Article pubs.acs.org/EF
Experimental Measurements of Bitumen−Water Aquathermolysis during a Steam-Injection Process Na Jia,*,† Hongying Zhao,† Tao Yang,‡ Tair Ibatullin,‡,§ and Jinglin Gao† †
DBR Technology Center, Schlumberger, 9450 17th Avenue Northwest, Edmonton, Alberta T6N 1M9, Canada Statoil ASA, Forusbeen 50, 4035 Stavanger, Norway
‡
ABSTRACT: Laboratory studies and pilot project tests have shown that appreciable amounts of H2S and CO2 could be generated as a result of the aquathermolysis reaction between bitumen and steam or hot water during thermal recovery operations. A detailed experimental study was carried out to investigate the H2S generation mechanism that occurs during the recovery processes. A laboratory setup was designed and assembled that allowed for aquathermolysis tests to be carried out under controlled pressure conditions and at temperatures to 250 °C. Aquathermolysis tests on a defined ratio of bitumen and water sample were carried out at 225 and 245 °C over 3, 10, and 30 day reaction periods. Phase sampling and analysis procedures were developed to quantify the amount of H2S and CO2 generated during the individual vapor and aqueous phases. Vapor- and liquid-phase composition and bitumen properties, including viscosity and density, were analyzed after each reaction. The results of the investigation showed that the amount of H2S and CO2 generated increased with the reaction time and temperature and the CO2 concentration tended to flatten out over the test period. Data generated during the study were used to develop a kinetic model on a laboratory scale for predicting the time and temperature effects on H2S and CO2 production during the bitumen−steam/hot water aquathermolysis.
■
INTRODUCTION
reaction mechanisms of aquathermolysis at typical steam injection temperatures from 200 to 300 °C. The early research in the 1980s focused on experimental tests to identify reaction products and sources of H2S formation. Hyne et al.2 carried out aquathermolysis tests at 200, 240, and 300 °C for two heavy oil samples in H2S corrosion-resistant Hastelloy autoclave bottles and compared the results to those obtained from placing quartz tubes inside the autoclave bottles. The results were used to discuss the catalytic effect of the autoclave inner wall, which demonstrated that the rate of gas production accelerated by the metallic or metallic sulfide forms of the reaction vessel compared to those in the quartz tube. However, the equilibrium-produced gas concentration was similar for those within the quartz tube and within the Hastelloy vessel. This catalytic effect of the vessel has the advantage to reach equilibrium, which will take months or years to be achieved under field conditions, while it can be reached in the lab in only a few weeks. This study by Hyne et al.2 also found major components of the gas phase from heavy oil to be the same as the model organosulfur compounds, such as thiolane and thiophene; however, the H2S yield from oil was less because the heavy oil contains a small fraction of organosulfur compounds. No H2S production was observed for the separated sand when it was subjected to the same aquathermolysis conditions. Nevertheless, a significant amount of CO2 was produced from aquathermolysis of separated sand besides from organosulfur components. The study also found that gas production increased disproportionally in temperatures from 200 to 240 °C compared to production in the 240−300 °C temperature range.
There are more than 6 trillion barrels of heavy and extra-heavy oil under the Earth’s surface, with about 1.7 trillion barrels of heavy oil and bitumen deposited in the Western Canada Sedimentary Basin.1 In typical practice, bitumen is heated to more than 200 °C by injecting high-pressure and high-temperature steam or hot water into the reservoir to reduce viscosity, which facilitates fluid flow to the surface. During the steam-assisted recovery process, the complex chemical interactions between water, oil, and rock occur and should be considered in reservoir simulation and management. These reactions are usually regarded as “aquathermolysis” by Hyne et al.2 in the 1980s, in which “aqua” means water, “thermos” means hot, and “lysis” implies dissolution or loosening. Currently, the sour gas generations through aquathermolysis reactions are well-recognized by the industry. A figure presented by Kapadia et al.3 showed the volume of H2S generated per cubic meter of produced oil during various Athabasca bitumen steamassisted gravity drainage (SAGD) pilot programs and commercial operations, which were included in the corporate annual reports made to the Alberta Energy Resources Conservation Board (now Alberta Energy Regulator) in 2011. The data revealed that the higher the temperature, the larger the amount of H2S produced. The report stated that H2S evolution can even reach up to 400 L/m3 of bitumen. Actual field data indicated that increasing the H2S level and other sulfur emissions from the bitumen thermal recovery process was becoming a serious challenge, which, in turn, increased the expenditures to upgrade current facilities and retrofit existing plants for H2S treatment. Currently, the mechanisms of those reactions that form H2S, CO2, mercaptan, light hydrocarbon, and aqueous solutes are not fully understood by the oil and gas industry. To our knowledge, very few attempts have been made to quantitatively investigate the © 2016 American Chemical Society
Special Issue: 65th Canadian Chemical Engineering Conference Received: February 14, 2016 Revised: May 22, 2016 Published: June 13, 2016 5291
DOI: 10.1021/acs.energyfuels.6b00346 Energy Fuels 2016, 30, 5291−5299
Article
Energy & Fuels
of high-molecular-weight molecules and prevent the degradation of those components. Fan et al.11,12 conducted aquathermolysis tests in a silica tube placed inside of an autoclave to investigate the catalytic effect of minerals on the aquathermolysis reactions. Obtaining the same results as those by Montgomery et al.,7−9 Fan et al.11,12 also proved that, after aquathermolysis tests, the amount of saturate and aromatic hydrocarbons increased, while resins and asphaltenes decreased along with the oil viscosity and molecular weight (MW). In addition, Fan et al.11,12 investigated the catalytic mechanisms of minerals on the aquathermolysis of heavy oil and found that the acidic center in the surface of the mineral can lead to the formation of carbocation, where a catalytic effect can occur. The mineral catalytic effect is also due to the “dynamic indusive effect”, which can lead to the breakdown of the carbon−carbon link. Furthermore, transition metals and their oxides and sulfides contribute to the catalytic effect and lead to the breakdown of different chemical bonds. Lamoureux-Var et al.13−15 performed an aquathermolysis investigation in a gold tube with temperatures extending from 240 to 320 °C and for a test period of 24 and 203 h. Their results suggested that H2S is emitted from pyrolyzable sulfur. Furthermore, the authors also proved that asphaltenes and resins will react to form aromatics, H2S, and saturates. H2S production is higher when water is in the vapor/liquid equilibrium state, as compared to the case when water is in the liquid state. These authors proposed a series of compositional kinetic models to define sulfur components in saturates, aromatics, resins, asphaltenes, insolubles, and gas phase before and after aquathermolysis for modeling purposes. Almost all of these above-mentioned studies were performed by cooling the reactor for the sampling gas phase after completion of the aquathermolysis test, which indicates that the most representative vapor-phase samples might not have been sampled, and thus, the measurement accuracy of H2S, CO2, and hydrocarbon in the vapor phase was affected. Also, there were not many directly reported values of H2S and CO2 composition in the aqueous phase and associated water-phase properties. Furthermore, the majority of the tests were conducted in stainless-steel vessels with stainless-steel sampling valves and lines. Even when the samples were placed inside of the quartz test tubes, the H2S scavenging could not be avoided, thus affecting the accuracy of those measured H2S values. The following challenges need to be addressed to conduct quality aquathermolysis experiments. First, the reaction temperatures usually exceed 200 °C and can even reach 350 °C. Thus, an appropriate apparatus and seals are needed to meet these test requirements. Second, H2S can be easily scavenged by the stainless-steel surface; thus, the reaction bottle, lines, and sampling vessel require special design considerations. Third, the H2S and CO2 concentrations in the vapor and aqueous phase in the parts per million (ppm) to parts per billion (ppb) level need to be accurately quantified. Finally, safety is of concern because the laboratory is at conditions that include hightemperature tests, sour gas production, and steam injection, all of which need special design for the test facility, oven, and reaction vessel. The following solutions are proposed to overcome these previously mentioned challenges. First, the internal surfaces of the reaction vessel, sampling lines, and sample pycnometers are to be coated with a special inert material to minimize H2S scavenging. Second, for the H2S concentration in the vapor and aqueous phases, two analytic methods are used and compared to
The increased amount of methane and light hydrocarbon production between 240 and 300 °C indicates that thermolysis has become an increasing factor. In addition, H2S levels measured in the study by Hyne et al. lie on a reasonable extrapolation of the field data. Hyne4 proposed the principal chemical reactions, which are believed to occur in the aquathermolysis process and explored the interrelations between those reaction components. hydrolysis
organosulfur ⎯⎯⎯⎯⎯⎯⎯⎯⎯→ alcohol + mercaptan + H 2S
alcohol → aldehydes aldehydes → carbon monoxide + hydrocarbon WGSR
carbon monoxide + steam ⎯⎯⎯⎯⎯⎯→ carbon dioxide + hydrogen hydrodesulfurization
hydrogen + organosulfur + mercaptan ⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯→ H 2S
Organosulfur compounds of the heavy oil can either polymerize or react with water. The oil polymerization was due to the CO2 production in the early reaction period stage, and polymerization tends to increase oil viscosity. The presence of metal catalysts in the oil sands can affect H2S production and tends to scavenge H2S to form metal sulfides.4 The aquathermolysis “window” concept was mentioned by Hyne based on the fact that aquathermolysis is the predominant reaction between thermolysis (frequently occurs above 300 °C, with or without water) and low-temperature thermal maturization (typically occurs below 200 °C). Aquathermolysis is relatively nondestructive compared to high-temperature thermolysis reactions. Furthermore, minute or no conversion of the liquid phase to a solid deposit (coking) occurs, and gas-phase production, although important and indicative of ongoing aquathermolysis reactions, is minimal compared to behavior above 300 °C. Belgrave et al.5,6 carried out an aquathermolysis gas evolution study on selected core samples taken from three large heavy oil and bitumen deposits in Alberta. Five samples were prepared for his study; i.e., two samples of the Athabasca bitumen were mixed with different minerals, and one Athabasca oil was preoxidized before being mixed with one of the minerals. Two other bitumen samples were obtained from the North Bodo and Frisco Countess fields. The study was performed by introducing 200 g of a prepared core sample in a quartz tube that was then placed inside of the stainless-steel reactor and exposed to three test temperatures at 360, 397, and 420 °C. The Belgrave et al. study5,6 showed that low-temperature oxidation had more effect on CO and H2 production at all three temperatures but little effect on the generation of CO2. The mineralogical and reaction time do affect H2S evolution, asphaltene, and liquid oil composition. Montgomery et al.7−9 conducted laboratory aquathermolysis assessment in a 75 mL high-pressure, high-temperature reactor over a temperature range of 150−325 °C for 24 h. They found that, for a particular Alberta oil sand sample, H2S is released at temperatures above 200 °C. The post-aquathermolysis fraction tests were further separated into saturate, aromatic, resin, and asphaltene fractions. The results implied that the asphaltenes and resins are sources of sulfur. The effects of minerals on the aquathermolysis were also examined by Montgomery et al.10 for Alaska oil, and their results showed that the presence of mineral materials results in H2S generated at 50 °C lower than when no minerals were present. In addition, the results indicated that the existence of minerals promote the formation 5292
DOI: 10.1021/acs.energyfuels.6b00346 Energy Fuels 2016, 30, 5291−5299
Article
Energy & Fuels
temperatures above 200 °C without causing H2S scavenging problems in the presence of steam and/or water. As such, two 500 mL Inconel cylinders, rated to operate at a maximum of 250 °C and 10 000 psia, were designed and manufactured for the aquathermolysis tests. The interior surfaces of the cylinders, the sampling lines and valves, the end cap, the piston, and the mechanical seals were coated with a special coating material to minimize H2S scavenging. This special coating material is the result of an exclusive and joint development by Schlumberger and another company. This coating can dramatically increase hardness, enhance H2S retention time, and increase compatibility to different pH environments. The cylinders were mounted in a temperature-controlled oven (rated to 300 °C), which is capable of rocking two bottles simultaneously and also equipped with nitrogen purging, oxygen-sensing systems, and a blowout panel. A schematic of the experimental setup is shown in Figure 1. A floating piston makes the pressure control available, with a maximum system working pressure of 5000 psia. Procedures. For the aquathermolysis tests, initially, the thoroughly cleaned and evacuated bottle was heated to the test temperature and bitumen and distilled water were charged at the specified volume ratio (∼1:1). Pressure was then established and stabilized. The resulting fluid mixture was then mixed at the test temperature and pressure for the specified testing periods, where the temperature and pressure of the system were monitored to ensure stable test conditions. The fluid mixture in the cylinders was gently mixed. After the mixing stage was complete, the vapor phase evolved and the vapor−aqueous−bitumen equilibrium (VLLE) condition was observed. Gas was situated in the top section of the reaction vessel, while the aqueous phase was located between the vapor and bitumen phases, with the bitumen phase located at the bottom of the cell. To accurately quantify the composition and properties of each individual phase, the detail analysis procedures are shown in Figures 2 and 3. Vapor-Phase Analysis. A specified amount of the vapor-phase samples was isobarically displaced from the bottle (at the test temperature and pressure) into cleaned and evacuated titanium pycnometers for compositional analysis and H2S content determination. The isobarical displacement of vapor phases ensures that the phase equilibrium was not disturbed. The vapor density was measured by the gravimetric method, which is the mass difference of the pycnometer before and after sampling divided by the purged gas volume. The H2S content in the vapor phase was analyzed by a colorimetric and dry gas method. This colorimetric method is based on the reaction between H2S and a proprietary reagent developed by Schlumberger. For consistency, three vapor samples (∼10 mL each) were taken and analyzed with this method. The dry gas method uses a GC−sulfur
ensure the data quality: a reaction-based colorimetric method and a gas chromatography (GC)-based method. Third, a hightemperature oven equipped with an oxygen sensor and gas purge system within a specially designed H2S laboratory facility was set up to meet the safety requirements for the tests. After equipment was designed and set up, the following issues could be addressed: (1) quantify generated H2S, CO2, light hydrocarbons, and various sulfur-containing components as a result of aquathermolysis, with compositional analysis of the reacted oil and water as well as viscosity change as a result of the chemical reaction, (2) determine time, temperature, pressure, and composition effects of the interaction between bitumen and steam, with the effect of the reservoir rock on the aquathermolysis reaction investigated in future work, and (3) develop preliminary kinetic models for H2S and CO2 formation to model the generation of these gases in the reservoir simulation models.
■
AQUATHERMOLYSIS EXPERIMENTS
Apparatus. The unique nature of the aquathermolysis tests required a specialized laboratory design for equipment that could operate at
Figure 1. Aquathermolysis equipment setup.
Figure 2. Flowchart of the bitumen−water aquathermolysis test. 5293
DOI: 10.1021/acs.energyfuels.6b00346 Energy Fuels 2016, 30, 5291−5299
Article
Energy & Fuels
Figure 3. Phases and analysis procedure for an aquathermolysis test.
Table 2. Summary of Initial Properties of the Bitumen Sample
chemiluminescence detector (SCD) method to determine the amount of H2S in the flashed gas of a vapor phase. For the dry gas method, approximately 100 mL of vapor was purged out of the bottle and flashed to ambient temperature to collect the flashed gas. The steam in the vapor was condensed in an ice trap, while the flashed gas, referred to as “dry gas”, was collected in a gas pycnometer, and the volume and composition were measured. The condensed water was quantified by mass, and H2S and CO2 dissolved in the flashed water were estimated using Henry’s law using the constants provided in Table 1.16
analysis (wt %) bitumen water content sediment in the bitumen total sulfur of whole bitumen naphthenic acid by IR SARA saturates aromatics resins asphaltenes
Table 1. Henry’s Law Constants for H2S and CO2 Dissolved in the Flashed Water CO2 H2S
−d ln kH/d(1/T) (K)
−1 k⊖ bar−1) H (mol kg
2400 2200
0.034 0.1
result
method
0.4 0.03 5.23 0.56
Karl Fischer Titration ASTM D1796 ASTM D1552 Mobil 1463-89 ASTM D2007
17.35 40.96 20.36 21.34
The first column is used to analyze nonpolar components, and the second column is for polar components. Those two columns are connected sequentially, and there is a modulator between those two columns, which is used to refocus the effluents out of column 1 and then reinject them to column 2 for analysis. Using this two-column combination, the first dimension separation is governed by volatility (or boiling point). The separation on the second dimension is dependent upon polarity. GC × GC is a relatively recent powerful analytical technique that is particularly useful in the separation of complex petrochemical samples. GC × GC−SCD provides detailed sulfur hydrocarbon-type information for the bitumen phase. Viscosity Measurements. Viscosity measurements of the liquid oil phase were performed after the aquathermolysis tests using a capillary viscometer, which was developed and manufactured by Schlumberger. It had an operating temperature range of 10−250 °C and a pressure range of atmospheric to 34.5 MPa (14.7−5000 psia).
The analyzed results of condensed water and dry gas were then combined to determine vapor-phase composition. In addition to the vapor-phase samples for determining the H2S content, one or two vapor-phase subsamples (10−20 mL) were taken to analyze CO2 and other hydrocarbon components in the vapor phase by a gas GC analysis using an internal gas standard. After the H2S, CO2, and other hydrocarbon contents were determined from the vapor phase, the water content of the vapor phase was then calculated by subtracting the mass of H2S, CO2, and other detected hydrocarbon contents from the total weight of the vapor. The volume of the total purged vapor phase is measured by pump volume change. Water-Phase Analysis. When the vapor-phase analysis was completed, two water samples were evaluated for H2S content using the colorimetric method and another sample was analyzed for the gas/water ratio (GWR). The water-phase samples were purged under pressure (225 °C, 355−373 psia; 245 °C, 541−560 psia). The CO2 content in the pressurized water phase was calculated with Henry’s law.16 The water samples were removed from the bottle through a valve heater and into a flask immerged in an ice bath, where the water was collected. The gas was captured using a low-gas/oil ratio (GOR) apparatus set at ambient temperature and pressure conditions. When the GWR flash was complete, i.e., when no additional gas was noted, the water collected in the flask was removed and the composition of the flashed gas in the pycnometer was determined by natural gas GC. Bitumen Analysis. When the water analysis was completed, the remaining water and a small portion of the water−bitumen interface were isobarically purged from the bottle. At that time, approximately 40 mL of bitumen was displaced to a sample cylinder for viscosity measurements using a capillary viscometer. Following these viscometer measurements, oil composition was analyzed to determine C30+ by direct flash and the oil density was measured. The bitumen phase was also analyzed for properties such as total sulfur, total acid number, water content, MW, etc. Two dimensional gas chromatography with SCD (GC × GC−SCD) is used for advanced characterization of sulfur compounds in the bitumen phase. This instrument is equipped with a two-column combination.
■
DEVELOPMENT OF KINETIC MODELS Several thermal reactive reservoir models have been proposed for predicting various gas productions in the SAGD process.5,17,3,13,15,18 The main reaction for H2S generation is described by the following equation: bitumen + H 2O → H 2S + CO2 + light hydrocarbon The following first-order reaction rates were proposed as follows: rH2S = k H2S[bitumen] rCO2 = k CO2[bitumen]
In general, the reaction rate constant is expressed according to the Arrhenius relationship given by k = Ae−E / RT
where A is the frequency factor (day−1) and E is the activation energy (J/mol). Once the experimental data for the aquathermolysis tests are available, through gas concentrations at different times and temperatures, the activation energy and 5294
DOI: 10.1021/acs.energyfuels.6b00346 Energy Fuels 2016, 30, 5291−5299
Energy & Fuels
■
frequency factor were estimated by the following equations: ⎛ T1 ln k T − T2 ln k T ⎞ 1 2 A = exp⎜ ⎟ T1 − T2 ⎝ ⎠
E=
(1/T1) − (1/T2)
where T is in kelvin and k is in day−1. Table 3. MW of the Total Sulfur Content of SARA Fractions result
units
method
MW saturates aromatics resins asphaltenes saturates aromatics resins asphaltenes
367 433 730 2663
g/mol g/mol g/mol g/mol Total Sulfur 200 °C) and with pressure control. (2) A unique experimental setup was designed that minimizes H2S scavenging and allows for large test fluid sample volumes (up to 500 mL) for analysis along with safety features. (3) Vapor, water, and oil phases could be in-situ-sampled independently, allowing for compositional and property measurements for each interested phase. Accurate measurements of vapor-phase composition were achieved with two self-verified methods. (4) Over the course of the test reaction time, the pressure increase indicated the formation of gas, including H2S and CO2. The increased reaction time resulted in higher H2S generation and flattening of the CO2 concentration after 30 days. (5) An increased reaction temperature resulted in higher H2S and CO2 generation. (6) An experimentally measured H2S content agrees with values generated by the commercial and pilot SAGD operation. (7) Kinetic parameters for H2S and CO2 generation were developed on the basis of the measured values.
■
AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. Present Address §
Tair Ibatullin: Shell Global Solutions Canada, Inc., 400 4th Avenue Southwest, Calgary, Alberta T2P 0J4, Canada. Notes
The authors declare no competing financial interest.
■
ACKNOWLEDGMENTS The authors acknowledge Statoil ASA and Schlumberger for their permission to present and publish this work. Also, the authors thank Joshua Cassidy and Donald Sieben of Schlumberger Reservoir Laboratory in Edmonton for performing the experimental work.
■
REFERENCES
(1) Kapadia, P. R.; Kallos, M. S.; Gates, I. D. Fuel Process. Technol. 2015, 131, 270−289. (2) Hyne, J. B.; Clark, P. D.; Clarke, R. A.; Koo, J.; Greidanus, J. W.; Tyrer, J. D.; Verona, D. Rev. Tec. INTEVEP 1982, 2 (2), 87−94. 5299
DOI: 10.1021/acs.energyfuels.6b00346 Energy Fuels 2016, 30, 5291−5299
