustion, and emission behavior on a single cylinder diesel engine. Environ. Sci. Pollut. Res. 25 (3), 1–12. Butler, R.M., 1985. A new approach to the modelling of steam-assisted gravity drainage. J. Can. Petroleum Technol. 24 (3), 42–51. Butler, R.M., Stephens, D.J., 1981. The gravity drainage of steam-heated heavy oil to parallel horizontal wells. J. Can. Petroleum Technol. 20 (2), 36. Chang, S.H., Robinson, P.R., 2006. Practical Advances in Petroleum Processing. Springer New York. Chen, T.S., Qin, H., Hong, L., Peng, P.A., Liu, J.Z., 2009. Thermal simulation experiments of saturated hydrocarbons with calcium sulfate and element sulfur: implications on origin of H2S. Sci. China Earth Sci. | Sci Chin Ear Sci 52 (10), 1550–1558. Chu, C., 1977. A study of fireflood field projects (includes associated paper 6504). J. Petroleum Technol. 29 (2), 111–120. Chu, C., 1982. State-of-the-art review of fireflood field projects (includes associated papers 10901 and 10918 ). J. Petroleum Technol. 34 (1), 19–36. Dhinesh, B., Annamalai, M., Lalvani, J.R., Annamalai, K., 2016a. Studies on the influence of combustion bowl modification for the operation of cymbopogon flexuosus biofuel based diesel blends in a di diesel engine. Appl. Therm. Eng. 112, 627–637. Dhinesh, B., Lalvani, J.I.J., Parthasarathy, M., Annamalai, K., 2016b. An assessment on performance, emission and combustion characteristics of single cylinder diesel engine powered by cymbopogon flexuosus biofuel. Energy Convers. Manag. 117, 466–474. Dhinesh, B., Isaac JoshuaRamesh Lalvani, J., Parthasarathy, M., Annamalai, K., 2017. An experimental analysis on the influence of fuel borne additives on the single cylinder diesel engine powered by Cymbopogon flexuosus biofuel. J. Energy Inst. 90 (4), 634–645. Guo, K., Li, H., Yu, Z., 2016a. In-situ, heavy and extra-heavy oil recovery: a review. Fuel 185, 886–902. Guo, S., Xu, L., Zhang, L., Chang, W., Lu, M., 2016b. Characterization of corrosion scale formed on 3cr steel in CO 2 -saturated formation water. Corros. Sci. 110, 123–133. Haan, H.J.D., Lookeren, J.V., 1969. Early results of the first large scale steam soak project in the tia juana field western Venezuela. J. Petroleum Technol. 21, 101–110. Hart, A., Greaves, M., Wood, J., 2015. A comparative study of fixed-bed and dispersed catalytic upgrading of heavy crude oil using-capri. Chem. Eng. J. 282, 213–223. Isaac, J.L.J., Parthasarathy, M., Dhinesh, B., Annamalai, K., 2016. Pooled effect of
same. 4. Conclusions Based on experimental results and mechanism study in this research, the following conclusions can be reached: 1) Under single heavy oil condition (without water), the threshold temperature is about 250°C–280 °C, and then water can reduce the threshold pressure by about 50 °C, core reduce the threshold pressure by about 10 °C. The single heavy oil reaction products are low in strength and loose, the reaction products of aqueous condition are with gloss, and a lot of bubble pit can be found in the productions' surface, the reaction products of aqueous condition with cores are hard and brittle. 2) The regularity of the reaction results is obvious. Under the same weight heavy oil reaction conditions, the addition of water will increase the amount of reaction gas, with the core and water the reaction can generate more gas. The false high concentration can be found in the H2S results, which is because that the H2S increase does not have the same generation rate as the total gases. For the CO2 generation, however, which is far more than H2S, making CO2 concentration less influenced by the increase in the total amount of gas. And the more SO42− ion in the mimic formation water, the more H2S we can get. Analysis and calculation of gas production per 247
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Yan, W., Xiang, Y., Li, W., Deng, J., 2016. Downhole CO2 partial pressure calculation and tubing material selection - a case study of an offshore oil field in the South China Sea. Anti-Corrosion Methods Mater. 63 (5), 414–420. Zhao, D.W., Wang, J., Gates, I.D., 2014. Thermal recovery strategies for thin heavy oil reservoirs. Fuel 117 (1), 431–441. Zhao, D.W., Wang, J., Gates, I.D., 2015. An evaluation of enhanced oil recovery strategies for a heavy oil reservoir after cold production with sand. Int. J. Energy Res. 39 (10), 1355–1365. Zhong, X., Zhang, G., Qiu, Y., Chen, Z., Guo, X., Fu, C., 2013. The corrosion of tin under thin electrolyte layers containing chloride. Corros. Sci. 66 (10), 14–25. Zhu, G., Zhang, S., Huang, H., Liu, Q., Yang, Z., Zhang, J., et al., 2010. Induced H2S formation during steam injection recovery process of heavy oil from the liaohe basin, ne China. J. Petroleum Sci. Eng. 71 (1–2), 30–36.
injection pressure and turbulence inducer piston on performance, combustion, and emission characteristics of a di diesel engine powered with biodiesel blend. Ecotoxicol. Environ. Saf. 134 (Pt 2), 336. Kong, S.Q., Wei, L., et al., 2009. Microbial degradation characteristics of heavy oil in Bohai. Oil field Chem. 26 (4), 432–435. Lalvani, J.R., Parthasarathy, M., Dhinesh, B., Annamalai, K., 2015. Experimental investigation of combustion, performance and emission characteristics of a modified piston. J. Mech. Sci. Technol. 29 (10), 4519–4525. Lin, R., Song, D., Wang, X., Yang, D., 2016. Experimental determination of in situ hydrogen sulfide production during thermal recovery processes. Energy & Fuels 30 (7), 5323–5329. Liu, D., Song, Q., Tang, J., Zheng, R., Yao, Q., 2016. Interaction between saturates, aromatics and resins during pyrolysis and oxidation of heavy oil. J. Petroleum Sci. Eng. 154. Mi, J., Zhang, B., Shen, Z., Huang, W., Casalins, A., Liu, C., 2017. The experimental study on H2S generation during thermal recovery process for heavy oil from the eastern Venezuela basin. J. Nat. Gas Geoscience. Pahlavan, H., Rafiqul, I., 1995. Laboratory simulation of geochemical changes of heavy crude oils during thermal oil recovery. J. Petroleum Sci. Eng. 12 (3), 219–231. Parthasarathy, M., Isaac, J.L.J., Dhinesh, B., Annamalai, K., 2016. Effect of hydrogen on ethanol-biodiesel blend on performance and emission characteristics of a direct injection diesel engine. Ecotoxicol. Environ. Saf. 134 (Pt 2), 433. Romanov, A.I., Hamouda, A.A., 2011. Heavy oil recovery by steam injection, mapping of temperature distribution in light of heat transfer mechanisms. Neuropharmacology 27 (1), 15–21. Shah, A., Fishwick, R., Wood, J., Leeke, G., Rigby, S., Greaves, M., 2010. A review of novel techniques for heavy oil and bitumen extraction and upgrading. Energy & Environ. Sci. 3 (6), 700–714. Shan, Z.T., 2001. Experiments on heaving oil degradation and enhancing oil recovery by microbial treatments. Acta Pet. Sinica. 22 (1), 55–58. Smalley, P.C., 2000. Heavy oil and viscous oil. Mod. Pet. Technol. 1 Upstream. Szasz, S.E., Thomas, G.W., 1965. Principles of heavy oil recovery. J. Can. Petroleum Technol. 4 (4), 188–195. Wang, Q., 2008. Generation mechanism and control measures for H2S in oil wells, liaohe oilfield. Petroleum Explor. Dev. 35 (3), 349–354. Worden, R.H., Smalley, P.C., 1996. H 2 S-producing reactions in deep carbonate gas reservoirs: Khuff Formation, Abu Dhabi. Chem. Geol. 133 (1–4), 157–171. Xiang, Y., Li, C., Long, Z., Guan, C., Wang, W., Hesitao, W., 2017. Electrochemical behavior of valve steel in a CO 2/sulfurous acid solution. Electrochimica Acta 258, 909–918.
Glossary API: American Petroleum Institute CSS: cyclic steam stimulation SAGD: steam-assisted gravity drainage ISC: in-situ combustion BSR: Bacterial sulfate reduction TSR: Thermochemical sulfate reduction TDS: Thermal decomposition of Sulfide R-S-R′: thioether R-SH: Mercaptan TCCM: The Clay Content in Minerals Pb: Bubble pressure mol. % H2S%: concentration of H2S mol. % CO2%: concentration of CO2 pH2S: Partial pressure of Hydrogen sulfide pCO2: Partial pressure of carbon dioxide PTotal: Total pressure of test under 350 °C(623K) Vautoclave: volume of autoclave T273,623: 0 °C(273K), 350 °C(623K) Atm: 0.1Mpa moil: the mass of heavy oil, g; VH2S: H2S volume per unitmass of heavy oil VCO2: CO2 volume per unitmass of heavy oil
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Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil
T
Kongyang Wang, Wei Yan∗, Jingen Deng∗∗, Hao Tian, Wenbo Li, Yangang Wang, Luyao Wang, Sutao Ye State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum, Beijing, 102249, China
A R T I C LE I N FO
A B S T R A C T
Keywords: Heavy oil Thermal recovery Pyrolysis H2S and CO2 generation Partial pressure
Thermal recovery is a conventional technology for heavy oil development. During thermal oil recovery the reservoir could generate H2S and CO2. They will potentially threat the safety of downhole tubing regarding the sweet or sour corrosion. In some Bohai heavy oil fields CO2 and H2S under thermal recovery conditions lead to some corrosion problems of the tubing and equipment. Therefore, to determine the corrosive gas generation capacity is crucial for anti-corrosion design of downhole tubing and casing. Heavy oil samples from Bohai, China were experimentally studied for their pyrolysis characteristics using high-temperature-high-pressure autoclaves. The gases were collected when autoclaves cooled down to the in situ formation temperature. Effects of temperature, water chemistry and core mineral on corrosive gas generation were investigated. The results show that total pressure increase significantly when temperature reached 250°C-280 °C under the single heavy oil condition. The additional water facilitates the reaction process, after more SO42− added in the mimic formation water, higher H2S content is obtained. Under the condition of multiphase of oil, formation water and cores, both of the H2S and CO2 content increase obviously, and the cores' effect on CO2 is greater than H2S. Anti-corrosion design usually concerns only the highest corrosive gas concentration without further analysis. The highest concentration does not always correspond to the best corrosive gases generation capacities of heavy oil. Comprehensive analysis of both the total pressure of reaction process and the quality of the reaction heavy oil is carried out, then the corrosive gases volume per unit mass of heavy oil is calculated. These can determine the strongest corrosive formation environment and the maximum gases generation capacities of heavy oil.
1. Introduction In the recent era, conventional fossil fuel depletion and the alternative energy source is a crucial problem all over the world. Some studies paid attention to the experiments of the alternative source like biofuels to solve the problem of conventional fossil fuel depletion (Dhinesh et al., 2016a; Annamalai et al., 2016; Parthasarathy et al., 2016). On the other hand, besides focusing on finding alternative source (Isaac et al., 2016; Dhinesh et al., 2016b, 2017), the development of unconventional fossil fuel resources may be a new solution. Crude oil is a fossil fuel formed by organic, thermal, and bacterial processes that transform sediments into hydrocarbons, water and carbon dioxide. It becomes an unconventional petroleum resourceheavy oil, if environmental conditions are appropriate (Chang and Robinson, 2006). Based on American Petroleum Institute (API) gravity and viscosity values, crude oil can be divided into light oil, medium oil,
∗
heavy oil and extra heavy oil (Smalley, 2000; Hart et al., 2015). The key properties of heavy oil are density, viscosity, and chemical composition. Here are several methods for heavy oil thermal recovery injection, including cyclic steam stimulation (CSS), also known as Huff and Puff (Shah et al., 2010; Haan and Lookeren, 1969), steam flooding/steam drive or steam stimulation (Zhao et al., 2014), steam-assisted gravity drainage (SAGD) (Zhao et al., 2015; Butler, 1985; Butler and Stephens, 1981), and in-situ combustion (ISC) or fire flooding (Chu, 1977, 1982; Guo et al., 2016a). All the methods will directly or indirectly heat the heavy oil reservoir. Under the conditions of mentioned thermal recovery methods, heavy oil decomposes to produce corrosive gases such as H2S and CO2. It is important to know the origin of H2S and CO2, which is toxic and corrosive. According to the reference, three causes of H2S production are: (1) Bacterial sulfate reduction (BSR), (2) Thermochemical sulfate reduction (TSR), (3) Thermal decomposition of Sulfide (TDS) (Mi et al.,
Corresponding author. Corresponding author. E-mail addresses: [email protected] (W. Yan), [email protected] (J. Deng).
∗∗
https://doi.org/10.1016/j.petrol.2018.03.100 Received 7 December 2017; Received in revised form 19 March 2018; Accepted 27 March 2018 Available online 12 April 2018 0920-4105/ © 2018 Elsevier B.V. All rights reserved.
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affected by water or core added to the reaction. Analysis of corrosive gas concentration and volume per unit mass of heavy oil is made to identify the condition of maximum corrosive gas generation capacity. The gas generation capacity of Bohai heavy oil is compared under different temperatures and SO42− concentration. And we conducted repeat-heat experiments to simulate cyclic steam stimulation (CSS) process used in Bohai oil fields.
2017; Zhu et al., 2010; Aali and Rahmani, 2012). These reactions also generate a large amount of CO2. The inorganically genetic H2S is produced primarily by TSR, water will participate in the reaction following the reaction equations below (Wang, 2008): 2CaSO4+4C+2H2O = 4CO2↑+Ca(OH)2+Ca(SH)2
(1)
Ca(SH)2+ CO2→CaCO3+ H2S↑
(2)
CaSO4+4H2 = Ca(OH)2+ H2S↑+2H2O
(3)
FeS2(pyrite)+HCl→FeCl3+ H2S↑
(4)
2. Experimental 2.1. Apparatus
The organically genetic H2S is generally related to Mercaptan and thioether, Mercaptan is prone to reacting with other substances to generate H2S following the reaction equations below (Wang, 2008): 2CuCl2+4RSH = RSSH+2RSCu+4HCl
(5)
RCH2CH2SH→H2S↑+RCH = = CH2
(6)
The stainless-steel autoclave (FYXD, Haian, China) with an internal volume of 2L, has been designed for a maximum operating temperature of 380 °C [653 K] and a pressure of 33 MPa [4786 psi]. The stainlesssteel autoclave was placed in an electrically heated furnace with electronic regulation and high heating power, permitting the vessel to be heated from ambient temperature to the experiment temperature condition within a few hours. A thermocouple was placed inside the vessel to record the temperature during the test. The apparatus was equipped with pressure gauge and a valve system to control the gas inlet and outlet. Different tests can be carried out with the stainless-steel autoclave being dynamic or stagnant. Because the in-situ heavy oil pyrolysis reactions could be recognized as static reactions, thus, the following laboratory tests were performed under stagnant condition. The stainless-steel autoclave was connected with an exhaust gas treatment device. When the test is finished, the air in the exhaust gas treatment device is swept by the exhaust gas and then gathered by gas packing (Tedlar PVF gas packing, Dalian Delin Gas packing Co.,Ltd, China). Other exhaust gases will be treated with NaOH solution before letting into the air (Fig. 1).
Mercaptan can provide high recovery of H2S and heavy oil will be cracked easily by catalyst (Alaei et al., 2017). Thioether is produced when the oxygen atom in an ether molecule is replaced by a sulfur atom, the structural formula is R-S-R′. Some thermal decomposition of thioether reaction equations are like below (Wang, 2008): C19H19SC19H19→C9H19SH + C9H18
(7)
C19H19SH →H2S↑+ C9H18
(8)
C2H5SC2H5→H2S↑+CH3CH3
(9)
C2H5SC2H5→C2H5SH + C2H4
(10)
C2H5SH→H2S↑+C2H4
(11)
2.2. Materials
These reactions of H2S and CO2 generation are related to the properties of the heavy oil itself, different regions may cause great difference, regarding reaction temperature, SO42− ions concentration in formation water and mineral in formation, and the effect of formation water (Lin et al., 2016). Thermal recovery methods will inject steam to reduce the viscosity of heavy oil which the temperature ranges from 180 to 350 °C (Liu et al., 2016; Romanov and Hamouda, 2011; Szasz and Thomas, 1965). The mercaptan (R-SH) is completely decomposed when the temperature reaches 300 °C, so the experiment chose the temperature condition of 280 °C and 350 °C to compare the effect of temperature on the corrosive gas generation. The combined effect of corrosive gas, high temperature and salty water has a great potential threat on the production tubing integrity of heavy oil (Zhong et al., 2013; Xiang et al., 2017; Guo et al., 2016b). For now, corrosive gas concentration is used to indicate the capacities of heavy oil, but this engineering method may come with error when the gas is of low concentration. The conditions of the highest measured concentrations of H2S or CO2 in laboratory may not always represent the best corrosive gas generation ability for a heavy oil sample (Pahlavan and Rafiqul, 1995). The experiment under this condition may show a false concentration of corrosive gases. Therefore, to determine the quantity of corrosive gas formation properly and accurately is significant for downhole tubing design during the heavy oil thermal recovery. For this case, a new comprehensive method considering gas concentration and gas volume per unit mass of heavy oil has been proposed. In this paper, pyrolysis experiments are conducted under three kinds of conditions (oil, oil + water, oil + water + rock) and two situations in different temperature and SO42− concentration. By using a certain amount of single heavy oil (200g), formation water(50g) and cores (100g) from Bohai bay block, China. The relationship between temperature and pressure during the reaction process is recorded, which is
The heavy oil samples were all collected from the Guantao formation (1000–1035 m) of Bohai bay block, China. They were from the exploratory wells and Guantao formation (1000–1035 m) temperature is about 64.6 °C. The properties of the heavy oil were given in Table 1 and the samples for the experiment were shown in Fig. 2(a) and b. Heavy oil viscosity is more than 10000 mPa s and density is more than 1 g/cm3. Sulfur content is about 0.43%, indicating that the sample itself is easy to produce H2S. Chemical properties are stable, not as easy to volatilize as light oil. All experimental oil samples are heavy oil. The main chemical composition of the heavy oil in this formation consists of 31% saturated hydrocarbon, 27% aromatic hydrocarbon, 21% asphalt and 21% non-hydrocarbon (Shan, 2001; Kong et al., 2009). Because of the high viscosity of heavy oil, after it was poured into the autoclave, the residual oil in the cup was around 10g, so a total mass of about 210g heavy oil was needed. Three core samples were collected from the same in-situ formation with heavy oil. The core samples were used in the heavy oil aquathermolysis and TSR experiment to compare the capacity of the heavy oil to generate corrosive gas under different conditions. The core and mimic formation water influence on gas generation were considered in the tests. The elements content analysis of each core samples is quantified by using a microscope and software QUANTAX7.0 (TM3030, HITACHI & Bruker, Japan). And the mineral contents of each three core samples are quantified using an X-ray diffractometer (Miniflex II, Rigaku, Japan). The elements and mineral contents analysis of all the samples are listed in Tables 2 and 3, respectively. Formation water samples were collected from eight different sampling points of exploratory wells, and analyzed by the Drilling Engineering Research Institute Bohai Experimental Center. The formation water ion concentration for this experiment by the Institute is shown in Table 4. For the #3 test, the SO42− ion concentration was 10 times higher than others. 242
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Fig. 1. Schematic of the experimental setup.
2.3. Procedures
3. Results and discussions
The testing matrix is shown in Table 5. Device installation and gas detection are similar to diesel engine combustion experiments (Lalvani et al., 2015; Balasubramanian et al., 2017). When the desired reaction samples were placed in the stainless-steel autoclave, the apparatus was assembled as shown in Fig. 1. Then, heat the stainless-steel autoclave to 70 °C and nitrogen was continuously injected in it to pressurize the system at 4 MPa to remove any residual air in the stainless-steel autoclave. After half an hour stop injecting nitrogen to close the outlet valve and inlet valve for a few hours to observe the pressure change, if the pressure does not change much, it means that the apparatus's air tightness is good and then discharged nitrogen to 0.1Mpa. During each experiment, samples were heated in the stainless-steel autoclave under a constant voltage (150 V) for a stable heating rate. When the inside temperature of the stainless-steel autoclave get 350 °C, it will remain at constant temperature by controlling the heating system. After the reaction was completed, the temperature of the autoclave was cooled down to 70 °C. Then, the outlet valve will be opened to guarantee that the gases are discharged from the stainless-steel autoclave to the gas sampling bag by the high pressure in the autoclave. Between the sampling bag and the stainless-steel autoclave, a desiccant is needed to dry the gas. Mixture Gas is analyzed by gas chromatography to obtain the percentage of each component (6890N, Agilent Technologies Inc, American). The experiment (#3) used 2000 mg/L SO42− to check the effect of H2S generation by SO42− ion concentration. The experiment (#5) was heated repeatedly, and the difference in gas composition between the former experiment and latter one that was heated repeatedly was examined. #7 experiment temperature stayed at 350 °C for at least 48 h because it is close to the formation temperature after steam injection. Another experiment, #6, is set at 280 °C for at least 48 h so that it can be compared to the effect of temperature on the reaction. Three core plugs were weighed after crushing and cleaning, then added the three experiments (#6,7,8). Each group used about 200g heavy oil, 100g core, 50g formation water (if the experimental conditions need to add).
3.1. Pressure and temperature The relationship between temperature and time of each experiment was recorded every half an hour, as well as the pressure and time. Once the temperature or pressure was stable, data is recorded hourly. The temperature generally needs 8–10 h to reach 350 °C under steady heating voltage (150 V) control, and the pressure change will be slightly slower than the temperature. The relationship of temperature, pressuretime is shown as Fig. 3 a, b, c. In this study, we call the initial temperature when pressure started rising fast as threshold temperature. Under the single heavy oil condition, the threshold temperature is between 250 and 280 °C. However, after the water was added into the experiment, the threshold temperature for aquathermolysis reaction decreased to 200-210 °C; and the threshold temperature of aquathermolysis + TSR was 190–200 °C. This phenomenon means that formation water promotes heavy oil to generate more gas and makes the decomposition reaction more easily. Thermal decomposition under aqueous condition reaction equation are like below (Chen et al., 2009): RCH2CH2SCH3+2H2O → RCH3+CO2 +H2S + H2+CH4
(12)
Comparing the single heavy oil reactions thermal decomposition like (6)–(11) (Wang, 2008), under aqueous condition, the reaction does not need the same energy as the single oil decomposition, so heavy oil decomposes more light gases like H2 and CH4. The gas composition test results show that the CH4 content is over 80%. For the experiments of aquathermolysis + TSR, the threshold temperature decreased by about 10 °C, but the total pressure was higher than others. Because rock cores contains an average of 1.4% calcite and 2.4% dolomite, those minerals generate a large amount of CO2. The threshold temperatures in all of the test were shown in Fig. 4. The product pictures of each reaction reflect the characteristics under three different conditions, as shown in Fig. 5. The decomposition product of single heavy oil after reaction are low in strength and loose,
Table 1 Properties of the heavy oil. Oil sample
Density (20 °C)
viscosity (50 °C)
Wax Content
Colloidal asphaltene
Freezing point
Sulfur content
guantao
1.004–1.011 g/cm3
37196–74462 mPa s
0.88–2.23%
28.60–44.35%
22–30 °C
0.42–0.44%
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Fig. 2. Heavy oil samples for the experiment. (a) Original oil samples obtained from the oil field, and (b) 200g heavy oil samples taken out of the bucket.
the corrosion gas partial pressure of the downhole string environment, the formulas are (Yan et al., 2016):
Table 2 The elements contents analysis of the core samples. element (wt%)
Core Sample#1
Core Sample#2
Core Sample#3
Carbon Oxygen Silicon Aluminium Iron Potassium Sodium Magnesium Sulfur Calcium Chlorine
52.96 33.02 8.452 2.649 0.88 0.83 0.68 0.26 0.12 0.11 0
48.13 34.33 10.58 3.26 0.79 1.17 0.88 0.26 0.13 0.42 0
47.05 36.01 12.35 1.74 0.48 0.52 0.80 0.19 0.27 0.32 0.21
#1 #2 #3
(13)
pCO2 = pb ∗CO2 %
(14)
pb: Bubble pressure mol. % H2S: concentration of H2S (mol/mol) mol. %CO2%: concentration of CO2 (mol/mol) pH2S: Partial pressure of Hydrogen sulfide pCO2: Partial pressure of carbon dioxide It has been found that the highest concentration of H2S is under the condition of single heavy oil, but it is generally believed that the aqueous condition and formation core will produce more H2S. This phenomenon has also occurred in other experimental results (Pahlavan and Rafiqul, 1995), in which the production of H2S increased with increasing temperature and time, but the concentration of H2S with these three conditions (oil, oil + water, oil + water + rock) diminished. And the CO2 concentration with these three conditions increased. These results are all in good agreement with our study. The reason of this situation can be explained as follows, one is many experiments gas collection are at room temperature, in the cooling process a part of H2S may be redissolved in heavy oil or water, in this study gas collection is conducted at 70 °C (the same as situ formation). Moreover, H2S generation in all of the reactions is little, so even a small percentage change in another large amount of gases, like:CH4, will lead to a greater impact on H2S concentration results; like formula (12) and blow (Lin et al., 2016; Shan, 2001; Worden and Smalley, 1996):
Table 3 The mineral contents analysis of the core samples. Core Sample
pH2 S = pb ∗H2 S %
mineral contents (%) quartz
Potash feldspar
Plagioclase
Calcite
dolomite
Siderite
TCCM
52.2 50.4 72.5
27.5 21.3 14.4
9.6 18.3 6.4
0.4 2.7 1.1
2.2 2.2 2.6
1.1 0 0
7.0 5.1 3.0
Table 4 The formation water ion concentration. ion
Na+
K+
Mg2+
Ca2+
Cl−
SO42-
HCO3−
CO32-
mg/L
1310.72
125.86
62.78
303.65
2489.43
213.13
344.82
0.00
hydrocarbons + SO42− →C1-5+C6++H2S + CO2+H2O + tar(aquathermolysis + TSR) (15)
so they can be taken out completely from the stainless-steel autoclave (Fig. 5(a)). And the reaction products' surface of aqueous condition appears with gloss, and a lot of bubble pit could be found (Fig. 5(b)). It also reflected that under aqueous condition heavy oil generates more gas than single heavy oil. After adding the cores, the final productions are hard and brittle, it is difficult to take them out of the stainless-steel autoclave entirely. The products fragments pictures after broken are shown in Fig. 5(c).
The H2S generation reactions will also generate other gases, especially in the aqueous condition like (12) and (15), and the mineral calcite and dolomite will generate CO2 and no H2S, some heavy oil reaction will generate CH4 or other C1-5 gases. So if the increase in the volume of H2S is disproportionate to other gases, the situation of total pressure will be lower while the H2S concentration is higher. For heavy oil + water + core, more gases like CH4 or CO2 will be generated. Total pressure is increased, while the H2S concentration is decreased, so the highest H2S concentration condition does not correspond with the best H2S generation capacity. Using the highest H2S concentration to calculate the anti-corrosive parameter will make the environment harsher than the actual formation. So here we propose an analytical method to identify this situation by calculating the gas volume that produced from the unit mass heavy oil. The H2S and CO2 volume per unit mass of heavy oil under 0 °C and atmospheric pressure can be calculated as following:
3.2. H2S and CO2 production analysis The H2S and CO2 contents are analyzed in all of the tests. The result of H2S and CO2 percentages under different environmental variables and the total pressure of the reactions are compared (Table 6). The H2S and CO2 concentrations of laboratory measurement are usually combined with the heavy oil bubble point pressure to calculate 244
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Table 5 Experimental matrix. No.
experimental sample
Temperature (°C)
Surrounding gas
experimental purposes
#1 #2 #3
Heavy oil Heavy oil Heavy oil + Formation Water (high SO42−) Heavy oil + Formation water Heavy oil + Formation water (heated repeatedly) Heavy oil + Formation water + core Heavy oil + Formation water + core Heavy oil + Formation water + core
350 350 350
N2 N2 N2
thermolysis thermolysis aquathermolysis
350
N2
aquathermolysis
350
N2
aquathermolysis
280
N2
aquathermolysis + TSR
350
N2
aquathermolysis + TSR
350
N2
aquathermolysis + TSR
#4 #5 #6 #7 #8
T
VH2S =
PTotal ∗H2 S%∗Vautoclave ∗ T273
623
(16)
atm∗m oil T
VCO2 =
PTotal ∗CO2 %∗Vautoclave ∗ T273
623
atm∗m oil
(17)
PTotal: Total pressure of test under 350 °C (623 K) H2S%: H2S concentration CO2%: CO2 concentration Vautoclave: volume of autoclave T273,623: 0 °C (273 K), 350 °C (623 K) atm:0.1Mpa moil: the mass of heavy oil, g; VH2S: H2S volume per unitmass of heavy oil VCO2: CO2 volume per unitmass of heavy oil The result of gas volume that produced of the per unit mass heavy oil as shown Table 7. All of the test results are shown in Fig. 6(a) and (b). The X-axis represents the total pressure of the reaction. The Y-axis represents the concentration of H2S(Fig. 6(a)) or CO2 (Fig. 6(b)). The circle size represents the volume of gas produced per unit mass (gas production capacity). The H2S analysis results (Fig. 6(a)) show that the condition of highest H2S concentration (#1) is not corresponding to the best H2S generation capacity (#7). The CO2 analysis results show that experiment#1,2 is opposite to the H2S experiment. It means when the total pressure is small, the high H2S concentration is because of a smaller amount of other gases. To identify this situation, we can calculate the
Fig. 4. Threshold temperature of each groups. #1#2 heavy oil (200g), #3 heavy oil (200g) formation water (50g, 2000 mg/L SO42−, 10times than the ion concentration in normal formation water),#4 heavy oil (200g) formation water (50g),#7#8 heavy oil (200g) formation water(50g)and core (100g).
amount of H2S generated per unit mass heavy oil, that is, using the size of circle (Fig. 6) to determine under which condition can the reaction generate the most amount of H2S. According to Fig. 6 the aquathermolysis + TSR condition or the #7, #8condition can generate the most H2S. Additionally, the two groups under the aqueous condition (#3 and #4) show that the high SO42− ion concentration in the formation water will make the reaction generate more H2S gas.
Fig. 3. Relationship of temperature, pressure-time. (a) thermolysis, experiments#1, #2 with only heavy oil (200g); (b) Aquathermolysis, experiments#3 (10times SO42−), #4 with heavy oil (200g) and formation water(50g); (c) Aquathermolysis + TSR, experiment#7, # 8 with heavy oil (200g) and formation water(50g) and core (100g). 245
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Fig. 5. Reaction products of #1 heavy oil (200g) thermolysis (a), #4 heavy oil (200g) formation water(50g) aquathermolysis (b), #8 heavy oil (200g) formation water(50g) and core (100g) aquathermolysis + TSR (c) conditions.
almost all the reactions will generate CO2, so CO2 have the same changing rate with the total gases, from the circle size we can get the same conclusion.
Table 6 Results of H2S&CO2 generation for each groups. Number
experimental sample
Temperature (°C)
Total pressure
Gas concentration (ppm)
#1
Heavy oil
350
11.91
#2 #3
Heavy oil Heavy oil+ Formation Water (high SO42−) Heavy oil+ Formation water Heavy oil+ Formation water + core Heavy oil+ Formation water + core
350 350
14.18 20.05
H2S 835 282 419
CO2 3808 14814 32008
350
19.42
300
27643
350
23.94
731
63590
350
23.09
600
60660
3.3. Effect of temperature
#4 #7
#8
The experiments (#6, #7, #8) used the same weight of heavy oil (200g), core (100g) and formation water(50g). Then those samples are heated to different temperatures (280 °C, 350 °C), the result of the three experiments can identify the capacity of corrosive gas generation by temperature. It is clear that an abundant amount of hydrocarbon gas and a small amount of H2S will be generated during aquathermolysis + TSR of heavy oil. The heavy oil aquathermolysis + TSR reaction total gases pressure is 13.7Mpa when the condition is 280 °C, less than the total pressure of 23.9Mpa and 23.1Mpa in 350 °C.The results of generated gas analysis, as shown in Tables 8 and 9, shows that the light hydrocarbon gases like CH4 content increased significantly, indicating that the decomposition of heavy oil is more complete. The CO2 and H2S concentration by heavy oil aquathermolysis + TSR of 280 °C is 28000 ppm and 300 ppm, which will increase to 63,600 ppm and 700 ppm when 350 °C.
Table 7 Gas volume of the unit mass heavy oil. Number
H2S CO2
Volume of per mass (ml/g) #1
#2
#3
#4
#7
#8
3.4. Effect of repeat heating
0.46 2.1
0.18 9.5
0.37 28.1
0.26 23.9
0.78 68.1
0.61 62.2
For the experiment #4, we used 200g of heavy oil and 50g of formation water for 48h heating and then discharged and measured the composition of the reaction gases. After cooling down the stainless-steel autoclave to room temperature, it was reheated to 350 °C for 24 h. That is the experiment #5, for the two experiments gas composition is shown in Table 10. For the total pressure of #4, the first reaction reached 19.4Mpa, and the total pressure of the second reaction after it is only 14.6Mpa at the same temperature of 350 °C. It indicated that the total amount of gas produced by the reheating reaction was decreased. The two experiments' gas analysis results show that although the reactants are reduced, the gas components are not affected by reheating. That is to say, for each of the steam injection heat, the corrosive environment is basically the same. Because the percentage of the various gas components does not change much and the bubble pressure is a natural property of heavy oil, the corrosion gas partial pressure of the downhole string environment using formula (13-14) is also basically the
Fig. 6. Results of H2S &CO2 generation characteristics for each groups. (a) the volume of H2S gas produced per unit mass by #12 heavy oil (200g), #3 heavy oil (200g) formation water (50g, 2000 mg/L SO42−, 10times than the ion concentration in normal formation water),#4 heavy oil (200g) formation water (50g),#7#8 heavy oil (200g) formation water(50g)and core (100g); (b) the volume of CO2 gas produced per unit mass by #12 heavy oil (200g), #3 heavy oil (200g) formation water (50g, 2000 mg/L SO42−, 10times than the ion concentration in normal formation water),#4 heavy oil (200g) formation water (50g),#7#8 heavy oil (200g) formation water(50g)and core (100g) volume.
Table 8 Concentration of H2S&CO2 gas by different temperature. Number
The CO2 total pressure, CO2 concentration and the CO2 volume per unit mass of heavy oil have a good consistency with the anticipation under experimental conditions. Because CO2 generation is much more than the H2S so the impact of other gases is small. On the other hand,
#6 #7 #8
246
Temperature (°C)
280 350 350
Gas concentration (ppm)
Volume of per mass (ml/ g)
H2S
CO2
H2S
CO2
300 731 600
28000 63590 60660
0.16 0.78 0.61
17.7 68.1 62.2
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unit mass of heavy oil can identify the false high concentration situation to find the best gas generation capacity of Bohai heavy oil. It's important for anti-corrosive design. 3) Under the aquathermolysis plus TSR condition, temperature is the most important factor affecting gas generation. The concentration of H2S (CO2) increased from 300 (28000) ppm to731 (63590) ppm, when the temperature increased from 280 °C to 350 °C. The total gas pressure at 280 °C is only half of that at 350 °C. After converted to the same temperature and pressure (0.1MPA 0 °C), the 350 °C H2S produced is about five times higher than that of 280 °C (0.16 ml/g to 0.78 ml/g) and the 350 °C CO2 produced is about four times higher than that of 280 °C (17.7 ml/g to 68.1 ml/g). 4) After 48 h of the first test, the stainless-steel autoclave temperature dropped from 350 °C to room temperature and then reheated to 350 °C again for 24 h, the final total pressure under the same condition is reduced by 5Mpa, but the composition of the various components of the gases is roughly the same as the first reaction, meaning that the whole reaction is a stable process.
Table 9 Composition of generation gas by different temperature. gas composition
280 °C#6
350 °C#7
350 °C#8
Hydrogen Oxygen Methane Carbon monoxide Carbon dioxide Ethylene Ethane Hydrogen sulfide Propane Propylene Isobutane N-butane Anti-butene Isobutylene Cis butene Isopentane
4.14 0.76 57.95 0.13 2.80 0.05 20.63 0.03 10.26 0.18 1.94 0.86 0.03 0.05 0.03 0.05
6.89 0.11 81.92 0.36 6.36 0 4.01 0.07 0.17 0 0.02 0.02 0 0 0 0.02
4.94 0.48 85.64 0.37 6.07 0 2.37 0.06 0.06 0 0 0.01 0 0 0 0
Notes
Table 10 Composition of generation gas by repeat heated. gas composition
350 °C#4
350 °C#5 (repeat heated)
Hydrogen Oxygen Methane Carbon monoxide Carbon dioxide Ethylene Ethane Hydrogen sulfide Propane Propylene Isobutane N-butane Anti-butene Isobutylene Cis butene Isopentane Pentene Hexane C6+
5.62 0.81 86.43 0.23 2.76 0 3.83 0.03 0.03 0 0 0 0 0 0 0.04 0.44 0.19 0.08
7.22 1.22 84.16 0.29 4.24 0 2.84 0.02 0.02 0 0 0 0 0 0 0.04 0.43 0.19 0.08
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same. 4. Conclusions Based on experimental results and mechanism study in this research, the following conclusions can be reached: 1) Under single heavy oil condition (without water), the threshold temperature is about 250°C–280 °C, and then water can reduce the threshold pressure by about 50 °C, core reduce the threshold pressure by about 10 °C. The single heavy oil reaction products are low in strength and loose, the reaction products of aqueous condition are with gloss, and a lot of bubble pit can be found in the productions' surface, the reaction products of aqueous condition with cores are hard and brittle. 2) The regularity of the reaction results is obvious. Under the same weight heavy oil reaction conditions, the addition of water will increase the amount of reaction gas, with the core and water the reaction can generate more gas. The false high concentration can be found in the H2S results, which is because that the H2S increase does not have the same generation rate as the total gases. For the CO2 generation, however, which is far more than H2S, making CO2 concentration less influenced by the increase in the total amount of gas. And the more SO42− ion in the mimic formation water, the more H2S we can get. Analysis and calculation of gas production per 247
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Glossary API: American Petroleum Institute CSS: cyclic steam stimulation SAGD: steam-assisted gravity drainage ISC: in-situ combustion BSR: Bacterial sulfate reduction TSR: Thermochemical sulfate reduction TDS: Thermal decomposition of Sulfide R-S-R′: thioether R-SH: Mercaptan TCCM: The Clay Content in Minerals Pb: Bubble pressure mol. % H2S%: concentration of H2S mol. % CO2%: concentration of CO2 pH2S: Partial pressure of Hydrogen sulfide pCO2: Partial pressure of carbon dioxide PTotal: Total pressure of test under 350 °C(623K) Vautoclave: volume of autoclave T273,623: 0 °C(273K), 350 °C(623K) Atm: 0.1Mpa moil: the mass of heavy oil, g; VH2S: H2S volume per unitmass of heavy oil VCO2: CO2 volume per unitmass of heavy oil
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