Pore pressure prediction from well logs: Methods, modifications, and new approaches

Accurate pore-pressure prediction is critical in hydrocarbon exploration and is especially important in the rapidly deposited Tertiary Baram Delta province where all economic fields exhibit overpressures, commonly of high magnitude and with narrow transition zones. A pore-pressure database was compiled using wireline formation interval tests, drillstem tests, and mud weights from 157 wells in 61 fields throughout Brunei. Overpressures are observed in 54 fields both in the inner-shelf deltaic sequences and in the underlying prodelta shales. Porosity vs. vertical effective stress plots from 31 fields reveal that overpressures are primarily generated by disequilibrium compaction in the prodelta shales but have been generated by fluid expansion in the inner-shelf deltaic sequences. However, the geology of Brunei precludes overpressures in the inner-shelf deltaics being generated by any conventional fluid expansion mechanism (e.g., kerogen-to-gas maturation), and we propose that these overpressures have been vertically transferred into reservoir units, via faults, from the prodelta shales. Sediments overpressured by disequilibrium compaction exhibit different physical properties to those overpressured by vertical transfer, and hence, different pore-pressure prediction strategies need to be applied in the prodelta shales and inner-shelf deltaic sequences. Sonic and density log data detect overpressures generated by disequilibrium compaction, and pore pressures are accurately predicted using an Eaton exponent of 3.0. Sonic log data detect vertically transferred overpressures even in the absence of a porosity anomaly, and pore pressures are reasonably predicted using an Eaton exponent of 6.5.

https://www.searchanddiscovery.com/documents/2011/40709tingay/ndx_tingay.pdf

Origin of overpressure and pore-pressure prediction in the Baram province, Brunei

[ 1] The Yinggehai - Song Hong basin is one of the world's largest pull-apart basins, lying along the trace of the Red River fault zone in the South China Sea. South of Hainan Island this basin crosscuts the rifted margin of the northern South China Sea. In this paper we present for the first time a regional compilation of multichannel seismic reflection data from both the strike slip and rifted margins. The basins started to open after similar to 45 Ma, especially after similar to 34 Ma. The Yinggehai basin was folded and inverted in the middle Miocene, after 21 Ma in the north and 14 Ma in the south, before rapidly subsiding again after similar to 5 Ma because of continued tectonism. This subsidence has caused shale diapirism, especially driven by associated sedimentation in the late Pliocene (2.6 - 2.0 Ma). Extension along the adjacent south Hainan margin shows preferential lower crustal extension, suggestive of lower crustal flow increasing toward the continent-ocean transition during breakup. Sediment supply is reconstructed to peak in the middle Miocene, then falls between 14 and 10.3 Ma to reach a low in the late Miocene. However, rates rose again in the Pliocene-Pleistocene. The Red River sediment budget is incompatible with climate models that propose stronger monsoon rains starting at 8 Ma or with large-scale river capture away from the Red River after similar to 10 Ma. Both lines of evidence point to major uplift in the Red River drainage being middle Miocene or older. The recent, preindustrial Red River carried much more sediment than the average Pleistocene accumulation rate, indicating modest sediment buffering onshore, at least in recent geologic time.

The sedimentary and tectonic evolution of the Yinggehai-Song Hong basin and the southern Hainan margin, South China Sea : Implications for Tibetan uplift and monsoon intensification

Hydrocarbon phase pressures at the peak of two severely overpressured reservoirs in the South Eugene Island 330 field, Gulf of Mexico, converge on the minimum principal stress of the top seal. We interpret that the system is dynamically constrained by the stress field present through either fault slip or hydraulic fracturing. In two fault blocks of a shallower, moderately overpressured reservoir sand, hydrocarbon phase pressures are within a range of critical pore pressure values for slip to occur on the bounding growth faults. We interpret that pore pressures in this system are also dynamically controlled. We introduce a dynamic capacity model to describe a critical reservoir pore pressure value that corresponds to either the sealing capacity of the fault against which the sand abuts or the pressure required to hydraulically fracture the overlying shale or fault. This critical pore pressure is a function of the state of stress in the overlying shale and the pore pressure in the sand. We require that the reservoir pore pressure at the top of the structure be greater than in the overlying shale. The four remaining reservoirs studied in the field exhibit reservoir pressures well below critical values for dynamic failure and are, therefore, considered static. All reservoirs that are dynamically constrained are characterized by short oil columns, whereas the reservoirs having static conditions have very long gas and oil columns.

Stress, pore pressure, and dynamically constrained hydrocarbon columns in the South Eugene Island 330 field, northern Gulf of Mexico

We report the results of a series of hydraulic conductivity tests carried out on seven natural, well-characterised specimens of London Clay mudstone. The clay fractions of the samples range from 27% to 66% and enabled a test of the influence of clay fraction on the hydraulic conductivity, pore size distribution, compressibility and specific surface area of natural mudstones. Hydraulic conductivities were determined at effective stresses between 1.5 and 33 MPa. Hydraulic conductivities of clay-rich samples (49–66% clay fraction) decreased from ∼10−11 m s−1 to ∼10−14 m s−1 over a porosity range of 48% to 25%. At a given porosity the hydraulic conductivities of two silt-rich samples (27 and 33% clay fraction) were 40–250 times greater than those of the five clay-rich samples. Variations in hydraulic conductivity are directly related to pore size distributions and are accurately predicted by a model which uses pore size distribution as its primary input. Clay-rich samples have unimodal pore size distributions with modal throat radii around 60–120 nm. Silt-rich samples have bimodal pore throat size distributions. One modal size is similar to that observed in clay-rich samples with a second modal value at 3–6 μm. Compaction under effective stresses up to 10 MPa results in the preferential collapse of larger pores, so that the rate of loss of hydraulic conductivity is greater in the silt-rich samples. Differences in hydraulic conductivity between silt-rich and clay-rich mudstones therefore decline with decreasing porosity. The range of porosity-hydraulic conductivity relationships means that hydraulic conductivity is not easily predicted from porosity alone; additional constraining parameters such as grain and pore size distributions are required.

https://agupubs.onlinelibrary.wiley.com/doi/pdf/10.1029/1999JB900276

Jean Burrus

Papers

Overpressure Models for Clastic Rocks, Their Relation to Hydrocarbon Expulsion: A Critical Reevaluation