Al-Jenaibi, Faisal (ADNOC) | Bogachev, Kirill (Rock Flow Dynamics) | Milyutin, Sergey (Rock Flow Dynamics) | Zemtsov, Sergey (Rock Flow Dynamics) | Gusarov, Evgenii (Rock Flow Dynamics) | Kuzevanov, Maksim (Rock Flow Dynamics) | Indrupskiy, Ilya (OGRI RAS)
This paper deals with the issues related to the modeling of non-equilibrium phase transition in isothermal compositional models. Based on a real case of oil and gas field in the Middle East, the importance to take into account the effects of thermodynamic non-equilibrium are demonstrated with the help of mathematical models proposed earlier.
Theoretical and experimental studies, as well as actual field development data, show that not all phase transition processes take place in the forward and reverse directions at the same rate. For example, the dissolution of gas is much slower than the gas liberation from oil. Non-equilibrium processes are those whose characteristic time is comparable to or exceeding the characteristic time of variation of external conditions. In the classical formulation, it is supposed that thermodynamic processes are equilibrium, but the effect of non-equilibrium in addition to large grid cell sizes of the dynamic model and small-time steps can significantly affect the simulation results. In the case of black oil models, there are extensions of the mathematical model that are often used to describe the non-equilibrium behavior. At the moment, the rate of establishment of thermodynamic equilibrium is not taken into account in the majority of compositional models, the neglection of which in some cases might question the reliability of the simulation results. The practical implementation of the ideas (Indrupskiy et al, 2017), which were stated about how to take into account the non-equilibrium of thermodynamic processes occurring in the reservoir for compositional models, is performed.
The paper presents the results of modeling gas and water injection as a method of pressure support after development under depletion. In the equilibrium approach gas dissolves in oil at gas-oil contact simultaneously with increasing pressure. In practice, gas dissolution in oil occurs extremely slowly, and the dissolution rate decreases as the pressure approach the saturation pressure of the oil. According to laboratory studies, the modeling of such phase transitions requires the implementation of non-equilibrium models. At the same time, usage of the equilibrium models for this type of field leads to dramatic errors in estimates of the oil recovery.
The produced water formation volume factor (FVF), Bw, is defined as the volume at reservoir conditions occupied by 1 stock tank barrel (STB) of formation water plus its dissolved gas. It represents the change in volume of the formation water as it moves from reservoir conditions to surface conditions. Figure 1 is a typical plot of water FVF as a function of pressure. As the pressure is decreased to the bubblepoint, pb, the FVF increases as the liquid expands. At pressures below the bubblepoint, gas is liberated, but, in most cases, the FVF still will increase because the shrinkage of the water resulting from gas liberation is insufficient to counterbalance the expansion of the liquid.
Formation volume factor (FVF) is a useful relationship for relating gas volumes in the reservoir to the produced volume at standard conditions. Formation volume factor also enables the calculation of density. The formation volume factor of gas is defined as the ratio of the volume of gas at the reservoir temperature and pressure to the volume at the standard or surface temperature and pressure (ps and Ts). It is given the symbol Bg and is often expressed in either cubic feet of reservoir volume per standard cubic foot of gas or barrels of reservoir volume per standard cubic foot of gas. The n divides out here because both volumes refer to the same quantity of mass.
This page provides a number of examples that illustrate the mathematical calculations behind the different fundamental gas properties. The density is calculated from Eq. 3 in Gas formation volume factor and density: The formation volume factor is calculated from Eq. 2 in Gas formation volume factor and density: The viscosity is determined using the charts of Carr et al. in Figs.
The oil formation volume factor (FVF) relates the volume of oil at stock-tank conditions to the volume of oil at elevated pressure and temperature in the reservoir. For saturated systems, gas is liberated as pressure is reduced below the bubblepoint. This results in a corresponding shrinkage in oil volume, as shown for all of the methods in Figure 1. The rather large number of correlations preclude the identification of individual methods. The results show a relatively narrow range of oil FVF values determined by all of the correlation methods.
The implications of these compositional effects are very dependent on the oil composition, the composition of the injected gas, and the surface facilities and pipelines available in a particular field situation. The injected gas/oil composition interactions can be categorized as either swelling effects (gas dissolving into the oil phase) or stripping effects (various components from the oil transferring to the gas phase). The most obvious compositional effect in the immiscible gas/oil displacement process is that, if the oil is not saturated with gas at the reservoir pressure or if the reservoir pressure is increased as a result of the gas injection, the volume of gas dissolved in the oil will increase until the oil is saturated at that pressure. At the same time and because of the increased volume of gas in solution in the oil, the oil formation volume factor (FVF) will increase. This phenomenon, commonly called swelling, can increase the efficiency of the gas/oil displacement process.
Ganjdanesh, Reza (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin) | Fiallos, Mauricio Xavier (The University of Texas at Austin) | Kerr, Erich (EP Energy) | Sepehrnoori, Kamy (The University of Texas at Austin) | Ambrose, Raymond (EP Energy)
As the pressure drops below dew point in an unconventional gas-condensate reservoir, the liquid drops out of gas phase and forms an oil phase in matrix and fracture. The volume of oil phase formed in the matrix mostly stays below the residual oil saturation, i.e., the oil will be trapped in matrix permanently if enhanced oil recovery techniques are not applied. The gas huff-n-puff process has been performed and shown the potential of improving the recovery from tight oil reservoirs. The objective of the study was to investigate the feasibility of huff-n-puff EOR in a gas condensate reservoir. The studied section of the field contains 13 horizontal producers. The wells have been producing for 4 to 8 years and the oil production rate of each well declined below 10 barrels per day.
Compositional reservoir simulation was used to predict the performance of enhanced oil recovery. A sector model was built for the area selected as the prospective candidate for gas injection. The embedded discrete fracture model (EDFM) was used for modeling the fractures, improving the CPU time by an order of magnitude compared to the local grid refinement method. A Peng-Robinson equation-of-state model was prepared based on the early produced samples from the wells. The only available gas for injection was the produced gas from the surrounding producers. A thorough phase behavior analysis was conducted to understand the miscibility of the injected gas and the in-situ fluid.
The well interference through fracture hits plays an important role in the studied reservoir. The image logs from the surrounding wells show the abundance and extent of the long fractures connecting multiple producers. The long fractures can impede the pressure buildup during gas injection and hamper the gas huff-n-puff performance. Several long fractures were added to the reservoir model to capture the characteristics of well interference.
Hydrocarbon-reservoir-performance forecasting is an integral component of the resource-development chain and is typically accomplished using reservoir modeling, by means of either numerical or analytical methods. Although complex numerical models provide rigorous means of capturing and predicting reservoir behavior, reservoir engineers also rely on simpler analytical models to analyze well performance and estimate reserves when uncertainties exist. Arps (1945) empirically demonstrated that certain reservoirs might decline according to simple, exponential, hyperbolic, or harmonic relationships; such behavior, however, does not extend to more-complex scenarios, such as multiphase-reservoir depletion. Because of this limitation, an important research area for many years has been to transform the equations governing flow through porous media in such a way as to express complex reservoir performance in terms of closed analytical forms. In this work, we demonstrate that rigorous compositional analysis can be coupled with analytical well-performance estimations for reservoirs with complex fluid systems, and that the molar decline of individual hydrocarbon-fluid fractions can be expressed in terms of rescaled exponential equations for well-performance analysis. This work demonstrates that, by the introduction of a new partial-pseudopressure variable, it is possible to predict the decline behavior of individual fluid constituents of a variety of gas/condensate-reservoir systems characterized by widely varying richness and complex multiphase-flow scenarios. A new four-region-flow model is proposed and validated to implement gas/condensate-deliverability calculations at late times during variable-bottomhole-pressure (BHP) production. Five case studies are presented to support each of the model capabilities stated previously and to validate the use of liquid-analog rescaled exponentials for the prediction of production-decline behavior for each of the hydrocarbon species.