Fluid Distribution Model for Structurally Complex Reservoirs in El Carito-Mulata and Santa Bárbara Fields, Venezuela
- Gelson Carpio (PDVSA Gas & Oil) | Fernancelys Del Carmen Rodriguez (PDVSA Gas & Oil) | Karem Alejandra Khan Torres (Petroleos de Venezuela S.A.) | Anairt Lisseth Contreras (Petroleos de Venezuela S.A.) | Luis S. Campos (Petroleos de Venezuela S.A.) | Crimilda Idrogo (Petroleos de Venezuela S.A.) | Eduardo Labastidas (Petroleos de Venezuela S.A.)
- Document ID
- Society of Petroleum Engineers
- Latin American & Caribbean Petroleum Engineering Conference, 15-18 April, Buenos Aires, Argentina
- Publication Date
- Document Type
- Conference Paper
- 2007. Society of Petroleum Engineers
- 5.6.2 Core Analysis, 1.2.3 Rock properties, 5.1 Reservoir Characterisation, 5.2.2 Fluid Modeling, Equations of State, 4.1.5 Processing Equipment, 1.8 Formation Damage, 4.1.2 Separation and Treating, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.1.5 Geologic Modeling, 5.5.11 Formation Testing (e.g., Wireline, LWD), 5.2.1 Phase Behavior and PVT Measurements, 5.6.1 Open hole/cased hole log analysis, 5.5 Reservoir Simulation, 5.5.3 Scaling Methods, 5.1.3 Sedimentology, 6.5.2 Water use, produced water discharge and disposal, 5.5.2 Core Analysis, 4.6 Natural Gas, 5.4.2 Gas Injection Methods, 5.1.2 Faults and Fracture Characterisation, 2.2.2 Perforating, 4.3.3 Aspaltenes, 2.4.3 Sand/Solids Control, 2 Well Completion, 5.1.1 Exploration, Development, Structural Geology, 5.2 Reservoir Fluid Dynamics, 1.6.9 Coring, Fishing, 5.6.4 Drillstem/Well Testing
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El Carito-Mulata and Santa Bárbara fields are located in Eastern Venezuela in the Maturín sub basin and cover almost 300 km2. The asymmetrical anticline of the reservoirs is the result of different tectonic regimes alternating compressive and extensive periods from the late Cretaceous to the Middle Miocene. The fields are producing 240,000 STB/D and their OOIP is estimated to be around 6.5 MMMSTB. The variation of the vertical fluid distribution is predominant. There is a light oil (condensate) at the top of the structure, black oil at the base and free water at different levels in the reservoirs. This vertical fluid distribution is not well represented in the
dynamic simulation model, which increases the uncertainty on any prediction or elaboration of the production plan.
The main objectives of this study are the determination of the original fluid contacts and the construction of a fluid model, which takes into account the free water presented in the reservoirs. This model can also define the vertical and lateral extension of the oil fields, indispensable for the reserves estimation.
The integration of the different kinds of static and dynamic information of 149 wells was necessary in order to obtain a well-supported fluid distribution model.
The analysis of the large number of data allowed defining the geometry of the Tar mat (asphaltene content > 20%), which is folded/faulted according to the structure and considered as a sealed layer in reservoir conditions, with thicknesses ranging between 300 and 500 feet. The irregular Tar mat surface limits the reservoirs and controls the free water levels in the fields. This new fluid distribution model was included at the numerical simulation model matching all the wells information about water or type of oil that has been produced or tested.
An accurate description of the fluid distribution in a reservoir is key to reduce uncertainty in the reserves estimates. The complexity of the stratigraphy, sedimentology, structural and fluid distributions were revealed during the evaluation of the reservoir data for El Carito-Mulata and Santa Bárbara fields.
The fluid distribution in these fields indicates the evidence of different properties and a strong variation of those with depth.
El Carito-Mulata and Santa Bárbara fields are currently sub-divided into four operating areas: North (MUC-2), Central (MUC-1), West (MUC-3) and South (SBC-10). To keep reservoirs pressure constant to avoid asphaltene precipitation, MUC-1 and MUC-3 are currently submitted under natural gas injection project, MUC-2 undergoes water injection while SBC-10 flows naturally.
Free water has been identified at different reservoir depths and this fact has not been represented at the previous fluid distribution model, this represents an inconvenience to match the fluids in the numerical model. An asphaltic crude oil, denominated Tar mat for its physical and chemical properties, has also been identified.
The term Tar mat is referred to heavy oil zones with high asphaltene content and well-defined limits presenting a local or regional distribution across different stratigraphic levels and depths. The main characteristic of the Tar mat zone is a minimal asphaltene content of 20% on the C15+ molar fraction .
A new model for the fluid distribution was generated for the fields in order to consider the original water-oil contacts, identify limits of the reservoirs and zones with Tar mat.
The previous fluid distribution model is based on a hydrocarbon column whose composition varies with depth, from gas condensate at the structural top to under saturated black oil down the flanks and at the base of the reservoir. A transition zone from gas condensate to volatile oil exists at approximately -14040 ft sub sea (ss). This model contains a water-oil contact, WOC, at -17300 ft ss in the south flank. Two stratigraphic limits are defined for the proven area in the North flank, one at -16800 ft ss and other one at -17400 ft ss
(see Figure 1).
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