Risk Assessment Based on Single Porosity, Alpha Factor, Dual Porosity Simulation of a Naturally Fractured Rich Gas Condensate Reservoir
- Fabian Oritsebemigho Iwere (Schlumberger) | Hui Gao (Schlumberger) | Ernest Gomez (Schlumberger) | Yuan Zee Ma | Omer M. Gurpinar (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- Eastern Regional Meeting, 17-19 October, Lexington, Kentucky USA
- Publication Date
- Document Type
- Conference Paper
- 2007. Society of Petroleum Engineers
- 2.2.2 Perforating, 4.6 Natural Gas, 7.2.1 Risk, Uncertainty and Risk Assessment, 5.2.1 Phase Behavior and PVT Measurements, 5.6.4 Drillstem/Well Testing, 5.8.6 Naturally Fractured Reservoir, 5.5.3 Scaling Methods, 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 5.7.2 Recovery Factors, 5.8.8 Gas-condensate reservoirs, 1.6.9 Coring, Fishing, 5.1.5 Geologic Modeling, 5.4.1 Waterflooding, 3.3.1 Production Logging, 5.4.2 Gas Injection Methods, 4.1.5 Processing Equipment, 5.2.2 Fluid Modeling, Equations of State, 5.5.2 Core Analysis, 2 Well Completion, 5.5.11 Formation Testing (e.g., Wireline, LWD), 5.6.1 Open hole/cased hole log analysis, 4.3.4 Scale, 5.5.8 History Matching, 5.6.2 Core Analysis, 5.5 Reservoir Simulation
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Modeling naturally fractured reservoirs is difficult because of the need to characterize the fractures, matrix and the matrix-fracture interaction. It becomes more challenging if the naturally fractured reservoir produces wet gas, condensates and water. Three different three dimensional, compositional models--single-porosity (SP), single-porosity with alpha factor (SPWAF), and dual-porosity single permeability (DPSP) of the study area, were studied.
The models were calibrated against measured pressure, historical oil production, layer contributions and gas-oil ratios. The calibrated models were then used to forecast the performance of wells in the study area. The impacts of the methodology of describing the natural fractures on fluid flow behavior and recovery mechanisms, as well as on the ultimate hydrocarbon recovery were evaluated. The results also were used to ascertain the risks of selecting the optimum methodology for the field development plan.
The forecasted results show little variations in oil recovery, pressure and oil saturation distributions under identical operating strategy for the three models. This is attributed to the absence of some critical properties required to model the oil recovery mechanisms in dual porosity system. For example, imbibition capillary and relative permeability functions were not input in the dual porosity (DPSP) model. However, the DPSP model is considered more efficient than the single porosity (SP and SPWAF) models because it took less time and modifications to obtain reasonable history match of the field performance. It was also more difficult to obtain a reasonable and acceptable history match using the SP and SPWAF models compared to the DPSP model, and the reservoir properties in the single porosity models had to be modified extensively and unrealistically to obtain history match.
The choice of a numerical smulator to study the behavior of naturally fractured reservoirs is often not obvious, and this decision is further complicated when the reservoir fluid is a rich gas condensate requiring compositional characterization. This is because naturally fractured reservoirs comprise of matrix and fracture systems; some of them contain vugs also and are referred to as triple porosity systems. Depending on the amount of matrix, natural fractures, vugs in the total pore volume and their role in fluid flow, a single porosity model, dual porosity - single permeability model or dual porosity - dual permeability model may be used.
Da Silva and Petrofina have suggested the use of pseudo relative permeability1 generated for different fracture spacings, which in turn were correlated from core observation as a function of effective permeability. This approach is tedious, time consuming and sometimes impossible to describe the fracture network in the model. Tealdi et al2 up-scaled the matrix, fracture and karst properties into an equivalent single porosity model and used the model to simulate natural depletion and miscible gas injection. The methodology was first evaluated in representative sector models and then extended to the full field model.
The work presented in this paper investigates the performance of a sector of a naturally fractured gas condensate reservoir using single porosity, single porosity with alpha factor and dual porosity-single permeability models to represent the dual porosity system. Alpha factors or transport coefficients were introduced by Baker and Fayers3 to model subgrid heterogeneity in compositional simulation. Alpha factors are particularly suited for reservoirs where flow is primarily single phase. It could be very efficient as it reduces model complexity and simulation time while capturing all the dynamic key performance indicators of the more complex and computationally expensive dual porosity model.
The field was initially developed under primary depletion with condensate yield of about 300STB/MMscf. Although produced gas is presently recycled, the reservoir pressure has dropped below the dew point. It is believed that production is due to revaporization of the liquid components into gas phase and transport of these components in the gas phase to the production wells.
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