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Abstract ‘Play-based Pore Pressure Prediction’ is a new concept that considers overpressures and pore pressure prediction as being a fundamentally similar process to the ‘play-based exploration’ approach commonly used to search for hydrocarbons. For overpressures to exist, the right set of conditions needs to occur in the right order and timeframe. Just like a hydrocarbon play, overpressures need a source (generation mechanism), reservoir (the overpressured formation) and seal (ability to maintain overpressures over geological time). Current pore prediction methods do not consider overpressure over the geological timespan of a basin, and commonly result in overpressures being encountered in unexpected formations and depths, or at greater magnitude than anticipated, and has resulted in many drilling incidents. Play-based pore pressure prediction involves undertaking pore pressure analysis in a similar holistic manner to how prospects are generated during hydrocarbon exploration. The process involves using basinscale geology to establish likely overpressure mechanisms and formations (akin to identifying sources, reservoirs and seals); determining timing of overpressure generation throughout burial history, and; identifying major events causing overpressure transfer or dissipation (akin to hydrocarbon generation, charge analysis and trap development). Regional concepts are used to develop models to determine the likely locations and magnitude of overpressure (akin to hydrocarbon fairways and plays). Finally, regional learning's are applied at the prospect scale to select the best methods to predict pressures for planned wells. The innovation, and added benefit, of this new and novel approach is that ‘play-based pore pressure prediction’ can also be used to identify successful new exploration plays. Herein, I present an example of ‘play based pore pressure prediction’ from the Malay Basin that was used to improve drilling safety, and developed a new play concept that has subsequently resulted in 3 successful discoveries.
Abstract The Eagle Ford Fm in southwest Texas is a self-sourced oil and gas reservoir currently stimulated through hydraulic fracturing to produce economic quantities of hydrocarbons. Both early and burial diagenesis has had a major impact upon the rocks and their resulting reservoir quality. In this presentation we infer mineral reactions and precipitation that took place during diagenesis through a combination of mineralogical and petrographic analysis using XRD, optical and electron microscopy. We highlight how such an understanding can improve prediction of rock properties and reservoir quality. Along with compaction and de-watering, we infer that bacterial sulphate reduction had a major impact during early diagenesis as it resulted in significant calcite cement precipitation. Calcite cements infill bioclasts and foraminifera chambers, thereby significantly reducing intra-granular porosity. Fine grained calcite cements the matrix and coccolith fragments that resulted in reduction in inter-granular porosity and its interlocking texture will likely lead to an increase in rock brittleness. Optical microscopy and cathodoluminescence (CL) highlight the extensive and invasive calcite precipitation that occurs within concretional features in the Eagle Ford Fm. Zonation within the calcite cements suggests evolution in pore water chemistry and this is interpreted to be caused by changes in microbial organic matter oxidation. Foraminifera chambers are commonly infilled with kaolinite, as well as or instead of calcite. There is no clear petrographic evidence to suggest which came first, but based on the fact the foraminifera are not compacted we infer early diagenetic origin. Unlike the calcite infills, kaolinite infills preserve significant inter-crystalline porosity. Authigenic kaolinite is also present as multiple crystal grains within the matrix, and replacing 30–60µm detrital grains- which we infer to be feldspars. During late burial, authigenic quartz cement commonly precipitated around detrital quartz grains and calcite cements, further reducing inter-particle and inter-crystalline porosity. This source of this silica may have been clay mineral reactions or biogenic silica dissolution. Chlorite is present in the form of 5~15µm wispy flakes in the most thermally mature samples. The precipitation of clay minerals during deeper burial leads likely to a decrease in rock brittleness and a further reduction in micro-porosity in the matrix.
Summary This study demonstrates the use of wireline logs for the overpressure-mechanisms analysis in a field in the southwestern Malay basin. The development of overpressure means that the fluid movement in the pores is retarded, both vertically and laterally. In many Tertiary basins, overpressure is mainly generated by compaction disequilibrium caused by a high deposition rate and low permeability in shales. In the Malay basin, temperature and high-heat flow also play an important role in generating overpressure at a shallow depth, because the geothermal gradient is very high (40–60°C/km). Pore-pressure profiles and crossplots of sonic velocity/vertical effective stress and of velocity/density are used to derive the overpressure-generating mechanisms. The results obtained from the crossplots of 10 wells reveal that in the study area, overpressure is generated by both primary (compaction-disequilibrium) and secondary (fluid-expansion) mechanisms. The overpressure-magnitude analysis suggests that the overpressure generated by the secondary mechanism is very high compared with the primary mechanism. In all the wells, the Eaton (1972) method with an exponent of 3 gives good prediction when overpressure is the result of the compaction-disequilibrium mechanism, but it underpredicted the high pore pressure where the fluid-expansion mechanism is also present. However, by use of a higher Eaton exponent of 5 for the fluid-expansion mechanism, the overpressures are predicted quite well. The Bowers (1995) method, by use of the unloading parameter (U) of 6, is also used for pressure prediction and it gives a reasonably good prediction in the high-overpressure zone of all the wells.
With advancements in technology such as horizontal drilling and hydraulic fracking, operators are able to pursue reserves in unconventional mudrock reservoirs. Brittleness, one of the many pre-screening considerations, is an important parameter because it determines whether a mudrock can be effectively stimulated via hydraulic fracking. The industry currently uses several geochemical signals (e.g. Si/Al and Si/Zr) to identify authigenic silica phases present in an unconventional reservoir. Cemented horizons are prime candidates for placing hydraulic fracks due to the strengthening effects of mineral cements on the rock frame. A similar geochemical method for readily indicating the occurrence of authigenic carbonate has not been identified. This study documents trace element geochemical differences between biogenic (detrital) carbonate phases and associated cements so that chemical proxies may be used to differentiate authigenic carbonate phases using bulk geochemical data. Both carbonate-rich formations (e.g. Eagle Ford and Niobrara) and argillaceous formations (e.g. Haynesville and Marcellus) are examined to gain insight into reservoir brittleness, using bulk and trace elements such as Ba, Mg, Mn, Fe, Sr, and Ca. The goal is to develop a technique that can be implemented real-time by the mudlogging unit at the wellsite and during the initial core analysis phase. This method will allow a more targeted placement of hydraulic fracking zones to increase permeability and hydrocarbon production in mudrock reservoirs.
Electron probe micro analysis (EPMA) on several types of carbonate was conducted on low (0.45 %Ro) and high (2.5 %Ro) thermal maturity Eagle Ford and Haynesville Formation samples, respectively. The EPMA reveals that Sr is the primary elemental signature of the authigenic carbonate phase within the low maturity Eagle Ford. The Haynesville EPMA reveals higher variability of Fe, Mn, Sr, Mg, and Ba trace element concentrations, however the dominant elemental signature associated with the authigenic phases is elevated concentrations of Fe and Mn. Utilizing XRF, Sr/Ca and Ca-Fe-Mg cross-plots can be used as proxies to identify authigenic carbonate in the Eagle Ford and Haynesville Formations respectively, and can be used to indicate brittle zones for target adjustments at the wellsite.