Effects of Burial Hydrodynamics on Trapping and Insight on Fluid Flow: What Have We Learned from the Pressure Regime of the Offshore Mahakam Fields?
Yves Grosjean¹, Aussie Gautama², Jean-Michel Gaulier³, Patrice Imbert4, and Michel Bois³
¹Total E&P Borneo, Bandar Seri Begawan, Brueni Darussalam
²Total E&P Indonesia, Balikpapan, Indonesia
³Total S.A., Paris la Défense, France
4Total S.A., Pau, France
The Offshore Mahakam fields are characterized by a repetitive stacking of fluvial-tidal dominated deltaic sedimentary cycles separated by regionally extensive flooding events. The geologic setting of the basin is very unique and characterized by a very smooth structural deformation with scarce faulting in large parts of the basin and very constant sedimentation processes during the Miocene to Pliocene times. This allows describing the successive stages of burial of the deltaic reservoirs over more than 4000m. The hydrodynamic regimes induced by burial and the details of the migration and entrapment of hydrocarbons were progressively deciphered over the past 25 years from abundant well data and targeted basin modeling. Numerous high accuracy formation pressure measurements were acquired in all permeable beds since the mid-1980’s, both prior and during the production phase, and hundreds of wells have been drilled which allow describing the pressure regime in the numerous stacked reservoirs as well as inferring the pressure regime in the intercalated shale layers.
Pressure domains in the Offshore Mahakam Delta:
A general increase of reservoir pressures with depth and regionally from proximal to distal areas can easily be observed with three main pressure domains:
1. “Hydrostatic”, where reservoir pressure is strictly conform to an aquifer having a piezometric level at or close to sea level;
2. “Pressure Transition”, where reservoir pressure is indicative of an aquifer piezometric level rising significantly above the mean sea level yet remaining generally below an equivalent specific gravity of 1.60 g/cm3;
3. “Over pressured” where reservoir pressure appears to be equal to shale pore pressure.
Shale pore pressure is interpreted to be systematically higher than interspersed reservoir pressures except in domain 3 where they appear to converge. Domain 3 is reached shallower and in younger sediments going from proximal to distal. Over pressuring is therefore not strictly a function of depth. The most critical parameter is the quality of the drainage of the deltaic and marine shales provided – or not – by the interspersed permeable layers: when thin / low quality reservoirs are encountered in domain 2, their pressure is very systematically higher than in better quality reservoirs. And the best quality reservoirs – or most proximal, where the best connectivity can be expected – have lower pressures than other reservoirs nearby. This is particularly observed in some localized areas in the form of a “pressure belly” that can be traced through measured reservoir pressures. The usual pressure increase with depth is locally more pronounced in relation to an interval characterized by more shaly deltaic facies, but pressure recedes in deeper horizons to regionally more representative values as better quality reservoirs are reached. The pressure regression is clearly related to more proximal deltaic reservoirs being commonly encountered in that deeper interval. Further, e-log transforms (Eaton, 1975) evidence an increase of shale pore pressure from proximal to distal in a given stratigraphic interval, indicating that over-pressuring originates from the more distal, shaly sediments and is transmitted laterally to the reservoirs.
Hydrodynamics and trapping, Fluid Pressure Units:
Hydrodynamics is demonstrated in reservoirs by lateral pressure gradients decreasing across the traps – i.e. water potential drops. These surprisingly affects trapping very high in the pay zone, in domain 1 where over pressuring is not recognized. Aquifer pressures are always higher on the distal side of the reservoir and lateral gradients progressively increase with depth.
The systematic measurement of pressures in all permeable beds during the exploration and appraisal phase has allowed delineating individual packages of stacked deltaic reservoirs in apparent pressure communication vertically and laterally, despite the fact that at wells the reservoirs are clearly separated vertically by shale intervals. These Fluid Pressure Units (FPUs) are about 40m thick on average and limited aerially, although they can extend over several kilometers. Several tens of such FPUs were defined in each field. They correspond to individual deltaic depositional cycles. They are separated by shale intervals that do not really stand out compared to others yet act as effective vertical seals. These aerially extensive shales are interpreted as regionally significant flooding events. They delineate packages with individualized hydrodynamic and trapping characteristics that are otherwise controlled by the connectivity of the sediments which is observed to vary between FPUs – probably as a function of the rate of accommodation. The gas water contact of a given FPU is tilted and deformed according to the hydrodynamic circulation in that particular FPU.
In the shallower FPUs (that represent the major part of the reserves), reservoir pressures measured in the hydrocarbon phase in wells intersecting the FPU align along the same static pressure gradient, therefore demonstrating reservoir pressures in static equilibrium. Aquifer pressures allow mapping the hydrocarbon-water-contacts through a direct application of King M. Hubert’s theory. In the deepest FPUs the pressures in the hydrocarbon saturated reservoirs are no longer in agreement with static equilibrium. Potentials are generally higher and decrease laterally more steeply towards proximal areas in both water and hydrocarbon-bearing reservoirs. This is indicative of a dynamic setting where both water and gas are being actively displaced laterally by the over-pressuring as a function of drainage.
Evidence of vertical migration: implications in terms of sealing capacity of the shales
Gas filled reservoirs occur very high in the section in apparently un-faulted areas where lateral migration has to be ruled out as the lateral equivalents in the synclines do not reach a sufficient maturity level. Further, the filling geometry of the fields can be interpreted to result from continuous vertical leakage where each individual FPU would be filled to its leak pressure. Yet vertical migration through sub-seismic faults is not considered likely as the presence of faults should have been identified from anomalies in the pressure regime, hydrocarbon fluid types and production history. Indeed the known locally faulted fields of the area do evidence such anomalies.
Therefore, even though entry pressures measured on rock samples from sealing shale intervals are very high, way above the capillary pressures extrapolated at the top of the drilled columns – and the shale pore pressures should be added – one has to accept that hydrocarbons did flow vertically across these layers. Seals are likely to be a dual porosity medium, with the effective entry pressure being that of the fracture network rather than of the matrix. Such fracture networks could be related to rapid dewatering of the shales during the first stages of burial. These networks would never heal completely as they would be used to drain the compaction waters out of the shales during burial. Then the effective sealing capacity would be determined by the sum of the entry pressure of the fracture network, and of the interstitial water pressure.
Results of 15 years of basin modeling in the Offshore Mahakam Delta:
Several basin modeling studies mainly along 2D cross sections were carried out, spanning from the late 80’s to the early 2000’s. The excellent match obtained with the observations allowed validating the numerical representation of the physical laws used in the models. Overpressures as well as hydrodynamic circulations were reproduced with sufficient accuracy, and the results in terms of filtration velocity of water in the shales and in the reservoirs provided solid arguments for the geologic interpretation of the observed phenomena and their impact on trapping. High resolution grids incorporating details of the depositional systems at regional scale delivered results such as pressure bellies and lateral drainage of waters, as well as tilted contacts.
Yet, in order for the simulations to properly account for the observed hydrocarbon accumulations it was necessary to use capillary pressures for the sealing lithologies that are lower than the measured high capillary entry pressures of shales. This observation confirms the aforementioned hypothesis proposed for the sealing properties of the shales. The regional and temporal properties of sealing shales remain an area that would deserve further investigations.
AAPG Search and Discovery Article #120098©2013 AAPG Hedberg Conference Petroleum Systems: Modeling the Past, Planning the Future, Nice, France, October 1-5, 2012