Article pubs.acs.org/EF
Joint Industrial Case Study for Asphaltene Deposition Priyanka Juyal,*,† Amy M. McKenna,‡ Tianguang Fan,§ Tran Cao,† Rosa I. Rueda-Velásquez,∥ Jade E. Fitzsimmons,‡ Andrew Yen,† Ryan P. Rodgers,‡ Jianxin Wang,⊥ Jill S. Buckley,§ Murray R. Gray,∥ Stephan J. Allenson,† and Jefferson Creek⊥ †
Nalco Energy Services, An Ecolab Company, Sugar Land, Texas 77478, United States Ion Cyclotron Resonance Program, National High Magnetic Field Laboratory, Florida State University, Tallahassee, Florida 32310, United States § Petroleum Recovery Research Center (PRRC)/New Mexico Tech, Socorro, New Mexico 87801, United States ∥ Department of Chemical and Materials Engineering, University of Alberta, Edmonton, Alberta T6G 2V4, Canada ⊥ Chevron Energy Technology Company, Houston, Texas 77042, United States ‡
ABSTRACT: Here, we present a case study on a Wyoming well with known asphaltene deposition issues as a result of natural depletion. Field deposits and crude oil from the same well were collected for analysis. Compositional differences between field deposits, lab-generated capillary deposits, and C7-precipitated asphaltenes were determined by Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS), and all three samples show similar trends in composition, displayed as plots of aromaticity versus carbon number. An enrichment of highly condensed aromatic molecules for the field deposit is detected with both ultrahigh-resolution mass spectrometry and thermal cracking experiments and could predict asphaltene deposition. FT-ICR mass spectral analysis of solvent-extracted fractions suggest different deposition mechanisms for field deposits (slow deposition) compared to rapid precipitation in standard asphaltene preparation protocols that contain trapped maltenes.
■
INTRODUCTION The phase separation and deposition of petroleum asphaltenes during oil production, recovery, and refining operations are a well-recognized problem. For almost 100 years, petroleum research has focused on fundamental molecular properties of asphaltenes, such as molecular structure and solution-phase instability, which leads to asphaltene precipitation in reservoirs and production, transport, and storage of crude oil. Because of the enormous molecular complexity associated with heavy petroleum fractions, asphaltenes are defined by solubility behavior; asphaltenes are the fraction of crude oil that precipitates in excess paraffinic solvents (e.g., n-heptane and n-pentane) but remains soluble in aromatic solvents (e.g., toluene and benzene). Thus, the operational definition of asphaltenes encompasses a vast array of molecular types and sizes and further challenges determination of fundamental asphaltene parameters, such as solution-phase behavior and physical/chemical molecular properties. The amount, chemical composition, and structure of asphaltenes vary with precipitant type, pressure, and temperature.1 Variations in the temperature, bulk fluid composition, reservoir pressure, and processes selected to enhance oil recovery can cause asphaltene destabilization and subsequent precipitation and deposition throughout oil production. As the oil industry continues to explore deep and ultradeep water oil reserves, one trend is the increase in asphaltene instability for produced crude oils. The ability to predict the occurrence and magnitude of asphaltene deposition in wellbores is critical to forecast the related flow assurance challenges for deep and ultradeep water production. Intervention and remediation costs for asphaltene-associated deposition can heavily impact the economic value of a project, © 2013 American Chemical Society
especially in harsh subsea environments, where deposition can halt production altogether. For example, intervention costs for asphaltene removal for a land-based well up to $0.5 MM U.S. translates to more than $3 MM U.S. for off-shore well production, and the economic loss incurred as a result of lost/ deferred production can amount to $1.2 MM U.S. per day.2 Fundamental knowledge of asphaltene deposition mechanisms is crucial for efficient production strategies, infrastructure design, and development of asphaltene mitigation procedures for maximum production yields that minimize flow impedance caused by deposition in tubings and pipelines in ultradeep water resources. Asphaltene instability is often reported as precipitation or deposition interchangeably; however, the difference is welldefined. Precipitation is defined as the formation of solids from the bulk liquid phase, primarily as a function of thermodynamic variables (i.e., composition, pressure, and temperature). Deposition, however, is characterized by the formation and growth of a solid layer on a surface, primarily through flow hydrodynamics and solid−solid and solid−surface interactions.1 Precipitation is a prerequisite to asphaltene deposition, but precipitation alone does not always lead to deposition. Although nearly all crude oils report some weight fraction that is heptane-insoluble (asphaltenes), not all crude oils exhibit asphaltene precipitation that leads to deposition in production Special Issue: 13th International Conference on Petroleum Phase Behavior and Fouling Received: November 29, 2012 Revised: January 8, 2013 Published: January 8, 2013 1899
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
Energy & Fuels
Article
tubes or equipment.3−5 Although much progress has been made in the area of asphaltene precipitation onset in the past several decades, the mechanism of asphaltene deposition is still not well-understood. Flow assurance parameters, such as fluid-phase behavior and mitigation strategies, have historically relied on laboratory testing to determine, with varying success, asphaltene deposition (i.e., chemical testing).6 The addition of excess aliphatic precipitant, such as heptane, to crude oil forms a heptane-soluble fraction (maltenes) and solid-phase residue (asphaltenes).7,8 Spot test, near-infrared (NIR) spectroscopy, microscopy, and laser-based light transmittance solid detection system (SDS) are other tests to determine the onset of asphaltene precipitation and flocculation.1 The yield and physical and chemical properties of lab-generated asphaltenes have been reported to vary significantly with the alkyl chain length of the precipitant, precipitant/oil ratio, contact time with the flocculant, temperature, etc.1,9−12 Therefore, controversy exists over the accuracy of laboratory-generated asphaltenes to reflect the properties exhibited from field asphaltenes formed in live crude oil in situ. Field asphaltenes are defined as the solid (asphaltenic) material that phase separates from a live crude oil because of depressurization or commingling.1,8,9 Pressure reduction in live crude oil generated asphaltenes that differed significantly from laboratory-generated solvent-precipitated asphaltenes from a dead oil, highlighted by Joshi et al.7 Klein et al. highlighted the compositional differences between the polar fraction of precipitated asphaltenes and asphaltenes induced by depressurization with electrospray ionization (ESI) Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) and concluded that the heptane-precipitated asphaltenes contain higher double bond equivalents (DBE, number of rings plus double bonds) compared to the asphaltenes induced by pressure drop.14,15 On the other hand, the pressure-drop product exhibits a higher abundance of species containing sulfur.14,15 A Real View organic solid deposition cell (OSDC) was recently introduced to replicate live-oil conditions to simulate asphaltene precipitation and the extent and location of adhesion in the tubulars.4,5,13 Compositional differences between the OSDC deposits versus the C7precipitated asphaltenes were recently detailed with ESI FTICR MS for a Gulf of Mexico crude oil, where it was confirmed that the OSDC deposits are more polar and compositionally different from C7 asphaltenes.16 Wang et al. employed stainless-steel capillary tubes to study the effects of the temperature, degree of asphaltene instability, and precipitant molar volume on asphaltene deposition mechanisms from mixtures of stock-tank oils and nalkanes.17−19 Pressure drop across the capillary tubing was used to estimate the amount and distribution of deposit formation.17−19 However, any laboratory technique is only useful if the measurements and conclusions can be translated to the field. A detailed understanding of the relationship and processes responsible for asphaltene precipitation and deposition would improve the design of diagnostic tools and preventative techniques to reduce asphaltene deposition.17 Although extensive research across many scientific disciplines has focused on petroleum asphaltenes, a comprehensive study on one unique set of asphaltenes has yet to be reported. The variability in studied asphaltenes that are accessible to each research group has further complicated the asphaltene research. Different groups often never examine the same crude oil, and different asphaltenes are investigated with different techniques.
This sample variation results in the lack of synergy between individual research groups. Consequently, conclusions from different investigative methods cannot be correlated for effective inferences.20−22 More often than not, crude oils that exhibit no field issues with respect to asphaltene stability are studied, because they are more readily available. Here, we report a coordinated, comprehensive, multidisciplinary research investigation on a unique crude oil sample with known asphaltene deposition from a land-based well in Wyoming, U.S.A. Field deposits and crude oil from the same well were collected and distributed for independent analysis for individual asphaltene research laboratories. Our hypothesis was that the different types of solids (field deposits, lab-generated deposits, and precipitated asphaltenes) would exhibit distinct compositional differences. Preliminary analyses, such as saturates, aromatics, resins, and asphaltenes (SARA) compositional profiling and elemental analysis on the deposit, were combined with a detailed molecular-level comparison determined by ultrahigh-resolution FT-ICR mass spectral analysis through atmospheric pressure photoionization (APPI) and ESI. Asphaltene deposition was performed in a stainless-steel capillary17−19 to yield lab-generated deposits from an oil− precipitant combination, whereas precipitated asphaltenes were generated as per IP-143/90.23 The structure of the field deposit was further elucidated by thermal cracking of thin films of asphaltenes, and observations were compared to results from FT-ICR MS.
■
EXPERIMENTAL SECTION
Material. Crude oil and field deposit samples were provided from Prima Exploration, Oxbow Well Thompson 2-35, located in Wyoming, U.S.A. The produced oil is a light crude oil with almost negligible gas content [gas/oil ratio (GOR) of ∼8 standard cubic feet/stock tank barrel (scf/stb)]. This well has severe deposition issues, despite a low asphaltene content and almost no gas production. All of the solvents and reagents employed were high-performance liquid chromatography (HPLC)-grade, procured from Fischer Scientific, and were used as supplied. C7-Precipitated Asphaltenes. C7-insoluble asphaltenes from Wyoming samples were prepared per IP-143/90.22 Briefly, 500 mL of n-heptane was added to the crude oil sample (10 g), refluxed for 1 h in a 1 L round-bottom flask and stored in the dark (∼24 h). The solids (asphaltenes) were isolated by gravity filtration through Whatman (Kent, U.K.) 2V (8 μm) grade filter paper and transferred with hot nheptane. The filter paper with asphaltenes was then refluxed with nheptane at a rate of 3−5 solvent drops/min for 120 min until all asphaltenes were completely desorbed from the filter paper and the solution was colorless. The asphaltene sample was then desolvated under dry nitrogen, weighed, and redissolved in toluene to produce a stock solution of 5 mg/mL. The stock solution was further diluted to 500 μg/mL in toluene prior to APPI FT-ICR MS analysis. Asphaltene Capillary Deposition Experiments. The capillary deposition experiment has been explained in great detail in published literature.17−19 The deposition of asphaltene occurs in a long capillary tube (25−100 ft) of 0.03−0.04 in. inner diameter. Two high-pressure syringe pumps were used to inject fluids at constant flow rates. A pressure transducer was used to measure the pressure drop across the capillary tubing continuously and was recorded by a computer. The temperature of the capillary tube was controlled within ±0.5 °C by immersing the tube in a water bath. To study the asphaltene deposition in the capillary, the oil stream from pump 2 is mixed with precipitant (n-alkane) from pump 1 by flowing through a mixing node within an ultrasonic bath to ensure complete mixing. The total flow rate was maintained within a laminar flow regime. To collect deposits at the end of a deposition test, the mixed liquid (oil + precipitant) that remained inside the capillary tube was slowly displaced with nitrogen, 1900
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
Energy & Fuels
Article
under vacuum, using 0.22 μm pore size filter paper (Millipore) to remove the inorganic material and solids present in the sample. Toluene was removed by rotary evaporation, and the inorganics-free deposit was mixed in a ratio of 40:1 n-heptane/sample. This mixture was stirred for 24 h with a magnetic stir bar. The precipitated n-C7 asphaltenes were filtered out under vacuum and recovered on 0.22 μm pore size filter paper (Millipore). The asphaltenes were dried at room temperature for 48 h, then weighed, and collected. The yield of asphaltenes on the inorganics-free deposit sample was 39.1 wt %, and balance was maltenes (n-heptane solubles). The thermogravimetric analysis (TGA) residue was used to approximate the microcarbon residue (MCR) and the ash contents of the n-C7 asphaltenes [thermogravimetric analyzer Q50, TA Instruments, at the Integrated Nanosystems Research Facility (INRF) at the University of Alberta]. The temperature program that approximates the ASTM D4530 method consisted of an isothermal step at 25 °C for 10 min, followed by a ramp of 5 °C/min up to 500 °C, and then an isothermal step at this final temperature for 2 h. These steps were made with nitrogen flowing at 50 mL/min. The gas was switched to air with the same flow, and the temperature was maintained at 500 °C for 3 h. The TGA residues after the inert and oxidative thermal treatments represented the MCR and ash contents, respectively. The n-C7 asphaltenes, obtained with the procedure described above, were reacted following the same methodology already described by Rueda-Velásquez et al.41 for the cracking of asphaltenes under hydrogenation conditions that achieved a high yield of distillates with a minimal production of coke while ensuring a minimal change of the chemical structures of the cracked fragments. Thus, 15 mL stainlesssteel batch microreactors, made of nominal 3/4 in. Swagelok fittings, were loaded with approximately 4 g of 1,2,3,4-tetrahydronaphthalene (tetralin) and n-C7 asphaltenes, in a ratio of 2.5:1 solvent/sample. An iron-based catalyst, prepared by wet impregnation of FeSO4 on subbituminous coal, was added at a concentration of 2 wt %. To improve the mixing during the reaction, five 3/16 in. stainless-steel balls were also introduced into the reactor. After leak testing, the microreactor was pressurized with hydrogen at 4.1 MPa, measured at room temperature. The microreactor was immersed into a fluidized sand bath (Tecam model SBS-4, Cole-Parmer) preheated at 450 °C and was vertically agitated for a reaction time of 3 h. After the reaction, the gas, coke, and liquid products were quantitatively recovered and analyzed as described by Rueda-Velásquez et al.41
followed by several hours of drying by a high flow rate stream of nitrogen. The deposits were recovered by pumping toluene through the tube until the effluent was completely colorless. Toluene was removed from the mixture by evaporation. Finally, the deposits were vacuum-dried at 100 °C to ensure that no traces of solvent remained before the final weighing. At the end of each experimental run, the in situ deposition profile along the capillary tube was measured using a novel nondestructive technique.18,19 FT-ICR MS (9.4 T). Wyoming crude oil and fractions were analyzed with a custom-built FT-ICR mass spectrometer24 equipped with a 9.4 T horizontal 220 mm bore diameter superconducting solenoid magnet operated at room temperature (Oxford Corp., Oxney Mead, U.K.) and a modular ICR data station (PREDATOR) facilitating instrument control, data acquisition, and data analysis.25 Ions generated at atmospheric pressure were accumulated in an external linear octopole ion trap.26 ICR time-domain transients were collected from a sevensegment open cylindrical cell with capacitively coupled excitation electrodes based on the Tolmachev configuration.27,28 The 100−200 individual transients of 5.6−6.1 s collected for the crude oil were averaged, apodized with a full-Hanning (magnitude spectrum) or halfHanning (absorption mode)29 weight function, and zero-filled once prior to fast Fourier transformation. For all mass spectra, the achieved spectral resolving power approaches the theoretical limit over the entire mass range; e.g., average resolving power at m/z 500 was approximately 1 000 000 in magnitude mode and 1 300 000 in absorption mode for all ionization modes.30 Mass Calibration and Data Analysis. ICR frequencies were converted to ion masses based on the quadrupolar trapping potential approximation.31 Each m/z spectrum was internally calibrated with respect to an abundant homologous alkylation series, differing in mass by integer multiples of 14.015 65 Da (mass of a CH2 unit), confirmed by an isotopic fine structure based on the “walking” calibration equation.32 Experimentally measured masses were converted from the International Union of Pure and Applied Chemistry (IUPAC) mass scale to the Kendrick mass scale to identify a homologous series for each heteroatom class (i.e., species with the same CcHhNnOoSs content, differing only by their degree of alkylation). Peak assignments were performed by Kendrick mass defect analysis, as previously described.33 For each elemental composition, CcHhNnOoSs, the heteroatom class, type (DBE, number of rings plus double bonds involving carbon), and carbon number, c, were tabulated for subsequent generation of heteroatom class relative abundance distributions and graphical DBE versus carbon number or H/C ratio versus carbon number images. APPI. The APPI source (Thermo-Fisher Scientific, San Jose, CA) was coupled to the first pumping stage of a custom-built FT-ICR mass spectrometer (see below) through a custom-built interface.34 The tube lens was set to 50 V to minimize fragmentation of thermal ions and a heated metal capillary current of 4.5 A. A Hamilton gastight syringe (2.5 mL) and syringe pump were used to deliver the sample (50 μL/ min) to the heated vaporizer region (300 °C) of the APPI source, where N2 sheath gas (50 psi) facilitates nebulization, while the auxiliary port remained plugged. Gas-phase molecules flow out of the heated vaporizer in a confined jet, and photoionization is initiated by a krypton vacuum ultraviolet gas discharge lamp (10 eV photons, 120 nm), where photoionization occurs. Toluene increases the ionization efficiency for nonpolar aromatic compounds through dopant-assisted APPI35 through charge exchange,36 and proton-transfer reactions37,38 occur between ionized toluene molecules and neutral analyte molecules at atmospheric pressure. Protonated ions exhibit halfinteger DBE values (DBE = c − h/2 + n/2 + 1, calculated from the ion elemental composition, CcHhNnOoSs) and may thus be distinguished from radical cations with integer DBE values. ESI. Sample solutions were infused via a microelectrospray source39 (50 μm inner diameter fused silica emitter) at 400 nL/min by a syringe pump. Typical conditions for negative-ion formation were an emitter voltage of −2.5 kV, a tube lens voltage of −350 V, and a heated metal capillary current of 4 A. Positive-ion formation occurred at the same conditions as negative-ion formation but with positive values. Cracking of n-C7 Asphaltenes under Hydrogenation Conditions.40 A deposit sample was dissolved in toluene and filtered
■
RESULTS AND DISCUSSION Preliminary Oil and Deposit Analyses. Wyoming crude oil employed in this investigation is a light crude oil with a very Table 1. Crude Oil Properties and Field Background American Petroleum Institute (API) gravity (deg) GOR (scf/stb) frequency of plugging (years) reservoir temperature (°F) production rate (barrels per day) water cut (barrels per day) where the problem occurs (depth) (ft) formation hole depth (ft)
35 ∼8 2 250 10 20 asphaltenes deposit at 4000 Minnelusa 10600
Table 2. Relative Percentages (by Weight) of SARAFractionated Components of the Wyoming Crude Oil (Topped Crude Oil Sample)
1901
saturates
aromatics
resins
asphaltenes
59.56
32.76
6.95
0.73
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
Energy & Fuels
Article
was observed that a very small precipitant/oil ratio induces the onset of asphaltene flocculation for the Wyoming crude oil. Capillary Deposition Experiments. The deposition tendency of the crude oil was studied as per the procedure described in the Experimental Section. Asphaltene onset ratios for mixtures of n-alkane precipitants and stock tank oils determined by refractive index measurements were employed for capillary deposition experiments. Figure 1 shows the pressure trace for Wyoming crude oil at the flow rate of 12 mL/h in a capillary tube of 0.03 in. internal diameter and 105 ft length. The precipitant reported here is n-pentadecane (C15), and the operating parameters relating to the experiment, such as the length and diameter of the capillary tube, oil/precipitant ratio, flow rate of the oil/precipitant mixture, and experiment temperature, are also described in the inset in Figure 1. FT-ICR MS. The experimentally generated asphaltenes (capillary deposit and precipitated asphaltenes) and field deposit were subjected to FT-ICR MS investigation for a compositional comparison. FT-ICR MS represents an exemplary analytical breakthrough in terms of ultrahigh resolving power and mass accuracy, critical for unambiguous compositional information for complex organic mixtures, such as crude oil and its derivatives. For example, ultrahigh resolving power (450 000−650 000 at m/z 500) enables identification of isobaric species that differ in mass by 3.4 mDa or less, and high mass accuracy [better than 300 parts per billion (ppb) mass error] allows for molecular formula assignment to more than 30 000 peaks42 for a single heavy oil sample, making it possible to identify, sort, and monitor compositional changes simultaneously for complex petroleum samples.43 Molecular Composition: DBE versus Carbon Number. Elemental compositions determined by FT-ICR MS analysis of petroleum samples can be visualized in two-dimensional images, as previously reported.44 Figure 2 shows a comparison of select classes (hydrocarbon, S1, N1, and O1) derived from positive-ion APPI FT-ICR mass spectra of the Wyoming whole crude oil, deposits from the field and the capillary deposition experiment, and the heptane-induced precipitation as per IP143/90. Relative-abundance-weighted average carbon number and DBE (number of rings plus double bonds involving carbon) values are displayed in the lower right corner in each
Table 3. Elemental Analysis for Field Deposit, Prima Exploration, Wyoming nitrogen (%)
hydrogen (%)
carbon (%)
H/C ratio
0.5
7.6
86.0
1.06
low asphaltene content and almost negligible gas content, and the well employs a suction rod pump for production. However, severe plugging with organic deposits is reported from the producing field. It is not always easy to find a well that has asphaltene deposition problems, where the sample of the asphaltene deposit can be easily procured along with crude oil, with complete system knowledge as to where the deposition occurs and the pressure and temperature of the system. Thus, this crude oil and the deposit formed a perfect case for us to investigate and possibly learn the mechanism of asphaltene deposition from this system. Crude oil and field properties are listed in Table 1. The SARA profile of the topped crude oil is summarized in Table 2. Upon topping, 35.3% of the crude oil sample was lost. The field deposit was subjected to analyses, including solubility test, elemental analysis (C, H, and N), differential scanning calorimetry (DSC) for melting point, and X-ray diffraction for identification of the nature of the deposit. Table 3 reports the elemental analysis and the H/C ratio for the Wyoming oil field deposit. The field deposit has a H/C ratio of 1.06, indicating the primarily asphaltenic nature of the deposit. The deposit exhibited better solubility in toluene and was insoluble in heptane, consistent with the solubility behavior of asphaltenes. Some inorganic material, such as little rocks, were also found associated with the deposit. DSC thermograms (not reported here) lacked the phase transitions typical of the appearance and melting of wax crystals, ruling out the presence of wax in the field deposit. Thus, it was confirmed that the severe plugging issues with this Prima Exploration well are due to asphaltene instability and deposition. Stability evaluation on the crude oil sample with Turbiscan and flocculation point analysis showed the crude oil to be highly unstable with respect to asphaltene precipitation. Asphaltene flocculation onsets were also determined for various precipitants with refractive index measurements on mixtures of stock tank oil with the precipitants at different dilutions, and it
Figure 1. Pressure drop versus time profile for Wyoming crude oil. A total of 0.7 g of deposit was collected after drying the toluene effluent recovered from the capillary. The deposition experiment was repeated with pentadecane under a similar set of experimental parameters but with a shorter, 25 ft capillary. The experiment yielded similar results, and 0.4 g of deposit was recovered from the capillary. Elemental analysis of the deposit revealed a H/C ratio of 0.99, thus confirming the asphaltenic nature of the capillary deposit. 1902
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
Energy & Fuels
Article
Figure 2. Positive-ion APPI FT-ICR mass spectra derived relative isoabundance color- contoured plots of double bond equivalents (DBE) versus carbon number for hydrocarbon, S1, N1 and O1 class species from the Wyoming crude oil, and deposits from the field, capillary deposition experiment and heptane-precipitated asphaltenes.
an acidic or basic reagent, enabling targeted molecular level characterization of polar compounds without interference from the complex hydrocarbon matrix.45 ESI generates ions at atmospheric pressure without fragmentation and is well-suited for the analysis of complex petroleum samples and deposits. For example, in negative-ion mode ESI of petroleum, the most efficiently ionized molecules correspond to carboxylic acids, phenols, and near-neutral nitrogen-containing species, such as carbazoles. Figure 4 shows relative isoabundance colorcontoured plots of DBE versus carbon number for members of the hydrocarbon, S1, N1, and N1S1 classes for Wyoming whole crude oil and field deposit samples. An enrichment of high DBE (more aromatic) and low carbon number molecules occurs in the field deposit compared to the whole crude oil across all four heteroatom classes. A similar shift as noted with positive-ion APPI to lower carbon number can be observed for the field deposit relative to the whole crude oil. This is in accordance with the lower H/C ratio characteristic of asphaltenes. Basic Speciation by FT-ICR MS. Enrichment of aromatic molecules with relatively less alkyl substitution in the field deposit is further corroborated with the basic N1 and N1S1 classes, as observed from the isoabundance color-contoured plots of DBE versus carbon number reported in Figure 5. It appears that the aromatic species with no alkylation (or short alkyl chains) on the aromatic cores to solubilize them in the
image. For whole crude oil, members of each heteroatom class contain molecules that span a wider carbon number distribution (C70), although field deposit molecules show an increase abundance of low carbon number species (C29−C31) compared to the whole crude oil (C33−C35) and capillary deposit (C32−C34), while C7-asphaltenes range from C29 to C34 within the same heteroatom class. One explanation for the difference between the capillary deposit and field deposit is the difference in the precipitation mechanism for the two samples, because the capillary deposit was generated by n-C15, which may tend to precipitate higher molecular weight (MW) and polarity species compared to natural depletion. Calculation of the H/C ratio from assigned elemental compositions facilitates rapid comparison to bulk elemental properties within heteroatom classes. Figure 3 shows the H/C ratio versus carbon number images converted from elemental compositions for the same heteroatom classes. Field deposit molecules, on average, contain fewer carbons per molecule than whole crude oil, capillary deposit, and C7-asphaltenes within the same heteroatom class yet with the same approximate H/C ratio, indicative of condensed aromatic rings with minimal alkylation. Acidic Speciation by FT-ICR MS. ESI MS identifies polar compound classes from crude oil and its associated fractions by generation of quasi-molecular-charged species of the type (M + H)+ or (M − H)− by protonation or deprotonation affected by 1903
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
Energy & Fuels
Article
Figure 3. Isoabundance-contoured plots of H/C ratios versus carbon number for members of the hydrocarbon, S1, N1, and O1 classes for Wyoming whole crude oil, field deposit, and capillary-generated C7-asphaltenes, revealing the difference in the H/C ratios of the four samples. Relativeabundance-weighted average H/C ratios (calculated from neutral elemental compositions) and carbon number are displayed in the lower right corner of each image.
Figure 4. DBE versus carbon number plots acquired for the hydrocarbon, S1, N1, and N1S1 classes obtained from the Wyoming crude oil and the field deposit by negative-ion ESI FT-ICR MS.
1904
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
Energy & Fuels
Article
Figure 7. Comparison of DBE versus carbon number relative isoabundance color-coded contour plots for the acidic N1 class from the co-precipitate washings obtained from the Wyoming field deposit and C7-precipitated asphaltenes.
Figure 5. Relative isoabundance color-contoured plots of DBE versus carbon number for N1 and N1S1 class species from the Wyoming crude oil and the field deposit. Data derived from positive-ion ESI FT-ICR MS.
Figure 8. Yields from the reactions of n-C7 asphaltenes from the Wyoming field deposit and Athabasca n-C7 asphaltenes, made by duplicate and triplicate, respectively, under conditions of 450 °C, for 3 h, with a tetralin/asphaltenes ratio of 2.5:1 and 2% catalyst.
Figure 6 shows the evolution of the acidic N1 class at the end of the first hour and after 4, 8, 24, 48, and 72 h for the Wyoming field deposit. A comparison of negative-ion ESI FT-ICR mass spectral analysis of the co-precipitates from the Wyoming field deposit and the C7-precipitated asphaltenes is reported in Figure 7. As observed from Figure 7, the mass spectral analysis of the extract collected from 24 to 48 h shows the release of the entrained maltenic species, whereas no such observation is made for the field deposit. These data (Figures 6 and 7) show that fast flocculation as in IP-143/90 traps maltenic material, whereas a slow deposition mechanism in the field does not result in maltene entrapment in the deposit. This occlusion in asphaltene aggregates has also been reported by Strausz et al., who found less and less recovery of asphaltene solids with six successive cycles of dissolution and re-precipitation with npentane because of the loss of entrapped material.46,47 Similar observations were made with another crude oil (not reported here), which reiterated that fast flocculation as in IP-143/90 traps maltenic material in the precipitated asphaltenes. An alternate explanation would be that the highly aromatic material would give less trapping of maltenes because of the physical structure of the deposited material, such that the nature of the deposit determines trapping rather than the rate.48
Figure 6. DBE versus carbon number relative isoabundance colorcoded contour plots for the acidic N1 class from the co-precipitate washings obtained from the Wyoming field deposit.
bulk causes them to precipitate out. Peripheral alkyl substitution on aromatic molecules is also expected to provide steric hindrance toward molecular aggregation. Removal of Weakly Bound or Occluded Material in Asphaltene Aggregates. A systematic Soxhlet extraction of C7-precipitated asphaltenes and the field deposit was performed in heptane to collect co-precipitated material. The apparatus consists of a round-bottom flask filled with heptane and equipped with a Soxhlet unit connected to a reflux condenser. Extractions are performed as a function of time, and heptane exchanged at the end of the first hour and after 4, 8, 24, 48, and 72 h. The extracts collected at the end of these hours yield six co-precipitate washings. Figure 6 reports DBE versus carbon number σ plots for the acidic N1 class from a negative-ion ESI FT-ICR mass spectrum. 1905
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
Energy & Fuels
Article
Figure 9. Boiling curves obtained by simulated distillation analysis of the asphaltenes feed and the liquid products from the reactions of Wyoming field deposit and Athabasca n-C7 asphaltenes, after the removal of tetralin.
Figure 10. Conversions of vacuum residue fraction (>538 °C) and n-C7 insolubles from the reactions of Wyoming field deposit and Athabasca n-C7 asphaltenes reacted at 450 °C, for 3 h, with a tetralin/asphaltenes ratio of 2.5:1 and 2% catalyst.
obtained by Rueda-Velásquez et al.41 Furthermore, the production of material in the distillable range was only 24.5 wt %, while for Athabasca, the distillates yield was 57.4 wt %. Both samples exhibited a similar production of gases. The simulated distillation curves for Wyoming field deposit and Athabasca n-C7 asphaltenes and their liquid products recovered after the reaction and removal of tetralin are shown in Figure 9. The asphaltenes exhibited similar boiling point distributions, but the liquid products from the reaction of the Wyoming field deposit sample showed a much higher content of material in the vacuum residue range. The conversion of the vacuum residue fraction was calculated as the disappearance of the 538 °C+ material, and similarly, the n-C7 insoluble conversion was estimated from the amounts of n-C7 asphaltenes before and after the reaction. The conversions for the Wyoming field deposit are compared to Athabasca n-C7 asphaltenes in Figure 10. Somewhat higher conversions were
Thermal Cracking Experiments. The TGA analysis indicated an ash content of the n-C7 asphaltenes from the Wyoming field deposit of 0.6 wt % and a TGA residue content of 69 wt % on an ash-free basis. In contrast, the TGA residue of asphaltenes from a diverse set of heavy crude oils was 38−49 wt %.49 The much higher yield of solid residue upon thermal cracking is consistent with a high content of large aromatic groups with limited substitution by pendant ring groups.40 In Figure 8, the yields of products from the reaction of n-C7 asphaltenes from the Wyoming field deposit were compared to the results for Athabasca n-C7 asphaltenes obtained by RuedaVelásquez et al., a typical asphaltene from an asphaltic heavy crude oil.41 These reactions were performed by duplicate or triplicate, and the mass balances were above 97 wt %. The Wyoming sample produced 30.4 wt % coke, which is significantly higher than the coke yield for Athabasca and range of asphaltenes from heavy oils at identical conditions as 1906
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
Energy & Fuels
Article
obtained with Athabasca than with Wyoming field deposit n-C7 asphaltenes, consistent with a less reactive molecular structure, on average, for the latter sample. This comparison does not, however, take into account the radically different yields of coke versus distillate between the two samples (Figure 8), which indicates that a large fraction of the Wyoming field deposit sample was highly resistant to thermal change and prone to give insoluble, highly aromatic coke as a product. The pattern of coke and distillate yields is consistent with a high concentration of large condensed aromatics in the Wyoming field deposit sample.
(9) Hammami, A.; Phelps, C. H.; Monger-McClure, T.; Little, T. M. Energy Fuels 2000, 14, 14−18. (10) Speight, J. G.; Long, R. G.; Trowbridge, T. D. Fuel 1984, 63, 141−146. (11) Fuhr, B. J.; Cathrea, C.; Coates, L.; Kalra, H.; Majeed, A. I. Fuel 1991, 70, 1293−1297. (12) Hammami, A.; Chang-Yen, D.; Nighswander, J. A.; Stange, E. Fuel Sci. Technol. Int. 1995, 13 (9), 1167−1184. (13) Akbarzadeh, K.; Eskin, D.; Ratulowski, J.; Taylor, S. Energy Fuels 2012, 26, 495−510. (14) Klein, G. C.; Kim, S.; Rodgers, R. P.; Marshall, A. G.; Yen, A.; Asomaning, S. Energy Fuels 2006, 20, 1965−1972. (15) Klein, G. C.; Kim, S.; Rodgers, R. P.; Marshall, A. G.; Yen, A. Energy Fuels 2006, 20, 1973−1979. (16) Juyal, P.; Yen, A. T.; Rodgers, R. P.; Allenson, S. J.; Wang, W.; Creek, J. Energy Fuels 2010, 24, 2320−2326. (17) Wang, J.; Buckley, J. S.; Creek, J. L. J. Dispersion Sci. Technol. 2004, 25 (3), 287−298. (18) Wang, J. X.; Buckley, J. S. Estimate Thickness of Deposit Layer from Displacement Test; New Mexico Tech: Socorro, NM, June 2006; Technical Report PRRC 06-16. (19) Wang, J. X.; Creek, J. L.; Fan, T.; Buckley, J. S. Asphaltene deposit distribution in capillary tests. Proceedings of the 11th International Conference on Petroleum Phase Behavior and Fouling; Jersey City, NJ, June 13−17, 2010. (20) http://www.ualberta.ca/dept/chemeng/asphaltenes. (21) Calles, J. A.; Dufour, J.; Marugán, J.; Peña, J. L.; GiménezAguirre, R.; Merino-García, D. Energy Fuels 2008, 22, 763−769. (22) Merino-García, D.; Shaw, J.; Carrier, H.; Yarranton, H.; Goual, L. Energy Fuels 2010, 24 (4), 2175−2177. (23) Institute of Petroleum (IP). Asphaltene (heptane insolubles) in petroleum products, IP-143/90. Standards for Petroleum and Its Products; IP: London, U.K., 1985; p 143.1. (24) Kaiser, N. K.; Quinn, J. P.; Blakney, G. T.; Hendrickson, C. L.; Marshall, A. G. J. Am. Soc. Mass Spectrom. 2011, 22, 1343−1351. (25) Blakney, G. T.; Hendrickson, C. L.; Marshall, A. G. Int. J. Mass Spectrom. 2011, 306, 246−252. (26) Senko, M. W.; Hendrickson, C. L.; Emmett, M. R.; Shi, S. D.-H.; Marshall, A. G. J. Am. Soc. Mass Spectrom. 1997, 8, 970−976. (27) Tolmachev, A. V.; Robinson, E. W.; Wu, S.; Kang, H.; Lourette, N. M.; Pasa-Tolic, L.; Smith, R. D. J. Am. Soc. Mass Spectrom. 2008, 19 (4), 586−597. (28) Kaiser, N. K.; Savory, J. J.; McKenna, A. M.; Quinn, J. P.; Hendrickson, C. L.; Marshall, A. G. Anal. Chem. 2011, 83 (17), 6907− 6910. (29) Xian, F.; Hendrickson, C. L.; Blakney, G. T.; Beu, S. C.; Marshall, A. G. Anal. Chem. 2010, 82 (21), 8807−8812. (30) Marshall, A. G.; Verdun, F. R. Fourier Transforms in NMR, Optical, and Mass Spectrometry: A User’s Handbook; Elsevier Science and Technology: Amsterdam, The Netherlands, 1990. (31) Shi, S. D.-H.; Drader, J. J.; Freitas, M. A.; Hendrickson, C. L.; Marshall, A. G. Int. J. Mass Spectrom. 2000, 195/196, 591−598. (32) Savory, J. J.; Kaiser, N. K.; McKenna, A. M.; Xian, F.; Blakney, G. T.; Rodgers, R. P.; Hendrickson, C. L.; Marshall, A. G. Anal. Chem. 2011, 83 (5), 1732−1736. (33) Hughey, C. A.; Hendrickson, C. L.; Rodgers, R. P.; Marshall, A. G.; Qian, K. Anal. Chem. 2001, 73 (19), 4676−4681. (34) Purcell, J. M.; Hendrickson, C. L.; Rodgers, R. P.; Marshall, A. G. Anal. Chem. 2006, 78 (16), 5906−5912. (35) Robb, D. B.; Covey, T. R.; Bruins, A. P. Anal. Chem. 2001, 72 (15), 3653−3659. (36) Robb, D. B.; Blades, M. W. J. Am. Soc. Mass Spectrom. 2006, 17 (2), 130−138. (37) Purcell, J. M.; Hendrickson, C. L.; Rodgers, R. P.; Marshall, A. G. J. Am. Soc. Mass Spectrom. 2007, 18 (9), 1682−1689. (38) Purcell, J. M.; Rodgers, R. P.; Hendrickson, C. L.; Marshall, A. G. J. Am. Soc. Mass Spectrom. 2007, 18 (7), 1265−1273. (39) Emmett, M. R.; White, F. M.; Hendrickson, C. L.; Shi, S. D.-H.; Marshall, A. G. J. Am. Soc. Mass Spectrom. 1998, 9 (4), 333−340.
■
CONCLUSION Field deposits and crude oil from the same well were collected for analysis. Compositional differences between field deposits, lab-generated capillary deposits, and C7-precipitated asphaltenes were studied with FT-ICR MS. It is found that the field deposit shares the same compositional space with precipitated asphaltenes and the capillary deposit. An enrichment of highly aromatic components (low H/C ratio) is observed for the field deposit with thermal cracking experiments and is consistent with the mass spectral information. On the basis of the Soxhlet extraction data, it is inferred that the field deposit resulted from slow accumulation and deposition of asphaltenic species compared to the faster process as for the lab-precipitated asphaltenes. Field deposition precludes maltene entrapment, unlike n-alkane-induced precipitation in the laboratory.
■
AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. Notes
The authors declare no competing financial interest.
■
ACKNOWLEDGMENTS The authors thank Nalco Energy Services (An Ecolab Company) and Chevron Energy Technology Company for permission to publish the results in this study. FT-ICR MS analysis was supported by the National Science Foundation (NSF) Division of Materials Research through DMR-06-54118 and the State of Florida.
■
REFERENCES
(1) Hammami, A.; Ratulowski, J. In Asphaltenes, Heavy Oils and Petroelomics; Mullins, O. C., Sheu, E. Y., Hammami, A., Marshall, A. G., Eds.; Springer: New York, 2007; pp 617−676. (2) Creek, J. L. Energy Fuels 2005, 19, 1212−1224. (3) Zougari, M. J.; Jacobs, S.; Ratulowski, J.; Hammami, A.; Broze, G.; Flannery, M.; Stankiewicz, A.; Karan, K. Energy Fuels 2006, 20, 1656−1663. (4) Akbarzadeh, K.; Ratulowski, J.; Lindvig, T.; Davies, T.; Huo, Z.; Broze, G.; Howe, R.; Lagers, K. Proceedings of the SPE Annual Technical Conference and Exhibition; New Orleans, LA, Oct 4−7, 2009; SPE 124956. (5) Akbarzadeh, K.; Huo, Z.; Broze, G. World Oil 2010, February, 105−107. (6) Akbarzadeh, K.; Hammami, A.; Kharrat, A.; Zhang, D.; Allenson, S.; Creek, J.; Kabir, S.; Jamaluddin, A.; Marshall, A. G.; Rodgers, R. P.; Mullins, O. C.; Solbakken, T. Oilfield Rev. 2007, 22−43. (7) Andersen, S. I.; Manuel del Rio, M.; Khvostitchenko, D.; Shakir, S.; Lira-Galeana, C. Langmuir 2001, 17, 307−313. (8) Joshi, N. B.; Mullins, O. C.; Jamaluddin, A.; Creek, J.; McFadden, J. Energy Fuels 2001, 15, 979−986. 1907
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
Energy & Fuels
Article
(40) Gray, M. R. Energy Fuels 2003, 17, 1566−1569. (41) Rueda-Velásquez, R. I.; Freund, H.; Qian, K.; Olmstead, W. N.; Gray, M. R. Energy Fuels 2013, DOI: 10.1021/ef301521q. (42) McKenna, A. M.; Blakney, G. T.; Xian, F.; Glaser, P. B.; Rodgers, R. P.; Marshall1, A. G. Energy Fuels 2010, 24, 2939−2946. (43) McKenna, A. M.; Robbins, W. K.; Marshall, A. G. Prepr. Pap. Am. Chem. Soc., Div. Pet. Chem. 2010, 56 (1), 112. (44) Hughey, C. A.; Hendrickson, C. L.; Rodgers, R. P.; Marshall, A. G.; Qian, K. Anal. Chem. 2001, 73, 4676−4681. (45) Zhan, D.; Fenn, J. B. Int. J. Mass Spectrom. 2000, 194 (2/3), 197−208. (46) Strausz, O. P.; Lown, E. M. The Chemistry of Alberta Oil Sands, Bitumens, and Heavy Oils; Alberta Energy Research Institute (AERI): Calgary, Alberta, Canada, 2003. (47) Strausz, O. P.; Torres, M.; Lown, E. M.; Safarik, I.; Murgich, J. Energy Fuels 2006, 20 (5), 2013−2021. (48) Gray, M. R.; Tykwinski, R. R.; Stryker, J. M.; Tan, X. Energy Fuels 2011, 25, 3125−3134. (49) Karimi, A.; Qian, K.; Olmstead, W. N.; Freund, H.; Yung, C.; Gray, M. R. Energy Fuels 2011, 25, 3581−3589.
1908
dx.doi.org/10.1021/ef301956x | Energy Fuels 2013, 27, 1899−1908
