Article pubs.acs.org/EF
Simple Relative Sorptivity Model of Petroleum Expulsion Alan K. Burnham*,† and Robert L. Braun‡ †
Department of Energy Resources Engineering, Stanford University, 367 Panama Street, Stanford, California 94305, United States GeoIsoChem Corporation, 738 Arrow Grand Circle, Covina, California 91722, United States
‡
S Supporting Information *
ABSTRACT: That the timing of petroleum expulsion from a source rock is strongly influenced or even dominated by expulsion from kerogen has its roots a half-century ago and is very widely accepted. Similarly, solubility and swelling theory is commonly used to explain the compositional differences between retained and expelled oil. This paper proposes and implements a simple sorption−expulsion algorithm based on the twin concepts of maximum sorption capacity and relative sorptivities of lumped chemical classes in immature kerogen and on residual kerogen (semicoke). Sorption capacity as a function of kerogen composition is estimated from published swelling and adsorption data, and relative sorptivities are estimated from several published hydrous and semiopen pyrolysis data sets. The model is implemented in a compositional kinetic simulator, PMod2, which treats open and closed system pyrolysis as well as a relative sorptivity model for geological expulsion. Although not as rigorous as the models based on Flory−Rehner and regular solution theories, the empirical approach used here is more easily calibrated within the context of compositional chemical kinetic models for which the molecular speciation of the lumped species is limited. Improved compositional models are derived for type I (organofacies C) and type II (organofacies B) organic matter, and model calculations are compared to laboratory and field data. Although the models could be improved to agree closer with any given set of data, they generally agree well with experimental results over a very wide range of conditions, including isothermal pyrolysis at 470 °C, slow pyrolysis in both open and closed systems, and the preferential expulsion of hydrocarbons from source rocks.
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INTRODUCTION A detailed understanding of oil and gas generation developed during the second half of the 20th century. Although it was not unambiguously established until the 1970s that petroleum forms thermogenically from kerogen-rich, fine-grained rock, the 1980s showed rapid improvement in mathematical models of petroleum generation within and expulsion from source rock. Even so, the seeds of modern computer simulation of petroleum generation and expulsion were sown in the 1960s. An important observation by Philippi1 from that era was that the threshold for expulsion from source rocks seemed to be about 100 mg/g of insoluble TOC in the rock, and this threshold was cited in the classic work of Pepper and Corvi.2 In parallel, other workers (e.g., Hunt3 and Sandvik et al.4) focused on selective expulsion of hydrocarbons from and selective retention of aromatics and polar NSOs in source rock. In addition, work on swelling of coal, related to liquefaction efforts in response to a perceived incipient shortage of petroleum, advanced understanding of Flory−Rehner and regular solution theories,5−7 and that understanding was subsequently applied to the selective expulsion of hydrocarbons from oilprone kerogen,8−10 culminating in the work of Kelemen and co-workers11−13 and Walters et al.14,15 Some laboratory generation experiments also simulated the selective expulsion of hydrocarbons during pyrolysis. Hydrous pyrolysis is particularly well-known in this regard,16 but slow semiopen pyrolysis at elevated pressure produces a similar result.17 Consequently, liquid water appears to play a secondary role to other factors for producing this fractionation. Burnham et al.18 and Burnham19 calculated partition coefficients between expelled and retained phases for various lumped © XXXX American Chemical Society
oil species from both hydrous and semiopen pyrolysis as a function of the extent of kerogen conversion. Over a wide range of time, temperature and conversion, the ratio of specific compound groups approximately followed parallel 1/T relationships, and the slope might be interpreted as an enthalpy of evaporation or transport. The magnitude of the partition coefficient depended on the molecular weight and polarity of the oil fraction, with lower molecular weights and lower polarity enabling greater expulsion from the source rock. The current work is based on the long-standing observation that both expulsion efficiency and sorption and swelling propensity depend on the characteristics of lumped chemical species and the composition of the kerogen. First, we define sorption to be the sum of absorption and adsorption, where the former is defined as molecular dissolution and the latter is defined as molecules sticking to a rigid surface. Reality, of course, is a bit more complicated. For immature, hydrogen-rich kerogen, sorption is dominated by absorption, which is reflected in the amount of swelling upon immersion. As the kerogen matures, its structure becomes microporous and rigid, so adsorption and capillary condensation is the more appropriate physical description. For simplicity, we lump capillary condensation within adsorption. The model presented here presumes that intermediate maturities can be represented by a mixture of immature and fully mature kerogen, and the total sorption can be represented by a two-tank successive spill model. This is clearly an approximation, and the algorithm could be easily extended to Received: June 26, 2017 Revised: August 2, 2017
A
DOI: 10.1021/acs.energyfuels.7b01815 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels Table 1. Chemical Reaction Model for Green River Oil Shalea rxn
reactant
1
KER1 k1 k2 k3 KER2 k4 k5 k6 KER3 k7 HO3 k8 MO3 k9 MO2 k10 MO1 k11 LO1 k12 LO2 k13 CHX k14 COK1 k15 k16 k17 k18 k19 k20 k21 k22 COK2 k23 k24
2
3 4 5 6 7 8 9 10 11
12
fi
Ai
Ei
0.3 0.5 0.2
5 × 1013 5 × 1013 5 × 1013
47 49 51
0.2 0.6 0.2
5 × 1013 5 × 1013 5 × 1013
50 52 54
1.0
5 × 1013
53
1.0
5 × 1013
53
1.0
5 × 1012
51
1.0
2 × 1013
54
1.0
3 × 1013
58
1.0
1 × 1013
58
1.0
1 × 1010
49
1.0
2 × 1012
58
0.20 0.20 0.17 0.14 0.11 0.08 0.06 0.04
1 × 1014 1 × 1014 1 × 1014 1 × 1014 1 × 1014 1 × 1014 1 × 1014 1 × 1014
56 58 60 62 64 66 68 70
0.7 0.3
1 × 1014 1 × 1014
56 58
products HO3 0.44 0.44 0.44 HO3 0.70 0.70 0.70 MO3 0.26 MO3 0.26 MO1 0.15 LO1 0.30 LO1 0.65 CHX 0.50 CH4 0.15 CH4 0.70 CH4 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 CHX 1.0 1.0
MO2 0.11 0.11 0.11 MO3 0.20 0.20 0.20 MO2 0.14 MO2 0.14 LO1 0.25 LO2 0.25 LO2 0.05 CH4 0.20 COK3 0.85 COK3 0.30
MO1 0.11 0.11 0.11 COK1 0.008 0.008 0.008 MO1 0.22 MO1 0.22 LO2 0.15 CHX 0.10 CHX 0.10 COK1 0.025
CO2 0.20 0.20 0.20 COK2 0.005 0.005 0.005 LO2 0.04 LO2 0.04 CHX 0.10 CH4 0.05 CH4 0.05 COK2 0.015
CH4 0.02 0.02 0.02 COK3 0.087 0.087 0.087 LO1 0.04 LO1 0.04 CH4 0.05 COK1 0.025 COK1 0.012 COK3 0.26
COK1 0.010 0.010 0.010
COK2 0.005 0.005 0.005
COK3 0.105 0.105 0.105
CHX 0.05 CHX 0.05 COK1 0.025 COK2 0.015 COK2 0.008
CH4 0.010 CH4 0.010 COK2 0.015 COK3 0.26 COK3 0.13
COK1 0.010 COK1 0.010 COK3 0.26
COK2 0.010 COK2 0.010
COK3 0.22 COK3 0.22
Ai and Ei are the frequency factor (s−1) and activation energy (kcal/mol), respectively, for each reaction channel, and f i is the mass fraction of the reactant that is governed by those parameters. The coefficients in the product columns are the mass fraction of each product produced from each reaction channel. Product definitions are given in Table 3.
a
the totality of immature kerogen but excludes recycled dead carbon. Coke (also known in the literature as semicoke, char, and residual kerogen), denoted by Cok, represents mature kerogen and recycled dead carbon (unreactive kerogen) that has expended all oil potential but still has the capability to generate methane as aromatic groups continue to consolidate without a change in adsorption capacity. The reactive kerogen and coke each have different specified total sorptive capacities for oil and gas, and the relative sorptivities for oil and gas species in and on reactive kerogen and coke are specified independently for each oil and gas species. The first step is to specify the concentration of organic matter in the rock:
any number of successive tanks if there were sufficient data to constrain the parameters. The Pepper−Corvi2 concept presumes that oil is expelled into the intergranular porosity, through which it migrates quickly relative to the time scale for generation. (They define first step as expulsion and the physical fluid flow process as “primary migration” within and out of the source bed, although others use the terms differently.) This mechanism is conceptually different from both the sorption−permeation model of McAuliffe20 and the sorption−diffusional fractionation model of Stainforth,21,22 both of which presume primary migration through a continuous organic network. Distinguishing between the various competing mechanisms is difficult, and multiple approaches can be adapted in a general sense to give similar predictions. The current work makes no claim about proving one mechanism over the other. That scope of investigation remains for future work.
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MODEL DESCRIPTION The following section gives the governing equations of the expulsion model. Reactive kerogen, denoted by Ker, represents B
S Ker = mg of Ker /g of rock
(1)
SCok = mg of Cok /g of rock
(2)
Wio = mg of Oili /g of rock
(3)
Wig = mg of Gasi /g of rock
(4) DOI: 10.1021/acs.energyfuels.7b01815 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels Table 2. Chemical Reaction Model for Type II Marine Source Rocka rxn
reactant
1
KER1 k1 k2 k3 k4 KER2 k5 k6 k7 k8 KER3 k9 k10 k11 k12 k13 k14 HO3 k15 k16 k17 k18 k19 k20 MO3 k21 MO2 k22 MO1 k23 LO1 k24 LO2 k25 CHX k26 COK1 k27 k28 k29 k30 k31 k32 k33 k34 COK2 k35 k36
2
3
4
5 6 7 8 9 10 11
12
fi
Ai
Ei
0.4 0.3 0.2 0.1
1.6 × 1014 1.6 × 1014 1.6 × 1014 1.6 × 1014
48 50 52 54
0.10 0.25 0.50 0.15
1.6 × 1014 1.6 × 1014 1.6 × 1014 1.6 × 1014
48 50 52 54
0.05 0.15 0.20 0.30 0.25 0.05
1.6 × 1014 1.6 × 1014 1.6 × 1014 1.6 × 1014 1.6 × 1014 1.6 × 1014
50 51 52 53 54 55
0.05 0.15 0.20 0.30 0.25 0.05
1.6 × 1014 1.6 × 1014 1.6 × 1014 1.6 × 1014 1.6 × 1014 1.6 × 1014
50 51 52 53 54 55
1.0
1 × 1013
51
1.0
2 × 1013
54
1.0
3 × 1013
58
1.0
1 × 1013
58
1.0
1 × 1010
49
1.0
2 × 1012
58
0.22 0.20 0.17 0.13 0.10 0.08 0.06 0.04
1 × 1014 1 × 1014 1 × 1014 1 × 1014 1 × 1014 1 × 1014 1 × 1014 1 × 1014
55 57 59 61 63 65 67 69
0.6 0.4
1 × 1014 1 × 1014
55 57
products CO2 1.00 1.00 1.00 1.00 HO3 0.80 0.80 0.80 0.80 MO3 0.15 0.15 0.15 0.15 0.15 0.15 MO3 0.15 0.15 0.15 0.15 0.15 0.15 MO1 0.15 LO1 0.30 LO1 0.65 CHX 0.50 CH4 0.15 CH4 0.70 CH4 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 CHX 1.00 1.00
MO3 0.20 0.20 0.20 0.20 MO2 0.14 0.14 0.14 0.14 0.14 0.14 MO2 0.14 0.14 0.14 0.14 0.14 0.14 LO1 0.25 LO2 0.25 LO2 0.05 CH4 0.20 COK3 0.85 COK3 0.30
MO1 0.03 0.03 0.03 0.03 0.03 0.03 MO1 0.03 0.03 0.03 0.03 0.03 0.03 LO2 0.15 CHX 0.10 CHX 0.10 COK1 0.025
LO2 0.03 0.03 0.03 0.03 0.03 0.03 LO2 0.03 0.03 0.03 0.03 0.03 0.03 CHX 0.10 CH4 0.05 CH4 0.05 COK2 0.015
LO1 0.04 0.04 0.04 0.04 0.04 0.04 LO1 0.04 0.04 0.04 0.04 0.04 0.04 CH4 0.05 COK1 0.025 COK1 0.014 COK3 0.26
CHX 0.03 0.03 0.03 0.03 0.03 0.03 CHX 0.03 0.03 0.03 0.03 0.03 0.03 COK1 0.025 COK2 0.015 COK2 0.006
CH4 0.02 0.02 0.02 0.02 0.02 0.02 CH4 0.02 0.02 0.02 0.02 0.02 0.02 COK2 0.015 COK3 0.26 COK3 0.13
COK1 0.035 0.035 0.035 0.035 0.035 0.035 COK1 0.035 0.035 0.035 0.035 0.035 0.035 COK3 0.26
COK2 0.015 0.015 0.015 0.015 0.015 0.015 COK2 0.015 0.015 0.015 0.015 0.015 0.015
COK3 0.51 0.51 0.51 0.51 0.51 0.51 COK3 0.51 0.51 0.51 0.51 0.51 0.51
Ai and Ei are the frequency factor (s−1) and activation energy (kcal/mol), respectively, for each reaction channel, and f i is the mass fraction of the reactant that is governed by those parameters. The coefficients in the product columns are the mass fraction of each product produced from each reaction channel. Product definitions are given in Table 3.
a
To simulate pure reactive kerogen, the initial value of SKer would be 1000. The concentrations of these species evolve over time through chemical reactions and expulsion, and the following equations specify how to calculate expulsion from the kerogen after each chemical kinetic calculation. In the current implementation, the transport of oil and gas expelled from the kerogen is assumed to be instantaneous, so expulsion from kerogen and expulsion from the rock are synonymous, which is the assumption by Pepper and Corvi.2 Consequently,
we call the current model the enhanced Pepper−Corvi model, because it merely adds compositional selectivity to the original Pepper−Corvi model via relative sorptivities. However, one could add a sequential mass transport step within matrix permeability using Darcy’s law with relative permeabilities or some other more sophisticated pore storage and flow model to simulate the situation where fluid-phase saturation and overpressure can build up, as in the productive organic-rich “shale” reservoirs. C
DOI: 10.1021/acs.energyfuels.7b01815 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels
because the following equations provide normalization, but the specific coding in PMod2 uses values between 0 and 1. The function P proportions the relative amounts of sorption for each species Oili and Gasi on Ker and Cok. It is given by
Table 3. Definitions and Initial Concentrations of Organic Components species
description
KER1
labile biomarkers and early gas KER2 asphaltenes precursor KER3 direct oil and gas precursor HO3 asphaltenes (soluble kerogen) MO3 C14−C35 polars (resins) MO2 C14−C35 alkyl aromatics MO1 C14−C35 aliphatics LO1 C5−C13 aliphatics LO2 C5−C13 methylated aromatics CHX C2−C4 CH4 methane CO2 carbon dioxide COK1 methane precursor in semicoke COK2 C2−C4 precursor in semicoke COK3 final coke
fraction of organic fraction of organic matter matter for type II source for Green River oil shale rock 0.05
0.04
0.44 0.44
0.39 0.48
0.04
0.05
0.02
0.02
0.005
0.005
0.005 0.0 0.0
0.005 0.005 0.005
0.0 0.0 0.0 0.0
0.0 0.0 0.0 0.0
0.0
0.0
0.0
0.0
n Ker Ker Pi Ker = WR i i / ∑ WR i i
(9)
i=1
n Cok Cok Pi Cok = WR /∑ WR i i i i
(10)
i=1
This is a standard weighted averaging procedure commonly found in many applications. These functions assume no secondorder interactions among species in the competition for available sorption sites. The next step toward oil expulsion is calculating the maximum sorption capacity, B, for each species Oili and Gasi on Ker and Cok. These capacities are given by Bi Ker = 0.001 S KerC KerPi Ker (mg/g of rock)
(11)
BiCok = 0.001 SCokC CokPi Cok (mg/g of rock)
(12)
At this point, whatever oil and gas species exceed the sorption capacity of Ker and Cok, as calculated in a sequential fashion, are expelled If Wi < Bi Ker , Di Ker = Wi = amount of oil or gas species i absorbed by Ker (mg/g of rock)
(13)
If Wi ≥ Bi Ker , Di Ker = Bi Ker = amount of oil or gas species i absorbed by Ker (mg/g of rock)
(14a)
and Yi = Wi − Bi Ker = oil available for sorption on Cok or expulsion (mg/g of rock)
(14b)
If Yi < BiCok , Figure 1. Summary of oil cracking rate constants for the various oil fractions. The relative cracking rates of light aromatics and aliphatics cross at a temperature of about 350 °C, which is consistent with selective concentration of methylated aromatics at industrial cracking temperatures and selective concentration of paraffins at geological temperatures.
DiCok = Yi = amount of oil or gas species i absorbed by Cok (mg/g of rock) If Yi ≥ BiCok , DiCok = BiCok = amount of oil or gas species i
The following equations drop the subscript for oil and gas. Two concurrent sets of calculations for oil and gas are implied. First, the sorptive capacities and relative sorptivities are specified
absorbed by Cok (mg/g of rock)
(mg/g of rock)
(5)
R i Ker = relative sorptivity of Oili or Gasi on Ker
Ri
Cok
= relative sorptivity of Oili or Gasi on Cok
(16b)
Although the sequential calculation determines separate sorption quantities for Ker and Cok, they are a computational convenience and are not physically meaningful. Therefore, the only sorption value that is relevant is the sum of the two
C Cok = sorptive capacity for oil or gas on Cok (expulsion threshold for Cok) = (mg/g of Cok)
(16a)
and Xi = Wi − Di Ker − DiCok = oil or gas expelled
C Ker = sorptive capacity for oil or gas on Ker (expulsion threshold for Ker ) = (mg/g of Ker )
(15)
(6) (7)
Di = Di Ker + DiCok = total amount of oil or gas species i
(8)
sorbed on Ker and Cok
Here, relative sorptivity can be based on any desired relative scale, with the most sorptive species having the largest value,
(17)
These equations were implemented as the enhanced Pepper− Corvi expulsion model in the global chemical kinetic model D
DOI: 10.1021/acs.energyfuels.7b01815 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels
Figure 2. Lumped products from open and closed system pyrolysis of type I (GROS is Green River oil shale; organofacies C) and type II (organofacies B) organic matter at a constant heating rate of 2 °C/h.
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BASIC KINETIC CALCULATIONS For the purposes of this demonstration, chemical reaction models for type I and type II kerogen were adapted from earlier work,49,25 including the addition of species to model saturates, aromatics, and polars (NSOs).26 They are described in more detail in Tables 1−3. Unlike in the original PMOD code, PMod2 does not require elemental balance, so details such as elimination of water and fate of nitrogen and sulfur during maturation are neglected. However, the PMOD models were used as a guide for the stoichiometry, so elemental balance is followed qualitatively. The initial oil species are what is conventionally called native bitumen. A similar portion of the kerogen (KER1) generates early oil rich in biomarkers, CO2, and a little methane.27 One portion of the kerogen (KER2) decomposes first to asphaltenes and some resins, while the other portion (KER3) decomposes directly to oil. This is clearly an approximation, but the intent is to choose a ratio of KER2 to KER3 that can match the maximum concentration of asphaltenes or, similarly, polars insoluble in pentane but soluble in methylene chloride. The equivalence of the decomposition parameters for KER3 and HO3 is necessary to honor the observation that the maximum rate of oil generation for high-temperature isothermal pyrolysis occurs at initial time. Oil cracking kinetics are based on results from Burnham,19 Behar et al.,28 and references therein. The rate constants at temperatures ranging from industrial cracking to geological maturation are shown in Figure 1. The oil cracking network incorporates the observation that the relative rates of cracking of saturates and coking of aromatics cross at about 350 °C, which is consistent with selective concentration of methylated aromatics
Table 4. Comparison of Calculated Vitrinite Reflectance (Easy%Ro) at the Maximum Concentration of Various Chemical Species for Green River and Type II Organic Mattera species C2−C5 C6−C13 C13+ aromatics C6−C13 C14+ saturates C6−C13 C14+ hydrocarbons resins asphaltenes
Monin et al . (1900)
Behar et al . (2008)
Behar and Jarvie (2013)*
type II model
1.96 1.12 0.75 0.84
>1.1 >1.1 0.80 0.93 >1.1 0.93 >1.1 >1.1 >1.1 ≥1.1 0.80 0.72
>1.3 >1.3 0.75,0.9
2.14 1.35 0.79 0.95 1.32 0.93 1.32 1.41 1.17 1.10 0.81 0.71
1.01
0.68 0.68
∼0.95
∼1.3 >1.3 0.8 0.7
a
For Behar and Jarvie, when values for the Barnett and Posidonia shales are different, the first number is for the Barnett.
simulator PMod2, which can also simulate open and closed systems.23 The code also calculates Rock-Eval parameters based on whether a given “oil” species is volatile or nonvolatile, and if nonvolatile, the calculation includes subsequent decomposition steps. In addition, the Easy%Ro algorithm24 calculates vitrinite reflectance for the simulated thermal history. This provides a semiquantitative way to compare results from diverse thermal histories using an index of equivalent thermal stress, maturity, or severity (nomenclature depends on discipline). E
DOI: 10.1021/acs.energyfuels.7b01815 Energy Fuels XXXX, XXX, XXX−XXX
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Figure 3. Generation rates of oil, methane, and C2−C4 hydrocarbons (CHx) as a function of temperature in an open-system at a constant heating rate of 2 °C/h. These should be compared with the numerous measurements of type I and type II evolution profiles of Reynolds et al.35
Figure 4. Generation of oil for isothermal open-system pyrolysis at a temperature relevant to ex situ retorts. GROS is Green River oil shale.
coefficients. The sorption capacities and relative sorptivities of the fluid species are given in Table 5 and justified in the following paragraphs.
at industrial cracking temperatures and selective concentration of saturates at geological temperatures. One noteworthy item is that the activation energy of alkane cracking is based on isotopically doped hexadecane29 in an oil matrix rather than pure compounds. The oil cracking kinetics are the same in both models, except that cracking of MO3 is two times faster for the Type II source, in addition to differences in HO3 parameters. Open and closed system calculations at a constant heating rate of 2 °C/h are shown in Figure 2, and they agree well with published experiments to within the range of variability within various formations (reviewed in Chapter 6 of Burnham,19 particularly Evans and Felbeck30 and Behar et al.31 for Green River oil shale and Monin et al.32 and Behar et al.33,34 for type II kerogen). In a closed system, the maximum yield of NSOs (HO3 + MO3 = asphaltenes + resins = polars) is about 30% and occurs at 0.9%Ro for Green River organic matter and 0.8%Ro for type II organic matter. The maximum hydrocarbon yield (LO1 + LO2 + MO1 + MO2) is 48% at 1.2%Ro for Green River oil shale and 32% at 1.1%Ro for type II organic matter. Further comparisons for maximum concentrations of various lumped species are given in Table 4. Differences of one in the carbon number of the cut point are ignored. Open system product evolution profiles are shown in Figure 3 for oil, CH4, and C2−C4 hydrocarbons. The shift to higher temperature for methane relative to oil and C2−C4 is consistent with results from Reynolds et al.35 Isothermal pyrolysis at 470 °C is shown in Figure 4, and the results agree well with data reviewed in Chapter 4 of Burnham.19
Table 5. Assumed Values for Sorption Capacities and Relative Sorptivities
species total EOMa HO3 MO3 MO2 MO1 LO1 LO2 total Gas CO2 CH4 CHX a
immature GRS kerogen, mg/g
immature type II kerogen, relative mg/g sorptivity
900
700
mature kerogen, mg/g 150
1.00 0.90 0.30 0.25 0.25 0.30 50
relative sorptivity
50
1.00 0.90 0.50 0.25 0.25 0.50 30
1.0 0.2 1.0
1.0 0.2 1.0
Extractable organic matter.
For absorption in immature kerogen, the maximum swelling ratio is approximately 0.8 + 0.5 × H/C (from Burnham19 as derived from Larsen et al.8−10 and Kelemen et al.12) Green River kerogen, for which H/C is 1.50−1.55 has a swelling ratio of about 1.55. Converting this to a mass basis involves a fluid density, which depends on composition, temperature, and pressure. Also, polar aromatic material, which has a greater density, is preferentially absorbed. Unfortunately, all available swelling data is for unconfined kerogen, and lithostatic load will likely reduce swelling. Consequently, one can only estimate that the maximum
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EXPULSION CALCULATIONS The basis for the expulsion models is the assumption that release of oil and gas from kerogen as a function of maturity is based on absorption at low maturity and adsorption at high maturity, where the maximum absorption and adsorption capacities of all species and the relative affinities of each are user-supplied F
DOI: 10.1021/acs.energyfuels.7b01815 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels
Figure 5. Calculations for a closed system (top) and from the enhanced Pepper−Corvi expulsion model (center and bottom) for Green River oil shale (left) and a type II source rock (right) heated at 2 °C/My using model parameters from Tables 1−3. EOM is extractable organic matter, using a procedure that does not lose light ends. For comparison purposes, 0.4%Ro is achieved at 71 °C, 1.0%Ro at 149 °C, 1.6%Ro at 180 °C, and 2.2%Ro at 204 °C.
for gas. Similar reasoning a maximum sorption capacity of 700 mg of oil/g of type II kerogen. The relative sorptivities are estimated from relative swelling propensities of various chemical types and from relative partition coefficients (where the partition coefficient is defined as the ratio expelled to retained component) determined for semiopen and hydrous pyrolysis (Burnham19 and Burnham et al.18). Further parametric studies showed that the relative partition coefficients between expelled and sorbed fluids were larger than the relative sorptivities due to the competition between species for sorption, but the relative sorptivities are consistent with relative swelling coefficients at atmospheric pressure. Due to the sparsity of experimental data for adsorption, the relative sorptivities were assumed the be equal for absorption by immature kerogen and adsorption by mature kerogen, except that the sorptivities of the aromatic oils were increased on the residual kerogen relative to immature kerogen to better match the paraffinicity of expelled oil in the Uinta Basin.37
absorption capacity is likely between 400 and 500 mg/g of kerogen from the swelling ratio corrected for estimated density and confinement effects. Initial calculations using such an expulsion threshold revealed that most of the initial sorption capacity was taken up by the asphaltic product HO3, which causes the initial expelled oil to be highly polar and dominated by the species MO3. In retrospect, the answer lies in how one considers HO3. It is more properly considered as a soluble solid that under geological conditions could be extruded from kerogen under lithostatic load but is not actually a Newtonian fluid.36 If we consider that it is both the most abundant initial product and also a sorbent for oil and gas species, increasing the sorption threshold seems appropriate, and the best results were obtained at approximately twice the sorptivity of kerogen alone. For the Green River organic matter, the current modeling uses maximum sorption capacities of 900 mg/g of kerogen for oil and 50 mg/g of kerogen G
DOI: 10.1021/acs.energyfuels.7b01815 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels Adsorption in this context means surface adsorption and capillary condensation on a carbon-rich rigid matrix. Given that the carbon-rich matrix exists only at high maturities, the adsorbed oil and gas will also be more hydrogen-rich, so the fluid density may be only half as large as the matrix. Mature kerogen has a surface area of several hundred m2/g and a porosity of 15−30%,38−42 although their measurement is complicated by bitumen impregnation43 and collapse during kerogen isolation if not supercritically dried.44 The surface area and porosity may evolve as a function of maturity through additional elimination of volatiles and Ostwald-like ripening of pores, but that is a complication beyond the scope of the current model. For a plausible value of 25% porosity and a fluid density of 0.8 g/cm3, the sorbed fluid would be 180 mg/g of coke. Partitioning that sorption value between oil and gas implies 150 mg/g of coke and 30 mg/g of coke for gas, which we adopt as the base case. These are slightly higher than the values of 100 mg/g of coke for oil and 20 mg/g of coke for gas estimated by Pepper and Corvi.2 Calculations from a closed system and the enhanced Pepper− Corvi model for a constant heating rate of 2 °C/My (million years) are shown in Figure 5. The compositions in a closed system are similar but vary somewhat from the results at 2 °C/h due to the different activation energies and, hence, different relative rates at laboratory and geological heating rates, for the various reactions. This is more evident in Figure 6, in which light
Figure 7. Rock-Eval simulations for the enhanced Pepper−Corvi model for Green River (organofacies C) and type II (organofacies B) organic matter heated at 2 °C/My.
potential of the kerogen. These calculations are consistent both with measurements versus depth for Green River shale46 and for Vaca Muerta shale samples45 and with semiopen pyrolysis of Green River oil shale.18 Table 6 shows the composition of the oil expelled from Green River and type II kerogen at various maturity ranges using the enhanced Pepper−Corvi model. In all cases, the expelled oil is primarily hydrocarbons and the polar fraction is minor. This is a direct result of the preferential sorption of polar material by immature and mature kerogen. Because of the sorptive capacity of the kerogen, oil expulsion does not start until 10% kerogen conversion for the type II organic matter model and 20% for the Green River oil shale model. Due to the selective sorption parameters, the initial expelled oil in both cases is lighter than the cumulative expelled oil. The cumulative expelled oil is 34.5 API gravity for the type II model and 33.1 for the Green River oil shale model. The type II value is a little heavier than WTI and Brent benchmark crude oils, and the latter is a little lighter than Bluebell and Roosevelt crudes from the Uinta Basin.47 In both cases, also, the last expelled oil is substantially lighter, consistent with the condensate produced from mature source-rock reservoirs. For the Green River formation, oil composition versus depth in the Altamont Field of the Uinta Basin is given by Ruble et al.37 Saturates dominate the produced oil except for the shallowest well at 4700 feet. It is roughly 1/4th polar material, but it is also rich in pristane, carotane, and polycyclic biomarkers, which indicates that it comes largely from extractable components prior to the main stage of kerogen decomposition. In addition, some of the “asphaltenes” from these crude oils might include waxes, which have different chemical characteristics assumed here for asphaltenes. Finally, some differences in the natural crude oils
Figure 6. Saturate (LO1 + MO1), aromatic (LO2 + MO2), and resin (MO3) abundances for type I (organofacies C) organic matter in a closed system as a function of maturity at laboratory and natural maturation time scales. This shows the enhanced destruction of aromatics relative to saturates at lower geological temperatures.
and heavy oil saturates and aromatics are combined to show that aromatics persist to substantially higher maturities at higher laboratory temperatures than in the geologic environment. Resins show a similar but less pronounced effect. Rock-Eval simulations are shown in Figure 7 for the two types of organic matter. Changes in calculated Tmax are consistent with geological observations, except that the Tmax value for type II organic matter is flatter in the 0.3−0.8%Ro range than in the natural system. The calculated maximum value of S1/TOC occurs near 0.9%Ro for Green River oil shale and 0.8%Ro for the type II organic matter. The measured maximum for Vaca Muerta shale45 is similar in magnitude to the type II organic matter, albeit at a slightly lower maturity, but loss of light ends from the oil for the experimental measurement likely depresses the S1/TOC value and shifts it to lower maturity. Values of the production index [S1/(S1 + S2)] of about 0.5 after the kerogen is largely depleted merely reflects that adsorption of oil on the residual kerogen is comparable in value to the remaining gas-generation H
DOI: 10.1021/acs.energyfuels.7b01815 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels
Table 6. Composition of Oil Expelled from Green River Oil Shale and Type II Source Rock at Various Maturity Intervals when Heated at 2 °C/My
a
maturity, %Ro
% of oil expelled
HO3
MO3
0.75−0.86 0.86−0.91 0.91−1.06 1.06−1.20
16.6 33.4 38.1 11.9
0 4 2 0
0 10 9 0
0.75−0.86 0.86−0.91 0.91−1.06 1.06−1.20
63.0 23.1 11.1 1.2
3 0 0 0
16 3 0 0
MO2
MO1
Green River Oil Shale 30 49 21 38 18 39 9 48 Type II Source Rock 35 13 29 19 17 27 0 36
LO1
LO2
saturatesa
aromaticsb
NSOsc
12 15 20 33
9 11 13 9
62 54 58 81
38 32 30 19
0 14 11 0
18 30 43 64
14 17 12 0
32 50 70 100
49 47 30 0
19 3 0 0
MO1 + LO1. bMO2 + LO2. cHO3 + MO3.
Green River (organofacies C) and generic type II (organofacies B) organic matter use the same basic chemical reaction structure with different kinetic and stoichiometric coefficients. They should be viewed as incremental improvements over earlier composition models from LLNL25,26 and IFP31,33 and are similar to the ShellGenex model.22 Although the particular parameters here are within the range of variability for those two organic types, they have not been fully optimized on all aspects of generation and expulsion so should be considered merely as a starting point for refinement. In addition, use of this type of modeling for any specific location should reoptimize the coefficients for that location.
versus depth may be related to small differences in kerogen composition with a given formation. One example for the Green River Formation is that kerogen varies in branched hydrocarbon content as a function of depth and tends to become more paraffinic in the lower zones of the Green River Formation.48
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DISCUSSION It is possible to model compositional preferences for expulsion of hydrocarbon-rich fractions of oil at both laboratory and geological heating rates using a relatively simple extension of the Pepper−Corvi expulsion model. The model is based on combining simple relative sorptivities as a function of chemical fraction properties with a sequential dual-tank spill model with different capacities for immature and mature kerogen. The model is based on observations that polar molecules are preferentially absorbed by swelling of immature kerogen and adsorbed on nanoporous mature kerogen. Although water may play a secondary role in this fractionation, it is certainly not the primary driver. An important issue is the relationship of the model presented in this paper to the approach patented by ExxonMobil.14,15 Both use the concepts of preferential solubility of polar material within kerogen and of decreasing swelling propensity with maturity that were well established 20 years ago. The ExxonMobil model uses ill-defined algorithms (too few equations) based on coupling a more rigorous mechanistic chemical reaction model via lumped species to expulsion models. Their expulsion calculation flowchart mentions a first approximation of retained petroleum that is then revised by a process of chemical fractionation. Our generation of lumped species chemical reaction models is similar to that used in PMOD,49 and our expulsion algorithm calculates the retained petroleum directly without any iteration. Our expulsion algorithm is best viewed as a simple combination of the relative expellability factors in PMOD to the common tank-spill model popularized by Pepper and Corvi.2 In both models, the equation for proportioning the absorbed oil among the lumped species is the same weighted average, and that equation is also the high-concentration limit of the common multicomponent Langmuir adsorption model.50,51 Detailed comparisons of the ExxonMobil approach with the one presented in this paper are not possible, because the ExxonMobil algorithms are not published, but their published examples indicates their algorithms also work well. Using a sorption-dominated expulsion model to provide useful predictions of the compositions of retained and expelled crude oil and gas requires compositional models that account for both molecular weight and chemical type. The two examples here for
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ASSOCIATED CONTENT
S Supporting Information *
The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.energyfuels.7b01815. Additional figures (Figures A1−A7) that present further experimental and modeling results. (PDF)
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. ORCID
Alan K. Burnham: 0000-0002-3101-4419 Notes
The authors declare the following competing financial interest(s): A. K. Burnham is a consultant for Total E&P Research and Development, and both authors have copyright and royalty interests in PMod2.
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ACKNOWLEDGMENTS This work was supported in part by Total E&P Research and Development, Pau, France. The authors thank Total S. A. and Francois Gelin for support of this project. We also thank the reviewers (Ken Peters, Andy Pepper, John Stainforth, Cliff Walters, and an anonymous reviewer) that substantially improved the clarity of the paper. This does not mean, of course, that we and all reviewers agree on all aspects of the model.
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REFERENCES
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