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A s a typical volatile oil reservoir, the actual production characteristics o f Wenchang 8-3 reservoir are inconsistent with the results of traditional phase equilibrium experiments. The conventional isothermal instantaneous phase equilibrium theory cannot meet the production performance or numerical simulation analysis requirements of this type of reservoir. The thermodynamic properties of volatile oil reservoirs are like those of condensate gas reservoirs. As the formation pressure drops below the dew point pressure during the mining process, the balance between the liquid phase and the gas phase is not completed instantaneously. Based on the non-equilibrium phase recovery treatment method of the condensate gas reservoir, the phase behavior change curve of the A4h well of Wenchang 8-3 oil reservoir recovered from the saturation pressure to three different pressures is analyzed. The accuracy of the numerical simulation results with or without non-equilibrium phase transition is compared. The results show that the non-equilibrium phase change has a great impact on the production performance of volatile oil reservoirs; t he numerical simulation results considering the non-equilibrium phas e transition are in good agreement with the actual production performance of a single well and can better reflect the actual situation of this type of reservoir. Therefore, considering the effects of non-equilibrium phase transitions has important guiding significance for the dynamic analysis of volatile oil reservoirs, numerical simulation, and the formulation of development management strategies.

Wenchang 8-3 oil reservoir is in the west of the western pearl river mouth basin, the north of the South China Sea. Three sets of volatile oil reservoirs have been developed. Wenchang 8-3 oil reservoir is in the west of the Pearl River Mouth Basin and the north of the South China Sea. Three sets of volatile oil reservoirs have been developed. Compared with the components of traditional black oil and condensate gas, the main feature of volatile oil is that the content of intermediate hydrocarbons (C2-C6) is much higher than that of black oil and condensate gas [

The formation temperature of volatile oil and black oil are both on the left side of the critical point, the formation temperature of volatile oil is close to the critical point, but the formation temperature of black oil is far away from the critical point.

fluid type | hydrocarbon composition /% | ||||||||
---|---|---|---|---|---|---|---|---|---|

C1 | C2 | C3 | C4 | C5 | C6 | C7+ | total | C2-C6 | |

Typical condensate gas | 87 | 4.30 | 2.20 | 1.60 | 0.70 | 0.50 | 3.70 | 100.00 | 9.30 |

Typical volatile oil | 64.40 | 7.50 | 4.70 | 4.10 | 3.00 | 1.30 | 15.00 | 100.00 | 20.60 |

Typical black oil | 48.80 | 2.80 | 1.90 | 1.60 | 1.20 | 1.60 | 42.10 | 100.00 | 9.10 |

WC8-3-1 | 52.82 | 12.99 | 8.08 | 4.82 | 3.32 | 3.52 | 14.44 | 100.00 | 32.73 |

A3h | 44.25 | 15.22 | 12.74 | 6.78 | 3.44 | 2.79 | 14.78 | 100.00 | 40.97 |

A4h | 36.69 | 14.84 | 14.55 | 8.56 | 4.30 | 3.04 | 18.01 | 100.00 | 45.29 |

The actual production performance characteristics of the wells in Wenchang 8-3 oil reservoir show that the volatile oil reservoirs of Wenchang 8-3 oil field are inconsistent with typical volatile oil reservoirs. When the formation pressure drops to the saturation pressure, the gas-oil ratio drops, which is inconsistent with the development characteristics of typical volatile oil reservoirs. Take Well A4h in Wenchang 8-3 oilfield as an example for analysis.

The fluid test crude oil saturation pressure of this well is 22.82 MPa. The well started production in January 2009, and its pressure (18.62 MPa) was lower than the saturation pressure in June 2012 (

It can be seen from the production performance curve that, the actual gas-oil ratio of the well is lower than the gas-oil ratio (550.5 m^{3}/m^{3}) measured overall by the flash experiment, which is consistent with the characteristics of non-equilibrium phase change volatile oil. For this reason, for accurate numerical simulation of the well’s production performance, the impact of non-equilibrium phase transitions must be considered.

In the early development experiment design of Wenchang 8-3 reservoir, the influence of non-equilibrium phase transition was not considered, which made the numerical simulation lack the numerical basis of non-equilibrium phase transition. In the early development experiment design of Wenchang 8-3 reservoir, the influence of non-equilibrium phase transition was not considered, which made the numerical simulation lack the numerical basis of non-equilibrium phase transition. For this reason, research is carried out based on the theory of phase recovery of condensate gas reservoir fluid. The phase state recovery is a process of restoring the phase state characteristics of the original fluid according to the phase state theory. In the general development process, the formation pressure drops, and gas is precipitated in crude oil; while in condensate gas reservoirs, condensate oil is precipitated. Knowing a point in the course of history, it is possible to perform forward and backward calculations.

Theoretical model for calculation of gas-liquid balance of formation fluid [

f i L k ( P , x 1 k , ⋯ , x n k ) − f i v k ( P , y 1 k , ⋯ , y n k ) = 0

Z i k − x i k L k − y i k V k = 0

∑ x i k − ∑ y i k = 0

L k + V k − 1 = 0

Z i k = [ Z i k − 1 + x i k − 1 Δ N i n k ] / ( 1 + Δ N i n k )

where f_{iLk} and f_{ivk} are the fugacity in the equilibrium liquid phase and gas phase when the component i recovers at the kth level respectively; P is the system pressure, MPa; Z_{ik}, x_{ik} and y_{ik} are the mole fraction of component i in the system, equilibrium liquid phase, and equilibrium gas phase when the kth level is restored respectively; L_{k}, V_{k} are the k-level recovery of the mole fraction of liquid and gas in the system; Z_{ik}_{-1} is the molar composition of component i in the k − 1 level formation (%); ΔN_{ink} is the increment of the equilibrium oil phase under the dew point pressure when level k is restored, kmol.

The following parameters can be calculated for the composition of well flow after each level of recovery [

1) The volume of 1kmol condensate gas under dew point pressure:

V d = Z d R T f / P f

2) Moles of well flow produced in the pressure drop process of stage J:

Δ N w j = { ( Z v j V p j + Z L j L p j ) ( 1 − N w j − 1 ) R T f P j − V d } P j Z v j R T f

3) Under the J-level pressure, the cumulative recovery factor of the well flow when the gas production is depleted:

N w j = ∑ i = 2 j Δ N w i

4) Saturation of retrograde condensate liquid under formation pressure of J level:

S o j = Z L j L p j ( 1 − N w j − 1 ) R T f P j V d

where L_{Pj} and V_{Pj} are the molar fractions of equilibrium liquid and gas phases in the formation at pressure level j; V_{d} and Z_{d} are the volume and deviation coefficient under dew point pressure, L/kmol; T_{f} and P_{f} are formation temperature and pressure, K, MPa; Z_{vj}, Z_{Lj} are the deviation factor of the balance between the gas phase and the liquid phase in the formation at a pressure of level j; N_{wj} is the cumulative production volume of well fluids under j-level pressure, kmol; R is the gas constant, R = 8.31 MPa·L/(kmol·K).

The current commercial numerical simulation software (ECLIPSE, CMG, etc.) cannot simulate the non-equilibrium phase change process of fluids, and the phase change is treated as an instantaneous phase equilibrium in the simulation calculation. To effectively characterize the initial composition of the fluid, according to the “higher bubble point pressure of volatile oil”, the phase recovery method was used to study the phase recovery of the oil samples from the A4h well. Three sets of fluid compositions at different saturation pressures are obtained, and the composition gradient is adopted, which approximately represents the non-equilibrium phase change effect. Based on the above-mentioned phase recovery theory, the phase status of Well A4h was recovered to different saturation pressures of 22.3, 22.0, and 16.5 MPa, respectively. The balance oil is added to obtain the change curve of the phase properties of the well when the saturation pressure of the crude oil of the well is restored to 22.3, 22.0, and 16.5 MPa (Figures 5-8). The three groups of different fluid compositions obtained after the phase state recovery are shown in

Composition name | Well flow composition, % | ||
---|---|---|---|

Saturation pressure 22.3 MPa | Saturation pressure 22.0 MPa | Saturation pressure 16.5 MPa | |

X1+ | 42.83 | 39.34 | 42.54 |

X2+ | 18.38 | 17.40 | 2.69 |

C3+ | 12.19 | 12.17 | 1.23 |

C4+ | 6.49 | 7.01 | 1.86 |

C5+ | 3.29 | 3.83 | 1.98 |

C6+ | 2.67 | 3.12 | 1.59 |

C14+ | 14.15 | 17.13 | 48.11 |

Total | 100.00 | 100.00 | 100.00 |

Composition | Molecular weight | Critical pressure Pc | Critical temperature Tc | Omega A | Omega B |
---|---|---|---|---|---|

M | MPa | K | |||

X1+ | 16.18 | 45.91 | 189.88 | 0.46 | 0.08 |

X2+ | 32.96 | 54.03 | 181.97 | 2.11 | 0.17 |

C3+ | 44.1 | 42.46 | 206.32 | 2.11 | 0.17 |

C4+ | 58.12 | 420.68 | 131.81 | 1.06 | 0.16 |

C5+ | 72.15 | 1421.5 | 2.15 | 0.24 | 0.31 |

C6+ | 84 | 1176.6 | 948.43 | 1.05 | 0.1 |

C7+ | 193.02 | 150.89 | 1442.52 | 0.62 | 0.4 |

Based on the above analysis, using the component model of the ECLIPSE simulation software E300, the ZH1-2L oil group A4h is numerically simulated with constant liquid volume using the unconsidered and non-equilibrium phase change processing method. Regardless of the influence of fault connectivity, composition gradients and non-equilibrium phase transitions on the simulation results, the simulation results obtained are shown in

Further combining with the latest knowledge of geology, based on the data obtained by the phase recovery processing method, the composition gradient is used to approximate the characteristic parameters of the non-equilibrium phase transition [

According to the above processing method, after considering the non-equilibrium phase transition, the history fitting result of Well A4h is obtained, as shown in

Altitude /m | Pseudo-component composition % | ||||||
---|---|---|---|---|---|---|---|

X1+ | X2+ | C3+ | C4+ | C5+ | C6+ | C7+ | |

2650 | 42.53 | 18.69 | 14.23 | 7.86 | 3.98 | 2.59 | 10.11 |

2800 | 42.54 | 2.69 | 1.23 | 1.86 | 1.98 | 1.59 | 48.11 |

1) According to the A4h well fluid composition and fluid P-T phase diagram of Wenchang 8-3 reservoir, it is comprehensively determined that the reservoir fluid has obvious volatile fluid characteristics and belongs to a volatile oil reservoir. In the phase behavior experiment results of Well A4h, the characteristics of the dissolved gas-oil ratio with pressure change are inconsistent with the actual situation, the gas-oil ratio has not risen, and the formation crude oil has not degassed, showing obvious non-equilibrium phase change characteristics.

2) Using phase recovery theory to recover the phase status of Well A4h to different saturation pressures. By adding the balance oil, the phase properties change curve and related parameters when the saturation pressure of the crude oil in Well A4h is restored to 22.3, 22.0, and 16.5 MPa are obtained, which lays the foundation for the numerical simulation.

3) Using the ECLIPSE simulation software E300 component model, the A4h well of Wenchang 8-3 reservoir was numerically simulated with a constant liquid volume. The results show that the simulation results are consistent with the actual situation when the component gradient and non-equilibrium phase change are considered. The feasibility and reliability of numerical simulation of volatile oil reservoir considering non-equilibrium phase transition are proved.

The author declares no conflicts of interest regarding the publication of this paper.

Xu, H.C. (2021) Numerical Simulation Considering Non-Equilibrium Phase Change Volatile Oil Reservoir: A Case Study of Wenchang 8-3 Oil Reservoir. International Journal of Geosciences, 12, 834-844. https://doi.org/10.4236/ijg.2021.129045