Origin of High Porosity Zones in Mid-Deep Buried Paleogene Clastic Reservoirs in Dongying Sag, East China

Three anomalously high porosity zones (porosity>20%) developed in the middle (2500m-3500m) and deep (>3500m ) buried Paleogene subaqueous fan and sublacustrine fan clastic reservoirs in 2800m-3050m (max porosity=29.5%), 3300m-3600m (max porosity=28.1%), and 3900m-4200m (max porosity=22.3%), respectively, in Shengtuo area, Dongying sag, East China. It is still debatable whether mid-deep buried high porosity zones are an inheritance of shallow high porosity reservoirs whose primary porosity is well preserved in deep burial stage, or are developed through mineral dissolution in the mid-deep buried low porosity reservoirs. Compaction and multi-stage carbonate cementation are main factors that reduced reservoir porosity, while primary porosity is on large extent preserved. Fluid overpressure began to develop approximately 41Ma and 16Ma ago when reservoir depth was about 2000m. Reservoir with hyperpressure has 6-8% more porosity than normal pressure reservoir, so the fluid overpressure largely slowed down the compaction during deep burial stage. Maximum oil expulsion occurred during 39-31.9Ma and 13-0Ma, respectively. Statistics show that oil immersion sandstones have 4-6% fewer carbonate cements than sandstones with oil trace or fluorescence, indicating that early hydrocarbon emplacement impeded carbonate cementation significantly. Also, a mass of feldspars were found dissolved while carbonate debris and carbonate cements were left intact which might due to a relative high partial pressure of carbon dioxide (pCO₂) or Ca²⁺ concentration in formation fluids. However, feldspar dissolution hardly enhanced the reservoir porosity. The author found almost isovolumetric dissolution products precipitated in the nearby primary intergranular pores, in forms of authigenic kaolinite (D<3100m, T<125°C), authigenic illite (D>3100m, T>125°C) and quarts overgrowths due to an absence of favorable fluid migration pathways in relatively closed diagenetic environment, net enhanced porosity originated from feldspar dissolution is generally less than 0.25%. Consequently, shallow development of fluid overpressure and early hydrocarbon emplacement are the two controlling factors for development of the three high porosity zones. Thus favorable exploration targets should be reservoirs with good primary porosity that experienced fluid overpressure developed from shallow, early hydrocarbon emplacement (before 1st carbonate cementation), and good preservation during later burial.

AAPG Search and Discovery Article #90142 © 2012 AAPG Annual Convention and Exhibition, April 22-25, 2012, Long Beach, California