# Composition Changes of Hydrocarbons during Secondary Petroleum Migration (Case Study in Cooper Basin, Australia)

^{*}

## Abstract

**:**

## 1. Introduction

## 2. Formulation of the Problem and Study Methodology

_{res}) of hydrocarbons versus the number of carbon atoms in four wells of two different oil pools. The aim of this work is to explain the difference in oil compositions.

## 3. Deep Bed Filtration of Colloidal Suspensions in Porous Media

_{s}and pore size r

_{p}

_{s}= 27 × 10

^{−10}m. Average pore size can be estimated from permeability and porosity

## 4. Mathematical Model for Secondary Migration with Particle Retention

#### 4.1. Assumptions of the Model

#### 4.2. Analytical Model for Steady-State Flow of Components

_{n}is the concentration of n-th component in the migrating fluid, U is the flux velocity, α

_{L}is the dispersivity and λ is the filtration coefficient.

_{L}/L is positive [53].

_{L}/L varies between 10

^{−3}and 10

^{−1}[10,11]. Therefore, diffusion can be neglected, and solution (10) degenerates into the solution of the following system

#### 4.3. Determination of Filtration Coefficient Versus X

## 5. Numerical Results

## 6. Effects of Stress on Compositional Gradients of Migrating Oil

_{res}is a pore (reservoir) pressure, σ

_{v}is the vertical component of stress, and α is the Biot’s coefficient.

#### Example

_{w}= 1 g/cm

^{3}, ρ

_{r}= 2.6 g/cm

^{3}, the coefficient in the bracket at gH right hand side of Equation (18) is equal to 1.32. Therefore, the vertical stress increases with depth. For usual depth variations of lateral stress, the effective stress σ

_{eff}also increases with depth (see Equation (15)). Consider two reservoirs with 1km (reservoir a) and 10 km (reservoir b) depth. Equation (16) defines the reservoir pressures, p

_{resa}= 1 and p

_{resb}= 10 MPa respectively. Using Equation (18) vertical stresses are equal to 17MPa and 170 MPa, respectively. According to monotonically decreasing relationships (17), permeability and porosity also decrease with depth. However, the relative decrease of permeability is significantly higher than that of porosity, so the average pore throat radius, according to Equation (2), decreases with depth. Finally, the pore radius decreases with depth, so the filtration coefficient due to size exclusion increases, yielding the increase in compositional gradients in migrating oil along the pathway.

## 7. Discussions

## 8. Conclusions

- An analytical model for deep bed filtration of petroleum components facilitates matching the component concentrations in source rock and reservoir.
- For heavy hydrocarbons with n>10, the obtained values of filtration coefficients vary in the typical intervals. The heavier the component, the larger the filtration coefficient.
- For light and intermediate hydrocarbons with n<10, the tendency of monotonicity does not take place, which is explained by evaporation into associated gas phase that migrates together with oil.
- Comparison between modelling with and without the component dispersion shows a negligible effect of dispersion on compositional difference between the source rock and petroleum reservoir.
- Higher stress yields to the lower porosity and lower permeability, which results in a smaller pore size and higher deep bed coefficients.

## Author Contributions

## Funding

## Conflicts of Interest

## References

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**Figure 2.**The ratio between concentration of hydrocarbons in source rock and in the reservoir in four wells.

**Figure 3.**Structural interpretation of the Cooper-Eromanga Basin showing the location of wells, the Permian outer edge (where Triassic seal pinches out), and the migration of oil from source rocks to traps: (

**a**)—Basement fault map of the study area showing the location of the four wells used in this study. Source rock composition was obtained from the Patchawarra Formation in wells G27 and G45. The expelled oil migrated along two pathways, vertically through large basement faults and laterally through a carrier bed. The oil compositions in the Jurassic reservoir are obtained from G27 and G45 wells (vertical migration through faults), and Tantanna 2 (T1) and Sturt East 1 (SE1) (lateral migration through carrier bed). [24,49]; (

**b**) showing the two migration paths from the source rock in the Gidgealpa region to the oil pools through faults and via sedimentary rocks. The Permian outer edge shows the location where Triassic seals pinch-out, allowing oil to freely migrate from the source rock to the overlying reservoir rock.

**Figure 4.**Summary of the Cooper-Eromanga Petroleum System Events: (

**a**)—The timing of hydrocarbon generation and expulsion through time showing that initial expulsion commenced in the Late Permian and continues today [50]; (

**b**) A summary of the key petroleum system events in the Cooper-Eromanga Petroleum System [30].

**Figure 5.**Schematic of deep bed filtration in porous media. Particle retention by straining, attachment and mechanical entrapment. C presents the hydrocarbon component and U is the flow velocity.

**Figure 6.**Concentration profiles of hydrocarbons for n = 11, 13, and 14 for path through the fault in G42: (

**a**) profiles throughout the fault; (

**b**) zoom near to production wells in the reservoir. Solid lines—flow with diffusion; dashed lines—diffusion-free flow.

**Figure 7.**Filtration coefficients for hydrocarbons with difference carbon numbers for four different flow paths: (

**a**) for wells G42 and G27, (

**b**) for wells T2 and SE1.

Carbon Number n | λ × 10^{3}1/m, without Diffusion, for Well G42 | λ × 10^{3}1/m, with Diffusion, for Well G42, α _{L} = 10 m | λ × 10^{3}1/m, without Diffusion, for Well G27 | λ × 10^{3}1/m, with Diffusion, for Well G27, α _{L} = 10 m | λ × 10^{4}1/m, without Diffusion, for Well T2 | λ × 10^{4} with Diffusion for Well T2α _{L} = 100 | λ × 10^{4}1/m, without Diffusion, for SE1 | λ × 10^{4} with Diffusion for Well SE1α _{L} = 100 |
---|---|---|---|---|---|---|---|---|

2 | 0.314 | 0.319 | 0.25 | 0.25 | ||||

9 | 0.06 | 0.06 | 0.058 | 0.058 | ||||

10 | 0.255 | 0.265 | 0.173 | 0.176 | 0.108 | 0.108 | 0.103 | 0.103 |

11 | 0.261 | 0.259 | 0.259 | 0.2635 | 0.127 | 0.127 | 0.113 | 0.113 |

12 | 0.066 | 0.067 | 0.11 | 0.11 | 0.09 | 0.09 | ||

13 | 0.0615 | 0.0617 | 0.0853 | 0.0866 | 0.128 | 0.128 | 0.073 | 0.073 |

14 | 0.170 | 0.173 | 0.2024 | 0.205 | 0.148 | 0.148 | 0.083 | 0.083 |

15 | 0.083 | 0.082 | 0.206 | 0.209 | 0.152 | 0.152 | 0.09 | 0.09 |

16 | 0.3541 | 0.358 | 0.393 | 0.400 | 0.155 | 0.155 | 0.108 | 0.108 |

17 | 0.429 | 0.434 | 0.304 | 0.309 | 0.137 | 0.137 | 0.072 | 0.072 |

18 | 0.5215 | 0.529 | 0.337 | 0.342 | 0.162 | 0.162 | 0.056 | 0.056 |

19 | 0.715 | 0.726 | 0.558 | 0.567 | 0.192 | 0.192 | 0.118 | 0.118 |

20 | 0.941 | 0.961 | 0.568 | 0.576 | 0.2 | 0.2 | 0.142 | 0.142 |

21 | 0.994 | 1.01 | 0.558 | 0.567 | 0.183 | 0.183 | 0.103 | 0.103 |

22 | 1.11 | 1.13 | 0.712 | 0.721 | 0.208 | 0.208 | 0.117 | 0.117 |

23 | 1.18 | 1.21 | 0.690 | 0.7 | 0.207 | 0.207 | 0.126 | 0.126 |

24 | 1.288 | 1.32 | 0.68 | 0.69 | 0.203 | 0.203 | 0.158 | 0.158 |

25 | 1.56 | 1.60 | 0.931 | 0.956 | 0.225 | 0.225 | 0.16 | 0.16 |

26 | 1.85 | 1.90 | 1.22 | 1.241 | 0.273 | 0.273 | 0.183 | 0.183 |

27 | 2.07 | 2.15 | 1.41 | 1.45 | 0.267 | 0.267 | 0.188 | 0.188 |

28 | 2.91 | 3.04 | 2.38 | 2.46 | 0.233 | 0.233 | 0.296 | 0.296 |

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**MDPI and ACS Style**

Borazjani, S.; Kulikowski, D.; Amrouch, K.; Bedrikovetsky, P.
Composition Changes of Hydrocarbons during Secondary Petroleum Migration (Case Study in Cooper Basin, Australia). *Geosciences* **2019**, *9*, 78.
https://doi.org/10.3390/geosciences9020078

**AMA Style**

Borazjani S, Kulikowski D, Amrouch K, Bedrikovetsky P.
Composition Changes of Hydrocarbons during Secondary Petroleum Migration (Case Study in Cooper Basin, Australia). *Geosciences*. 2019; 9(2):78.
https://doi.org/10.3390/geosciences9020078

**Chicago/Turabian Style**

Borazjani, Sara, David Kulikowski, Khalid Amrouch, and Pavel Bedrikovetsky.
2019. "Composition Changes of Hydrocarbons during Secondary Petroleum Migration (Case Study in Cooper Basin, Australia)" *Geosciences* 9, no. 2: 78.
https://doi.org/10.3390/geosciences9020078