R. Anthony Lilburn

Bio: R. Anthony Lilburn is an academic researcher. The author has contributed to research in topics: Sedimentary basin & Overpressure. The author has an hindex of 1, co-authored 1 publications receiving 404 citations.

Mechanisms for Generating Overpressure in Sedimentary Basins: A Reevaluation

Abstract: Overpressure can be produced by the following processes: (1) increase of compressive stress, (2) changes in the volume of the pore fluid or rock matrix, and (3) fluid movement or buoyancy. Loading during burial can generate considerable overpressure due to disequilibrium compaction, particularly during the rapid subsidence of low- permeability sediments. Horizontal stress changes can rapidly generate and dissipate large amounts of overpressure in tectonically active areas. Overpressure mechanisms involving change in volume must be well sealed to be effective. Fluid volume increases associated with aquathermal expansion and clay dehydration are too small to generate significant overpressure unless perfect sealing occurs. Hydrocarbon generation and cracking to gas could possibly produce overpressure, depending upon the kerogen type, abundance of organic matter, temperature history, and rock permeability; however, these processes may be self-limiting in a sealed system because buildup of pressure could inhibit further organic metamorphism. The potential for generating overpressure by hydrocarbon generation and cracking must be regarded as unproven at present. Fluid movement due to a hydraulic head can generate significant overpressure in shallowly buried, "well-plumbed" basins. Calculations indicate that hydrocarbon buoyancy and osmosis can generate only small amounts of localized overpressure. The upward movement of gas in an incompressible fluid also could generate ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received October 17, 1995; revised manuscript received September 4, 1996; final acceptance January 20, 1997. 2Department of Geological Sciences, Durham University, South Road, Durham DH1 3LE, United Kingdom. Osborne e-mail: M.J.Osborne@ durham.ac.uk; GeoPOP web site http://www.dur.ac.uk/~dgl0zz7/ We wish to thank the companies that support the Geosciences Project on Overpressure (GeoPOP) at the universities of Durham, Newcastle, and Heriot-Watt: Agip, Amerada Hess, Amoco, ARCO, Chevron, Conoco, Elf Exploration, Mobil, Norsk Hydro, Phillips Petroleum UK Company Limited, Statoil, and Total. We also thank Neil Goulty (Durham) for commenting on an earlier draft of this paper. Osborne thanks Gordon Macleod (Newcastle) for help with geochemical modeling.

Anomalously high porosity and permeability in deeply buried sandstone reservoirs: Origin and predictability

Abstract: Porosity and permeability generally decrease with increasing depth (thermal exposure and effective pressure); however, a significant number of deep (>4 km [approximately 13,000 ft]) sandstone reservoirs worldwide are characterized by anomalously high porosity and permeability. Anomalous porosity and permeability can be defined as being statistically higher than the porosity and permeability values occurring in typical sandstone reservoirs of a given lithology (composition and texture), age, and burial/temperature history. In sandstones containing anomalously high porosities, such porosities exceed the maximum porosity of the typical sandstone subpopulation. Major causes of anomalous porosity and permeability were identified decades ago; however, quantification of the effect of processes responsible for anomalous porosity and permeability and the assessment of the predictability of anomalous porosity and permeability occurrence in subsurface sandstones have rarely been addressed in published literature. The focus of this article is on quantification and predictability of three major causes of anomalously high porosity: (1) grain coats and grain rims, (2) early emplacement of hydrocarbons, and (3) shallow development of fluid overpressure. Grain coats and grain rims retard quartz cementation and concomitant porosity and permeability reduction by inhibiting precipitation of quartz overgrowths on detrital-quartz grains. Currently, prediction of anomalous porosity associated with grain coats and grain rims is dependent on the availability of empirical data sets. In the absence of adequate empirical data, sedimentologic and diagenetic models can be helpful in assessing risk due to reservoir quality. Such models provide a means to evaluate the effect of geologic constraints on coating occurrence and coating completeness required to preserve economically viable porosity and permeability (Begin page 302) in a given play or prospect. These constraints include thermal history and sandstone grain size and composition. The overall effect of hydrocarbon emplacement on reservoir quality is controversial. It appears that at least some cements (quartz and illite) may continue to precipitate following emplacement of hydrocarbons into the reservoir. Our work indicates that integration of basin modeling with reservoir quality modeling can be used to quantify, prior to drilling, the potential impact of hydrocarbon emplacement on porosity and permeability. The best-case scenario for significant reservoir quality preservation due to fluid overpressure development is in rapidly deposited Tertiary or Quaternary sandstones. Our models suggest that significant porosity can be preserved in sandstones that have experienced continuous high fluid overpressures from shallow burial depths. The models also indicate that the potential for porosity preservation is greatest in ductile-grain-rich sandstones because compaction tends to be the dominant control on reservoir quality in such rocks. The case for significant porosity preservation associated with fluid overpressures in pre-Tertiary basins, however, is more problematic because of the complexities in the history of fluid overpressure and the greater significance of quartz cementation as a potential mechanism of porosity loss.

Mudstone diversity: Origin and implications for source, seal, and reservoir properties in petroleum systems

Abstract: Mudstone is the most abundant sedimentary rock and variously acts as sources, seals, and shale gas reservoirs in petroleum systems. Many important physicochemical properties of mudstones are strongly influenced by the mineralogy and size of deposited grains, and by diagenetic changes (precompaction and postcompaction); these are commonly predictable. The diverse composition of mudstones reflects input and hydrodynamic segregation of detrital materials to basins, primary production within basins, and diagenetic processes (both precipitation and dissolution) in the sediment. High-magnification observations both in modern and ancient sediments demonstrate that mudstones are texturally and mineralogically heterogeneous; this variability is not always readily apparent. Although some mud is indeed deposited by suspension settling out of low-energy buoyant plumes, textural analyses reveal that it is commonly dispersed by a combination of waves, gravity-driven processes, and unidirectional currents driven variously by storms and tides. Such dispersal mechanisms mean that muddy successions are typically organized into packages that can be interpreted using sequence stratigraphy. Early bioturbation homogenizes mud, whereas early chemical diagenesis can result in highly cemented zones developing, especially at stratal surfaces. The nature of deeper burial diagenesis, which involves compaction, mineral dissolution, recrystallization, mineral reorientation and lithification, and petroleum generation, is preconditioned by depositional and early diagenetic characteristics of the mud. Although the petrophysical properties of homogeneous mudstones are reasonably well known, the quantitative implications of heterogeneity for petroleum expulsion, retention, petroleum migration, seal capacity, acoustic anisotropy, and identification of shale gas reservoir sweet spots are essentially unexplored. Future work should seek to redress this position.

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

Abstract: 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.