First EAGE International Conference on Fault and Top Seals - What do we know and where do we go?

Modeling the accumulation and loss of hydrocarbons in traps is one of the prirnary tasks in Petroleum Systems Modeling. Hydrocarbon column heights and accumulation sizes are in most cases determined by the physical properties of the top seals which can also obviously include faults and facies boundaries. The sealing capacity is usually quantified with capillary pressure values, and hydrocarbon break-through and loss from an accumulation occurs when the density contrast between the hydrocarbons and water times column height exceeds the capillary pressure. Accurate quantitative knowledge of the sealing capillary pressure is therefore required. Unfortunately, experimental values or theories for the derivation of capillary values from interfacial tensions, fluid properties and pore geometry are seldom available with the required degree of accuracy, especially as effective or bulk values are required.

Reservoirs and cap-rocks undergo burial dwing geological time. Hydrocarbons migrate into and fill traps during periods of active expulsion from source rocks. The supply of oil and gas can be abundant until deep burial stops the supply. Capillary leakage of oil and gas from the trap can then potentially decrease the size of the accumulation. A laboratory study of filling into and leakage out of a trap has been undertaken with a visual 2D laboratory model. The model defined a synthetic cap rock having a finite entry pressure overlying a permeable reservoir rock. The trap was formed by imbedding a pyramid-shaped layer of smaller glass beads in a pack of larger glass beads.

Accurate determination of hydrocarbon fill history is critical to the effective validation of predictive trap integrity models. In most instances, such models are validated using the distribution of hydrocarbon discoveries, thereby excluding the majority of the well results that are water wet. Interpreting the fill history of presently water-wet traps is desirable because it enlarges the footprint of investigation and helps produce a more statistically reliable predictive model. A reliance on conventional hydrocarbon shows, which are easily degraded over geological timeframes or during the drilling process and where there is uncertainty in the significance of oil show intensity, often makes reliable determination of the hydrocarbon charge history of water wet traps equivocal.

Capture of C02 from large point sources and subsequent long-term underground storage is at present the most promising option to reduce greenhouse-gas emissions without major sudden changes of our energy system. Two main types of subsurface CO2 reservoirs exist: emptied hydrocarbon fields and (saline) aquifers. In addition, some minor quantities of CO2 can be stored in enhanced oil recovery (EOR) projects. In all these cases, the existente of a tight seal is mandatory, to restrict buoyancy-driven upward migration of the CO2 into the atmosphere.

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The acquisition of gas data while drilling for geological-surveillance and safety is an almost universal. practice. Hence, mud logging services provide the earliest available data, along with LWD operations. A method has been developed by Total and Eni in order to use these gas data within the scope of reducing uncertainties in formation evaluation.

An integrated workflow for seal assessment and risking is proposed. The methodology considers six key parameters that can be combined into a single value indicative of overall risk for the presence of a sealed trap.

This paper is dedicated to an approach based on fluid analyses to investigate the possibility of either a fluid compartmentalisation or a fluid connectivity in complex oil and gas fields. This may have a major impact for the optimisation of the development and production of the fields.

Faults that affect fluid flow in hydrocarbon reservoirs are produced by the deformation of a large variety of sediment types, under different stress conditions.

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