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AAPG Asia Pacific Region GTW, Pore Pressure & Geomechanics: From Exploration to Abandonment

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Combining science with models and calibration data to provide PP-FG solutions for industry

Abstract

“Fit for purpose” pore fluid pressure (Pp) and fracture pressure (FP) predictions are required to guide execution of safe but cost-effective drilling programmes. Geology underpins these predictions, i.e. knowing the rocks and fluids and their properties and applying realistic models to new well locations and/or to the pathways of fluid movement where depletion and/or fluid re-injection are involved. Historically, predictive relationships for Pp and FP originated in the Gulf of Mexico, a classical deltaic setting, but not especially applicable to many other areas. Geological context is the most useful starting point – lithology strongly influences Pp distributions whilst regional/local stresses impact on FP. Estimating FP invariably incorporates knowledge of Pp. In the absence of relevant offset wells, pressure interpretations rely heavily on seismic, not only to determine the rock-types (from seismic facies analysis and rock physics) but also to assess the likely regional and local stress environment. Basin modelling may help constrain some of the parameters. High Pp and a narrow drilling window (FP minus Pp) are not a random phenomenon, rather the product of one or more mechanisms which generate overpressure (pressure above hydrostatic) – principally disequilibrium compaction trapping fluid in low-permeability sediments like claystones/shales during burial. At temperatures greater than about 100oC, fluid expansion and load transfer processes create additional overpressure (OP) which can be sufficient for hydraulic failure. Disequilibrium compaction OP can be predicted using shale porosity trends and/or the shale model based on sedimentation rates, from which reservoir pressures are related, subject to allowing for reservoir fluid transfer from elsewhere, as well as fluid escape to surface. At depths below about 100oC, however, less precise estimates of Pp result from uncertainty of OP magnitude from deeper and hotter processes. Determination of FP in frontier areas relies on analogues and algorithms requiring an estimate of overburden (Sv) and minimum principal stress (Sh) in extensional and strike-slip settings. Where relevant offset borehole data are available, shales are “picked” from log data, and Pp estimated using a variety of data types. In some environments (classically including the Gulf of Mexico) mudweight can be valuable as a guide to shale fluid pressure. Low permeability rocks, however, do not yield sufficient influx to be reliable Pp indicators in many cases, leading to unintended underbalanced drilling, sometimes revealed by kicks. Direct Pp measurements in reservoirs can calibrate shale-based Pp estimates, subject to the assumption that shale Pp = sand Pp, to secure a working fluid flow and geological model. In relation to FP, Leak-Off test pressures (LOP) and/or formation integrity tests (FIT) calibrate predictions. Geoscience provides a sound basis for defining the initial estimates of Pp and FP and the drilling window. However, the outcome invariably includes uncertainty leading to difficult decisions, especially relative to the “high case” Pp and “low case” FP. Effective communication between geoscientists and operations/drilling engineers is critical to a successful outcome. Improvement in predicting Pp are emerging from advances in seismic data analysis, including full waveform inversion, providing direct access to interval velocities. The ability to record pressures in low-permeability (microDarcy) rocks will improve calibration of Pp prediction. Standardisation of borehole fracture strength testing (e.g. the Leak-Off test procedure) would benefit FP calibration and reduce uncertainty. Wider availability of global analogues supported by databases of observed/measured Pp and FP would be of high benefit too.