A periodic measurement of static bottom-hole pressure to monitor the reservoir depletion is an essential reservoir management practice. In an HP/HT offshore environment, the unavailability of qualified permanent down-hole monitoring technologies and the risks and costs of occasional operations make gradient surveys very difficult to acquire on a routine basis.
On Elgin-Franklin (HP/HT gas condensate fields, North Sea, UKCS), the typical approach is to use an average fluid density to estimate the static bottom-hole pressure from the well-head shut-in pressure. This estimation is valid as long as there is only one phase present inside the well-bore. As soon as the pressure drops below dew point in the tubing, the vertical phase distribution changes and the bottom-hole pressure can not be accurately estimated using one single average density. Fluid segregation mechanisms involve complex thermo-convective phenomenon, in association to gravity, which are strongly related to the temperature gradient in the well bore.
Segregated phase distribution has been observed on some available static pressure gradient surveys, where three gradients were identified. They correspond to three different phases, i.e. gas at the top, condensate in the middle and supercritical gas at the bottom of the well. This phenomenon of having a low density fluid below a higher density fluid was referred to as "gradient reversals" (Bender and Holden, 1984). At that time, it was assumed to be only due to the increasing temperature with increasing depth, but not explicitly related to the thermo-dynamical behaviour of the critical fluid.
In this case, we show that the fluid densities numerically estimated from each phase composition, at the corresponding pressure and temperature in the tubing, are comparable to the densities derived from the measured gradients. Based on this, a robust correlation methodology has been developed to derive the static bottom-hole pressure from the well-head shut-in pressure using thermodynamic modeling.
Introduction
Elgin and Franklin are deep HP/HT gas condensate fields situated in the Central Graben of the North Sea. Main reservoir is Upper-Jurassic Fulmar sand buried at more than 5000 meters depth and containing a rich fluid in supercritical conditions (1100 bars and 190 degC). The fields have been on-stream since 2001. After eight years of production, the reservoir pressure has declined by approximately 700 bars.
HP/HT reservoirs have posed new challenges for field developments and new challenges appear as these fields mature. One of these challenges is dropping below dew point which will impact well performance, field production, measurement limitations and future developments.
In terms of well performance, the main related issues are condensate loading in the well and consequently cyclic degradation of well performance, and condensate banking near the well-bore inside the reservoir causing production degradation, compositional changes and GOR increase. The change of the fluid composition and the difficulty to sample regularly introduce inaccuracies in surface measurements, well allocations, and eventually in proper evaluation of further development options.
