A Geological Model for the Origin of Fluid Compositional Gradients in

Aug 18, 2015 - Saudi Aramco, Dhahran 31311, Saudi Arabia. § Schlumberger, Sugar Land, Texas 77478, United States. ∥ Woods Hole Oceanographic Instit...
0 downloads 8 Views 2MB Size
Download PDF
Subscriber access provided by UNIV OF CALIFORNIA SAN DIEGO LIBRARIES

Article

A geological model for the origin of fluid compositional gradients in a large Saudi Arabian Oilfield: an investigation by GC×GC and asphaltene chemistry Jerimiah C. Forsythe, Andrew E Pomerantz, Douglas J. Seifert, Kang Wang, Yi Chen, Julian Youxiang Zuo, Robert K. Nelson, Christopher M. Reddy, Arndt Schimmelmann, Peter E. Sauer, Kenneth E. Peters, and Oliver C. Mullins Energy Fuels, Just Accepted Manuscript • Publication Date (Web): 18 Aug 2015 Downloaded from http://pubs.acs.org on August 19, 2015

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a free service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are accessible to all readers and citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

Energy & Fuels is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

Page 1 of 30

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

A geological model for the origin of fluid compositional gradients in a large Saudi Arabian Oilfield: an investigation by GC×GC and asphaltene chemistry Jerimiah C. Forsythe1*, Andrew E. Pomerantz1, Douglas J. Seifert2, Kang Wang3, Yi Chen3, Julian Y. Zuo3, Robert K. Nelson4, Christopher M. Reddy4, Arndt Schimmelmann5, Peter Sauer5, Kenneth E. Peters6, Oliver C. Mullins1 1. 2. 3. 4. 5. 6.

Schlumberger-Doll Research, Cambridge, MA 02139, USA Saudi Aramco, Dhahran 31311, Saudi Arabia Schlumberger, Sugar Land, TX 77478, USA Woods Hole Oceanographic Institution, Woods Hole, MA 02543, USA Indiana University, Bloomington, IL 47405, USA Schlumberger, SIS, CA, 94941, USA

*corresponding author, email: [email protected] Abstract The heavy oil rim of a large Saudi Arabian oilfield has been shown to be in vertical and lateral equilibrium, matching predictions of the gravity term from the Flory-Huggins-Zuo equation of state for asphaltenes in the form of 5.2 nm clusters of the Yen-Mullins model. The large (10x) vertical gradient of asphaltene concentration over a very large perimeter (>> 10 km) of the oilfield provided a stringent test of this equation of state fit. Two-dimensional gas chromatography (GC×GC) and stable isotope analysis δD and δ13C were used to determine consistency of the liquid phase components with equilibration and the effects of biodegradation or thermal maturity on the observed asphaltene gradient. These analyses confirm homogeneity of equilibrated liquid phase components of similar chemical character and equilibrated asphaltene isotopes. Biodegradation is minimal and there is no maturity variation among the samples. Thus, the large asphaltene gradient did not result from these secondary processes and is not remnant from how the reservoir charged with crude oil. The results are consistent with original findings that the oil column is equilibrated. Thermodynamic equilibration over such large distances (>10 km) requires convective currents and provides constraints on fluid dynamic processes in reservoirs. A simple 1-D three-component single-phase model is introduced to account for asphaltene accumulation by way of convective currents established from a diffusive gas front at the top of the oil column. Introduction The composition of crude oils within a reservoir is typically not homogenous, even within specific segments or within the local vicinity of vertical depths. Instead, gradients in fluid composition are typically observed. These gradients can impact fluid viscosity, gas/oil ratio (GOR), and phase transition pressures, all of which can have an effect of production. Reservoir fluids are a complex mixture of components, ranging from liquids, dissolved gases, and 1 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 2 of 30

dissolved or colloidally suspended solids or asphaltenes. Determination of fluid composition and complexities can aid in deciphering origins of fluid gradients and permit appropriate planning for reservoir production. There are several mechanisms that can create variations in fluid composition gradients. Differences in the thermal maturity level of reservoir fluids can result in a gradient. Fluids are generated and expelled from source rock at different levels of thermal maturity, and those fluids have varying compositions. For example, fluids generated early in the process (low maturity) are relatively heavy in composition while fluids generated later in the process (high maturity) are relatively light.1 These fluids typically migrate to the top of the reservoir through a high permeability streak or charge plane, and then fill the reservoir from the top down.2 As a result of this charge history, heavier fluids typically are found at the base of a reservoir while lighter fluids are found higher in a reservoir. Active secondary processes can occur during or after the reservoir is filled. These processes can occur locally, preferentially altering the composition of fluids in a specific region of the reservoir and therefore creating gradients. If the temperature of a reservoir is low enough, active biodegradation can occur, which can create gradients in two steps: a fast step involving consumption of low molecular-weight labile compounds (e.g., n-alkanes) at the oil-water contact, while a slow step requires diffusion of labile compounds through the oil column to the oil-water contact. An example of this is the Bhagyam field, a shallow reservoir that was initially filled with crude oil approximately 50 million years ago.3 A large (8x) asphaltene gradient is observed in the reservoir and was formed by a diffusive gradient of biodegraded oil at the base of the oil column. This reservoir demonstrates how slow diffusion of components over geological time can establish large viscosity gradients.3 In some cases, the reservoir can become warmer with subsidence, thereby slowing or halting biodegradation, which can result in local equilibration of components.4 If sufficient geological time passes and if the reservoir is not subject to compositional alteration (e.g., by biodegradation) then thermodynamic equilibrium can sometimes be attained. At equilibrium, there is no change in reservoir properties or composition in time, no fluxes of any kind, and no changes in chemical potential. In many cases, different crude oil components equilibrate at different rates.5 For example, asphaltene distributions can often reach equilibrium in a shorter period of time than liquid phase hydrocarbons and biomarkers.6 Many reservoirs exhibit such partial equilibrium where some components of the crude oil have attained equilibrium distributions while other components have not. It is important to check the extent of equilibrium of all fluid components in reservoir crude oils; there are corresponding significant implications for reservoir evaluation. Here, an intensively studied large Saudi Arabian field with a large gradient in asphaltene content (10x) is investigated with the goal of understanding which of the above three mechanisms is mainly responsible for the gradient. The field occurs in a four-way sealing 2 ACS Paragon Plus Environment

Page 3 of 30

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

anticline with black oil with moderate asphaltene content in the crest and heavy oil with higher asphaltene content along the perimeter. 7-9 The height of the heavy oil column is about 150 feet (45 m) as shown in Fig. 1. The heavy oil is underlain by a ~ 33 feet (10 m) tar mat, with an aquifer under the tar. The reservoir is assumed to consist of one compartment, as determined by pressure analysis in production testing. Fig. 1 shows the measured asphaltene content of the mobile heavy oil vs. height of the oil column from multiple wells around the field as depicted in Fig. 1 inset.9

Figure 1. Multi-well asphaltene measurements made across eight wells in this reservoir, represented as a green oval in the insert. Depth, in feet, is expressed as true vertical depth subsea (TVDss) with the first two digits obscured to preserve reservoir anonymity. The FHZ EoS (Equation 1) was used to fit the blue squares of mobile heavy oil, resulting in 5.2 nm cluster sizes. The red squares represent measurements on black oil above the mobile heavy oil; nanoaggregate size of 2.0 nm was obtained from FHZ EoS fitting. It is desirable to perform additional validation of the equilibrium analysis of the asphaltene gradients in Fig. 1 for this reservoir. In this paper, chemical attributes of the asphaltenes are evaluated, specifically isotope ratios of hydrogen and carbon. In addition, detailed compositional analyses of the liquid phase components of the various crude oil samples were performed for multiple purposes. First, the extent of homogeneity of chemically similar biomarkers was used as an indicator of liquid phase equilibration. Second, compositional analyses were used to probe the impact of alternative mechanisms that affect asphaltene gradients in oilfield reservoirs. Specifically, two-dimensional comprehensive gas chromatography with flame ionization detection (GC×GC-FID) and two-dimensional comprehensive gas chromatography with time of flight mass spectrometry (GC×GC-TOFMS) were used to evaluate the extent of biodegradation at various points in this reservoir. The extent of biodegradation can be described using the Peters and Moldowan (PM, 1993) scale. In addition, the extent of oil maturity variation is determined vertically to probe the likelihood that observed gradients originate from large variations in the thermal maturity of the crude oils that originally charged into the reservoir. All measurements support the equilibrium analysis of this oil column. Finally, we propose a 1-D three-component single phase model to account for convective flow of asphaltenes via a density inversion created by a flux of gas at the top of the oil column. Simulations show that asphaltenes can accumulate at the front of the gas flux, create 3 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 4 of 30

conditions for convective flow to occur, and eventually deposit a tar mat at the base of the reservoir. Flory-Huggins-Zuo Model for Asphaltene Equilibrium Distributions Historically, reservoir fluid gradients have been examined through geochemical fingerprinting. In recent years, the measurement of asphaltene gradients has become routine in the oil industry with the aid of “downhole fluid analysis” (DFA). The cubic equation of state (EoS) is often used to model gas-liquid equilibria of reservoir crude oils. Asphaltene gradients are modeled with the Flory-Huggins-Zuo EoS (FHZ EoS). Application of the FHZ EoS relies on resolution of the molecular and nanocolloidal structure of asphaltenes as given by the YenMullins model. In many reservoirs, equilibrated asphaltenes have been identified as a strong indicator of reservoir connectivity, one of the largest concerns in oilfield development. Thermodynamic modeling of fluids provides insight into important properties of reservoir architecture. Fluid modeling also provides insight into variations of fluid properties. The heavy oil gradient was fit to the gravity term (Eq. 1) of the FHZ EoS; for low GOR crude oils, the gravity term dominates.5,10-11

OD(h2 ) φa (h2 )  v g(ρ − ρa )(h2 − h1 )  = = exp a  OD(h1 ) φa (h1 ) RT  

1.

where OD, R, φ, v, T, g, ρ, and h are the optical density, universal gas constant, volume fraction, molar volume, temperature, gravitational acceleration, mass density and depth, respectively. Subscript a denotes the properties of asphaltenes; h1 and h2 stand for the properties at depths h1 and h2, respectively. Optical density or oil color is linear in asphaltene content and is used in downhole fluid analysis to determine relative asphaltene content. Eq. 1 is essentially the barometric equation that describes the atmospheric pressure gradient, except that the equation uses asphaltene Archimedes buoyancy rather than mass. The size of the asphaltene particle, va, comes from the Yen-Mullins model shown in Fig. 2. For heavy oil, the asphaltenes are generally dispersed as asphaltene clusters with a nominal diameter of 5.0 nm (cf. Fig. 2). The good fit of Eq. 1 to the oilfield data, coupled with the single parameter being so close to expectations (5.2 nm vs. 5.0 nm), strongly suggests that in terms of asphaltene content, the heavy oil around this oilfield is in thermodynamic equilibrium.

4 ACS Paragon Plus Environment

Page 5 of 30

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Figure 2. The Yen-Mullins model for asphaltenes shows the dominant molecular structure and colloidal species.12-14 The nanoaggregate (2.0 nm) has about six molecules and the cluster (5.0 nm) contains about eight nanoaggregates. Black oils have asphaltenes in 2.0 nm nanoaggregates while heavy oils have at least some asphaltenes in 5.0 nm clusters of nanoaggregates. The existence of asphaltene clusters have been indicated by a variety of measurements. Combined X-ray scattering (SAXS) and small angle neutron scattering (SANS) showed both nanoaggregates and clusters of asphaltenes. The aggregation number of each was found to be about 10.15-17 The critical cluster concentration (CCC) was shown to be several grams per liter (asphaltene in toluene) by analysis of flocculation kinetics.18-19 DC-conductivity experiments and centrifugation show congruence with both small cluster aggregation numbers (depicted as eight clusters in Fig. 2) and with the CCC.20 Nuclear magnetic resonance (NMR) experiments confirmed this cluster size.21-22 In particular, by determining that 15% of the alkane chains experience hindered motion, a cluster aggregation number of six was obtained.22 The nanoaggregate to cluster transition with increasing concentration has also been indicated in interfacial studies.23 The “island” 1.5 nm molecular architecture depicted in Fig. 2 with a single polycyclic aromatic hydrocarbon (PAH) per molecule previously proposed by time resolved fluorescence polarization studies 24-25 has been confirmed by laser desorption, laser ionization mass spectrometry (L2MS).26-27 Further evidence for 1.5 nm asphaltene structures has been observed in tandem mass spectrometry coupled with collisional activation decomposition,28 in interfacial studies at an oil-water interface,29-31 and in sum-frequency generation experiments.32 2.0 nm nanoaggregates of about seven molecules have also been confirmed by SALDI-MS.26,33 These weakly bound nanoaggregates are readily disrupted. In toluene, the critical nanoaggregate concentration (CNAC) has been determined by high-Q ultrasonics,34 DC-conductivity,35 NMR,36 centrifugation,37 and mass spectrometry.38 In addition to validating the asphaltene model in Fig. 2, it is essential to validate the use of this model along with Eq. 1 to fit the asphaltene gradient in Fig. 1 for this reservoir. Previous studies on asphaltenes from this reservoir have confirmed that no change is observed in the vertical and lateral asphaltene chemistry within the oil column depicted in Fig. 1. Sulfur X-ray absorption near-edge structure (XANES) studies demonstrated that the thiophene fraction of sulfur dominates and does not vary within the reservoir, supporting the use of Eq. 1 for asphaltene clusters.7,26 Additionally, L2MS and SALDI-MS were used to determine that there is no observed variation in molecular weight or nanoaggregate weight for the asphaltenes in this reservoir.33 Thus, the large variation of asphaltenes with height correlates with different concentrations of asphaltenes as given by the barometric equation for asphaltene clusters, not from a large chemical change in the asphaltenes. 5 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 6 of 30

Sample Preparation Six downhole oil samples from three wells in a Saudi Arabian anticlinal closure holding a black oil were flashed to remove volatile components ( 10 km) would require a time frame of longer than the age of the universe (~ 1 trillion years), so is ruled out. The hypothesis presented here is that convective currents rich in asphaltenes caused an accumulation of asphaltenes at the base of the reservoir. This accumulation was largely laterally invariant. Convective currents, as shown from simulations, can be induced through a charge of methane into the top of the reservoir, creating a diffusive front of denser oil containing a higher concentration of asphaltenes than the oil lower in the column. As the gradient of higher asphaltene oil moves down the column, there will be a point at which the solvent capacity of the crude oil for asphaltenes is exceeded and the solid asphaltenes will plate out as a solid on the rock surface of the bottom of the reservoir, thereby precluding an impermeable tar mat and 24 ACS Paragon Plus Environment

Page 25 of 30

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

precluding any permeability. Therefore, we conclude that the large compositional gradient observed here results from gravitational segregation of asphaltenes from the liquid components. Many oilfields are observed to be subject to such asphaltene-enriched gravity currents and can be evaluated by an integrated method of dynamic and thermodynamic modeling coupled with laboratory analysis.

Supporting Information This information is available free of charge via the Internet at http://pubs.acs.org/

25 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 30

Appendix Abbreviation Ts Tm NH NM H 29-norhopane M G HH (S) HH (R) 2HH (S) 2HH (R) 3HH (S) 3HH (R) 4HH (S) 4HH (R) 5HH (S) 5HH (R) 2α-Me-Ts 2α-Me-Tm 2α-Me-NH 2α-Me-H 2α-Me-HH 2α-Me-2HH 2α-Me-3HH C27 sterane 1 (C27 αββ-20R) C27 sterane 2 (C27 αββ-20S) C27 sterane 3 (C27 ααα-20R) C28 sterane 4 (C28 ααα-20S) C28 sterane 5 (C28 αββ-20R) C28 sterane 6 (C28 αββ-20S) C28 sterane 7 (C28 ααα-20R) C29 sterane 8 (C29 ααα-20S) C29 sterane 9 (C29 αββ-20R) C29 sterane 10 (C29 αββ-20S) C29 sterane 11 (C29 ααα-20R)

Compound Name 18α(H)-22, 29, 30-trinorneohopane 17α(H)-22, 29, 30-trinorhopane 17α(H), 21β(H)-30-norhopane 17β(H), 21α(H)-norhopane 17α(H), 21β(H)-hopane 18α(H),21β(H)-30-norneohopane 17β(H), 21α(H)-hopane Gammacerane 17α(H),21β(H)-22(S)-homohopane 17α(H),21β(H)-22(R)-homohopane 17α(H),21β(H)-22(S)-bishomohopane 17α(H),21β(H)-22(R)-bishomohopane 17α(H),21β(H)-22(S)-trishomohopane 17α(H),21β(H)-22(R)-trishomohopane 17α(H),21β(H)-22(S)-tetrakishomohopane 17α(H),21β(H)-22(R)-tetrakishomohopane 17α(H),21β(H)-22(S)-pentakishomohopane 17α(H),21β(H)-22(R)-pentakishomohopane 2α-methyl-Ts 2α-methyl-Tm 2α-methyl-NH 2α-methyl-H 2α-methyl-HH 2α-methyl-2HH 2α-methyl-3HH 5α(H),14β(H),17β(H)-20R-cholestane 5α(H),14β(H),17β(H)-20S-cholestane 5α(H),14α(H),17α(H)-20R-cholestane 24-methyl-5α(H),14α(H),17α(H)-20S-cholestane 24-methyl-5α(H),14β(H),17β(H)-20R-cholestane 24-methyl-5α(H),14β(H),17β(H)-20S-cholestane 24-methyl-5α(H),14α(H),17α(H)-20R-cholestane 24-ethyl-5α(H),14α(H),17α(H)-20S-cholestane 24-ethyl-5α(H),14β(H),17β(H)-20R-cholestane 24-ethyl-5α(H),14β(H),17β(H)-20S-cholestane 24-ethyl-5α(H),14α(H),17α(H)-20R-cholestane

Formula C27H46 C27H46 C29H50 C29H50 C30H52 C29H50 C30H52 C30H52 C31H54 C31H54 C32H56 C32H56 C33H58 C33H58 C34H60 C34H60 C35H62 C35H62 C28H49 C28H49 C30H53 C31H55 C32H57 C33H59 C34H61 C27H48 C27H48 C27H48 C28H50 C28H50 C28H50 C28H50 C29H52 C29H52 C29H52 C29H52

26 ACS Paragon Plus Environment

Page 27 of 30

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

References 1. Tissot, B. P.; Welte, D. H., Petroleum Formation and Occurence. Springer-Verlag: New York, 1984. 2. Stainforth, J. G. New insights into reservoir filling and mixing processes Geological Society, London, Special Publications 2004, 237 (1), 115-132. 3. Zuo, J. Y.; Jackson, R.; Agarwal, A.; Herold, B.; Kumar, S.; Santo, I. D.; Dumont, H.; Ayan, C.; Beardsell, M.; Mullins, O. C. Diffusion Model Coupled with the Flory–Huggins–Zuo Equation of State and Yen–Mullins Model Accounts for Large Viscosity and Asphaltene Variations in a Reservoir Undergoing Active Biodegradation Energy Fuels 2015, 29 (3), 1447-1460. 4. Pomerantz, A. E.; Ventura, G. T.; McKenna, A. M.; Cañas, J. A.; Auman, J.; Koerner, K.; Curry, D.; Nelson, R. K.; Reddy, C. M.; Rodgers, R. P.; Marshall, A. G.; Peters, K. E.; Mullins, O. C. Combining biomarker and bulk compositional gradient analysis to assess reservoir connectivity Org. Geochem. 2010, 41 (8), 812-821. 5. Freed, D. E.; Mullins, O. C.; Zuo, J. Y. Heuristics for Equilibrium Distributions of Asphaltenes in the Presence of GOR Gradients Energy Fuels 2014, 28 (8), 4859-4869. 6. Mullins, O. C.; Wang, K.; Kauerauf, A.; Zuo, J. Y.; Chen, Y.; Dong, C.; Elshahawi, H. Evaluation of Coexisting Reservoir Fluid Gradients of GOR, Asphaltene and Biomarkers as Determined by Charge History in Reservoir Fluid Geodynamics; SPWLA, Ann. Symp.; Long Beach, CA, 2015. 7. Pomerantz, A. E.; Seifert, D. J.; Bake, K. D.; Craddock, P. R.; Mullins, O. C.; Kodalen, B. G.; Mitra-Kirtley, S.; Bolin, T. B. Sulfur Chemistry of Asphaltenes from a Highly Compositionally Graded Oil Column Energy Fuels 2013, 27 (8), 4604-4608. 8. Mullins, O. C.; Seifert, D. J.; Zuo, J. Y.; Zeybek, M. Clusters of Asphaltene Nanoaggregates Observed in Oilfield Reservoirs Energy Fuels 2013, 27 (4), 1752-1761. 9. Mullins, O. C.; Seifert, D. J.; Zuo, J. Y.; Zeybek, M.; Zhang, D.; Pomerantz, A. E. Asphaltene Gradients and Tar Mat Formation in Oil Reservoirs; World Heavy Oil Congress; Aberdeen, Scotland, 2012. 10. Freed, D. E.; Mullins, O. C.; Zuo, J. Y. Theoretical Treatment of Asphaltene Gradients in the Presence of GOR Gradients Energy Fuels 2010, 24 (7), 3942-3949. 11. Zuo, J. Y.; Mullins, O. C.; Freed, D.; Elshahawi, H.; Dong, C.; Seifert, D. J. Advances in the Flory–Huggins–Zuo Equation of State for Asphaltene Gradients and Formation Evaluation Energy Fuels 2013, 27 (4), 1722-1735. 12. Mullins, O. C. The Modified Yen Model Energy Fuels 2010, 24 (4), 2179-2207. 13. Mullins, O. C.; Sabbah, H.; Eyssautier, J.; Pomerantz, A. E.; Barré, L.; Andrews, A. B.; RuizMorales, Y.; Mostowfi, F.; McFarlane, R.; Goual, L.; Lepkowicz, R.; Cooper, T.; Orbulescu, J.; Leblanc, R. M.; Edwards, J.; Zare, R. N. Advances in Asphaltene Science and the Yen–Mullins Model Energy Fuels 2012, 26 (7), 3986-4003. 14. Mullins, O. C.; Pomerantz, A. E.; Zuo, J. Y.; Dong, C. Downhole Fluid Analysis and Asphaltene Science for Petroleum Reservoir Evaluation Annu. Rev. Chem. Biomol. Eng. 2014, 5 (1), 325-345. 15. Eyssautier, J.; Levitz, P.; Espinat, D.; Jestin, J.; Gummel, J.; Grillo, I.; Barré, L. Insight into Asphaltene Nanoaggregate Structure Inferred by Small Angle Neutron and X-ray Scattering J. Phys. Chem. B 2011, 115 (21), 6827-6837. 16. Eyssautier, J.; Hénaut, I.; Levitz, P.; Espinat, D.; Barré, L. Organization of Asphaltenes in a Vacuum Residue: A Small-Angle X-ray Scattering (SAXS)–Viscosity Approach at High Temperatures Energy Fuels 2012, 26 (5), 2696-2704. 17. Eyssautier, J.; Espinat, D.; Gummel, J.; Levitz, P.; Becerra, M.; Shaw, J.; Barré, L. Mesoscale Organization in a Physically Separated Vacuum Residue: Comparison to Asphaltenes in a Simple Solvent Energy Fuels 2012, 26 (5), 2680-2687. 18. Anisimov, M. A.; Yudin, I. K.; Nikitin, V.; Nikolaenko, G.; Chernoutsan, A.; Toulhoat, H.; Frot, D.; Briolant, Y. Asphaltene Aggregation in Hydrocarbon Solutions Studied by Photon Correlation Spectroscopy J. Phys. Chem. 1995, 99 (23), 9576-9580. 27 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 28 of 30

19. Yudin, I.; Anisimov, M., Dynamic Light Scattering Monitoring of Asphaltene Aggregation in Crude Oils and Hydrocarbon Solutions. In Asphaltenes, Heavy Oils, and Petroleomics, Mullins, O.; Sheu, E.; Hammami, A.; Marshall, A., Eds. Springer New York: 2007; pp 439-468. 20. Goual, L.; Sedghi, M.; Zeng, H.; Mostowfi, F.; McFarlane, R.; Mullins, O. C. On the formation and properties of asphaltene nanoaggregates and clusters by DC-conductivity and centrifugation Fuel 2011, 90 (7), 2480-2490. 21. Korb, J.-P.; Louis-Joseph, A.; Benamsili, L. Probing Structure and Dynamics of Bulk and Confined Crude Oils by Multiscale NMR Spectroscopy, Diffusometry, and Relaxometry J. Phys. Chem. B 2013, 117 (23), 7002-7014. 22. Dutta Majumdar, R.; Gerken, M.; Mikula, R.; Hazendonk, P. Validation of the Yen–Mullins Model of Athabasca Oil-Sands Asphaltenes using Solution-State 1H NMR Relaxation and 2D HSQC Spectroscopy Energy Fuels 2013, 27 (11), 6528-6537. 23. Lobato, M. D.; Pedrosa, J. M.; Möbius, D.; Lago, S. Optical Characterization of Asphaltenes at the Air−Water Interface Langmuir 2009, 25 (3), 1377-1384. 24. Groenzin, H.; Mullins, O. C. Asphaltene Molecular Size and Structure J. Phys. Chem. A 1999, 103 (50), 11237-11245. 25. Groenzin, H.; Mullins, O. C. Molecular Size and Structure of Asphaltenes from Various Sources Energy Fuels 2000, 14 (3), 677-684. 26. Pomerantz, A. E.; Wu, Q.; Mullins, O. C.; Zare, R. N. Laser-Based Mass Spectrometric Assessment of Asphaltene Molecular Weight, Molecular Architecture, and Nanoaggregate Number Energy Fuels 2015. 27. Sabbah, H.; Morrow, A. L.; Pomerantz, A. E.; Zare, R. N. Evidence for Island Structures as the Dominant Architecture of Asphaltenes Energy Fuels 2011, 25 (4), 1597-1604. 28. Tang, W.; Hurt, M. R.; Sheng, H.; Riedeman, J. S.; Borton, D. J.; Slater, P.; Kenttämaa, H. I. Structural Comparison of Asphaltenes of Different Origins Using Multi-stage Tandem Mass Spectrometry Energy Fuels 2015, 29 (3), 1309-1314. 29. Rane, J. P.; Harbottle, D.; Pauchard, V.; Couzis, A.; Banerjee, S. Adsorption Kinetics of Asphaltenes at the Oil–Water Interface and Nanoaggregation in the Bulk Langmuir 2012, 28 (26), 99869995. 30. Rane, J. P.; Pauchard, V.; Couzis, A.; Banerjee, S. Interfacial Rheology of Asphaltenes at Oil– Water Interfaces and Interpretation of the Equation of State Langmuir 2013, 29 (15), 4750-4759. 31. Pauchard, V.; Rane, J. P.; Zarkar, S.; Couzis, A.; Banerjee, S. Long-Term Adsorption Kinetics of Asphaltenes at the Oil–Water Interface: A Random Sequential Adsorption Perspective Langmuir 2014, 30 (28), 8381-8390. 32. Andrews, A. B.; McClelland, A.; Korkeila, O.; Demidov, A.; Krummel, A.; Mullins, O. C.; Chen, Z. Molecular Orientation of Asphaltenes and PAH Model Compounds in Langmuir−Blodgett Films Using Sum Frequency Generation Spectroscopy Langmuir 2011, 27 (10), 6049-6058. 33. Wu, Q.; Seifert, D. J.; Pomerantz, A. E.; Mullins, O. C.; Zare, R. N. Constant Asphaltene Molecular and Nanoaggregate Mass in a Gravitationally Segregated Reservoir Energy Fuels 2014, 28 (5), 3010-3015. 34. Andreatta, G.; Bostrom, N.; Mullins, O. C. High-Q Ultrasonic Determination of the Critical Nanoaggregate Concentration of Asphaltenes and the Critical Micelle Concentration of Standard Surfactants Langmuir 2005, 21 (7), 2728-2736. 35. Zeng, H.; Song, Y.-Q.; Johnson, D. L.; Mullins, O. C. Critical Nanoaggregate Concentration of Asphaltenes by Direct-Current (DC) Electrical Conductivity† Energy Fuels 2009, 23 (3), 1201-1208. 36. Lisitza, N. V.; Freed, D. E.; Sen, P. N.; Song, Y.-Q. Study of Asphaltene Nanoaggregation by Nuclear Magnetic Resonance (NMR)† Energy Fuels 2009, 23 (3), 1189-1193. 37. Mostowfi, F.; Indo, K.; Mullins, O. C.; McFarlane, R. Asphaltene Nanoaggregates Studied by Centrifugation† Energy Fuels 2009, 23 (3), 1194-1200.

28 ACS Paragon Plus Environment

Page 29 of 30

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

38. McKenna, A. M.; Donald, L. J.; Fitzsimmons, J. E.; Juyal, P.; Spicer, V.; Standing, K. G.; Marshall, A. G.; Rodgers, R. P. Heavy Petroleum Composition. 3. Asphaltene Aggregation Energy Fuels 2013, 27 (3), 1246-1256. 39. Gaines, R. B.; Frysinger, G. S.; Hendrick-Smith, M. S.; Stuart, J. D. Oil Spill Source Identification by Comprehensive Two-Dimensional Gas Chromatography Environ. Sci. Technol. 1999, 33 (12), 2106-2112. 40. Reddy, C. M.; Eglinton, T. I.; Hounshell, A.; White, H. K.; Xu, L.; Gaines, R. B.; Frysinger, G. S. The West Falmouth Oil Spill after Thirty Years:  The Persistence of Petroleum Hydrocarbons in Marsh Sediments Environ. Sci. Technol. 2002, 36 (22), 4754-4760. 41. Reddy, C. M.; Nelson, R. K.; Sylva, S. P.; Xu, L.; Peacock, E. A.; Raghuraman, B.; Mullins, O. C. Identification and quantification of alkene-based drilling fluids in crude oils by comprehensive twodimensional gas chromatography with flame ionization detection J. Chromatogr. A 2007, 1148 (1), 100107. 42. Frysinger, G. S.; Gaines, R. B.; Xu, L.; Reddy, C. M. Resolving the Unresolved Complex Mixture in Petroleum-Contaminated Sediments Environ. Sci. Technol. 2003, 37 (8), 1653-1662. 43. Schimmelmann, A. http://mypage.iu.edu/~aschimme/compounds.html. 44. Brand Willi, A.; Coplen Tyler, B.; Vogl, J.; Rosner, M.; Prohaska, T., Assessment of international reference materials for isotope-ratio analysis (IUPAC Technical Report). In Pure Appl. Chem., 2014; Vol. 86, p 425. 45. Schimmelmann, A.; DeNiro, M. J. Elemental and stable isotope variations of organic matter from a terrestrial sequence containing the Cretaceous/Tertiary boundary at York Canyon, New Mexico Earth. Planet. Sci. Lett. 1984, 68 (3), 392-398. 46. Schimmelmann, A.; Sessions, A. L.; Mastalerz, M. Hydrogen isotopic (D/H) composition of organic matter during diagenesis and thermal maturation Annu. Rev. Earth Planet. Sci. 2006, 34 (1), 501533. 47. Mullins, O. C.; Zou, J. Y.; Wang, K.; Hammond, P. S.; De Santo, I.; Dumont, H.; Mishra, V.; Chen, L.; Pomerantz, A. E.; Dong, C.; Elshahawi, H.; Seifert, D. J. The Dynamics of Reservoir Fluids and Their Substantial Systematic Variations; Society of Petrophysicists and Well Log Analysts 55th Annual Logging Symposium; Abu Dhabi, United Arab Emirates, May 18-22; Abu Dhabi, United Arab Emirates, 2014. 48. Betancourt, S. S.; Ventura, G. T.; Pomerantz, A. E.; Viloria, O.; Dubost, F. X.; Zuo, J.; Monson, G.; Bustamante, D.; Purcell, J. M.; Nelson, R. K.; Rodgers, R. P.; Reddy, C. M.; Marshall, A. G.; Mullins, O. C. Nanoaggregates of Asphaltenes in a Reservoir Crude Oil and Reservoir Connectivity Energy Fuels 2009, 23 (3), 1178-1188. 49. Zuo, J. Y.; Mullins, O. C.; Mishra, V.; Garcia, G.; Dong, C.; Zhang, D. Asphaltene Grading and Tar Mats in Oil Reservoirs Energy Fuels 2012, 26 (3), 1670-1680. 50. Seifert, D. J.; Moldowan, J. M., Use of biological markers in petroleum exploration. In Methods in Geochemistry and Geophysics, Johns, R. B., Ed. Elsevier: Amsterdam, 1986; pp 261-290. 51. Mullins, O. C., The Physics of Reservoir Fluids: Discovery Through Downhole Fluid Analysis. Schlumberger: Sugar Land, TX, 2008. 52. Peters, K. E.; Walters, C. C.; Moldowan, J. M., The Biomarker Guide: Biomarker and Isotopes in Petroleum Exploration and Earth History. Prentice Hall: Englewood Cliffs, New Jersey, 2005; Vol. 2. 53. Farrimond, P.; Bevan, J. C.; Bishop, A. N. Hopanoid hydrocarbon maturation by an igneous intrusion Org. Geochem. 1996, 25 (3–4), 149-164. 54. Seifert, W. K.; Moldowan, J. M.; Smith, G. W.; Whitehead, E. V. First proof of structure of a C28-pentacyclic triterpane in petroleum Nature 1978, 271 (5644), 436-437. 55. Kolaczkowska, E.; Slougui, N.-E.; Watt, D. S.; Maruca, R. E.; Michael Moldowan, J. Thermodynamic stability of various alkylated, dealkylated and rearranged 17α- and 17β-hopane isomers using molecular mechanics calculations Org. Geochem. 1990, 16 (4–6), 1033-1038. 56. McKirdy, D. M.; Kantsler, A. J.; Ypma, P. J. M., A geochemical comparison of some crude oils from Pre-Ordovician carbonate rocks. John Wiley & Sons: New York, 1983. 29 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 30 of 30

57. Rullkötter, J.; Aizenshtat, Z.; Spiro, B. Biological markers in bitumens and pyrolyzates of Upper Cretaceous bituminous chalks from the Ghareb Formation (Israel) Geochim. Cosmochim. Acta 1984, 48 (1), 151-157. 58. Holba, A. G.; Wright, L.; Levinson, R.; Huizinga, B.; Scheihing, M., Effects and impact of earlystage anaerobic biodegradation on Kuparuk River Field, Alaska. Geological Society of London: 2004; p 397. 59. Winters, J. C.; Williams, J. A. Microbiological alteration of crude oil in the reservoir; American Chemical Society, Divison of Petroleum Chemistry; New York Meeting Preprints, New York Meeting Preprints, 1969; pp E22-E31. 60. Peters, K. E.; Moldowan, J. M.; McCaffrey, M. A.; Fago, F. J. Selective biodegradation of extended hopanes to 25-norhopanes in petroleum reservoirs. Insights from molecular mechanics Org. Geochem. 1996, 24 (8–9), 765-783. 61. Goodwin, N. S.; Park, P. J. D.; Rawlinson, T., Crude oil biodegradation. John Wiley & Sons: New York, 1983. 62. Oliveira, C. R.; Ferreira, A. A.; Oliveira, C. J. F.; Azevedo, D. A.; Santos Neto, E. V.; Aquino Neto, F. R. Biomarkers in crude oil revealed by comprehensive two-dimensional gas chromatography time-of-flight mass spectrometry: Depositional paleoenvironment proxies Org. Geochem. 2012, 46 (0), 154-164. 63. Hill, R. J.; Schenk, C. J. Petroleum geochemistry of oil and gas from Barbados: Implications for distribution of Cretaceous source rocks and regional petroleum prospectivity Mar. Pet. Geol. 2005, 22 (8), 917-943. 64. Hildebrand, J.; Scott, R. L., The Solubility of Nonelectrolytes. 3rd ed.; Reinhold, New York, 1950. 65. Hildebrand, J.; Scott, R. L., Regular Solutions. Prentice-Hall Inc.: Englewood Cliffs, NJ, 1962. 66. Hansen, C. M., Hansen solubility parameters: a user's handbook. CRC press: 2007.

30 ACS Paragon Plus Environment