Magnitude Of Overpressure Research Articles

Mathematical Model for Viscoplastic Fluid Hammer

The current work presents a mathematical model to simulate “viscoplastic fluid hammer”-overpressure caused by sudden viscoplastic fluid deceleration in pipelines. The flow is considered one-dimensional, isothermal, laminar, and weakly compressible and the fluid is assumed to behave as a Bingham plastic. The model is based on the mass and momentum balance equations and solved by the method of characteristics (MOC). The results show that the overpressures taking place in viscoplastic fluids are smaller than those occurring in Newtonian fluids and also that two pressure gradients-one negative and one positive-are possibly noted after pressure stabilization. The pressure stabilizes nonuniformly on the pipeline because viscoplastic fluids present yield stresses. Overpressure magnitudes depend not only on the ratio of pressure wave inertia to viscous effect but also on the Bingham number. The pipeline designer should take into account the viscoplastic fluid behavior reported in this paper when engineering a new pipeline system.

Tectonic overpressure and underpressure in lithospheric tectonics and metamorphism

AbstractThe lithostatic pressure concept is most commonly applied on a geological scale for lithospheric processes and related evolution of metamorphic rock complexes. Here, various aspects of non‐lithostatic overpressure and underpressure phenomena in lithospheric tectonics and metamorphism are reviewed on the basis of recently published literature. The main conclusion from this short review is that these phenomena certainly exist in nature on all time and space scales including geological ones. They are, in particular, responsible for some geological processes, which are otherwise difficult to explain, such as downward water suction into the interior of subducting slabs. Magnitudes of overpressure and underpressure are strongly variable and may potentially reach up to ±100% of the lithostatic pressure and up to a GPa‐level. These magnitudes depend mainly on the rheology of deforming rocks and on the nature of related tectonic process. Rheological heterogeneity of deforming rock units, which is common in nature, has a tendency to enhance overpressure and underpressures. Large overpressure can typically be expected in rheologically strong (dry) bending rock units, in particular in the mantle lithosphere. However, rheological weakness of rocks and small local deviatoric stresses do not guarantee the absence of large overpressures in these rocks. Therefore, the influence of significant tectonic overpressure and/or underpressure cannot be excluded for any metamorphic complex a priori but should be instead tested by exploring realistic thermomechanical models for envisaged tectono‐metamorphic scenarios. Many lithospheric rocks subjected to large overpressures and underpressures cannot be studied as they do not exhume to the surface. Some controversy exists concerning overpressure magnitudes for the ultrahigh‐pressure (UHP) rocks and several conflicting hypotheses are proposed, which need to be thoroughly tested in the future. In this respect, the Alpine region may offer a unique opportunity for the testing of geological‐scale overpressures in (U)HP rocks by combining structural‐geological and petrological data with realistic lithospheric‐scale numerical modelling.

Factors controlling petroleum accumulation and leakage in overpressured reservoirs

This paper reviews the hydrocarbon-retaining properties of overpressured reservoirs and discusses the mechanisms for petroleum accumulation, preservation and loss in overpressured reservoirs, and the factors controlling hydrocarbon column heights in overpressured traps. Four types of overpressured traps (filled, underfilled, unfilled, and drained) are recognized. The diversities in petroleum-bearing properties reflect the complexities of petroleum accumulation and leakage in overpressured reservoirs. Forced top seal fracturing, frictional failure along preexisting faults, and capillary leakage are the major mechanisms for petroleum loss from overpressured reservoirs. The hydrocarbon retention capacities of overpressured traps are controlled by three groups of factors: (1) factors related to minimum horizontal stress (tectonic extension or compression, stress regimes, and basin scale and localized pressure–stress coupling); (2) factors related to the magnitudes of water-phase pressure relative to seal fracture pressure (the depth to trap crest, vertical and/or lateral overpressure transfer, mechanisms of overpressure generation); and (3) factors related to the geomechanical properties of top seals or sealing faults (the tensile strength and brittleness of the seals, the natures and structures of fault zones). Commercial petroleum accumulations may be preserved in reservoirs with pressure coefficients greater than 2.0 and pore pressure/vertical stress ratios greater than 0.9 (up to 0.97). The widely quoted assumption that the fracture pressure is 80%–90% of the overburden pressure and hydrofracturing occurs when the pore pressure reaches 85% of the overburden pressure significantly underestimates the maximum sustainable overpressures, and thus, potentially the hydrocarbon-retention capacities, especially in deeply buried traps. Lateral and/or vertical water-phase overpressure transfer from deeper successions plays an important role in the formation of unfilled and drained overpressured traps. Traps in hydrocarbon generation-induced overpressured systems have greater exploration potential than traps in disequilibrium compaction-induced overpressured systems with similar overpressure magnitude.

Porosity trends in the Skagerrak Formation, Central Graben, United Kingdom Continental Shelf: The role of compaction and pore pressure history

This paper describes reservoir properties in the Triassic Skagerrak Formation in the Central North Sea. This prolific sandstone reservoir often possesses anomalously high porosity for its depth of burial. Simple statistical analysis of wire-line-log-derived porosity data is used to derive empirical trends as a function of both depth and vertical effective stress that show variations between neighboring hydrocarbon fields and between different parts of the basin. Porosity data from the Josephine (J) Ridge (Quadrant 30 of the United Kingdom Continental Shelf [UKCS]) show a marked degradation with depth, but the porosities are significantly higher than in similarly deeply buried areas such as the Puffin high to the west (Quadrant 29) or the Forties–Montrose high to the north (Quadrant 22). To understand the porosity patterns better the data have been analyzed by plotting against vertical effective stress. This allows a better comparison to be made between fields and wells within the high-pressure–high-temperature (HPHT) realm. High pressure here refers to fluid pressures above 10,000 psi (), whereas high temperatures are above 300°F (149°C). Results show that porosity and fractional effective reservoir (the proportion of net sandstone with a porosity greater than a predetermined cutoff) decrease systematically with increasing vertical effective stress. Data from the different J Ridge fields fall on a common compaction trend even though they are derived from structures with marked variations in present-day depth of burial and static formation overpressure. Trends from the other areas of the Central Graben (the Puffin and Forties–Montrose highs) indicate more indurate reservoir states. The observed porosity trends are independent of fluid type within the reservoir and the absolute magnitude of overpressure. The main observed hydrocarbon effect is the result of buoyancy forces. The analysis supports the contention that, after accounting for facies-related grain-size variations, compaction controls average reservoir properties. Differences in compaction state between areas are postulated to relate primarily to structurally controlled timing of overpressure development relative to burial, and how these affect the resultant vertical effective stress history. Both the Puffin and Forties–Montrose highs are directly attached to the basin margins across stepped faults. These marginal terraces were open to lateral fluid flow for longer probably because across-fault seals were only established late in the burial history when higher temperatures promoted cementation and the destruction of permeability within fault cores. As a result, they developed overpressures in the last 5–10 m.y. or so and are largely normally compacted. The J Ridge horst block is hydrologically more isolated within the basin center by across-fault juxtaposition seals. Here, overpressure development appears to have started earlier, possibly between 50 and 60 Ma, retarding compaction and allowing preservation of higher porosities. Compaction continues to present day driven by the large static vertical effective stress gradients in these deeply buried reservoirs. The observed empirical trends offer a means of predicting average reservoir properties in deep untested exploration targets.

Kinematic linkage between minibasin welds and extreme overpressure in the deepwater Gulf of Mexico

A geopressure interpretation technique known as the seismic velocity method is a common workflow in which shale compaction functions are characterized at offset control wells, matched to interval seismic velocities, and then used to predictively calculate geopressure away from well control. The seismic velocity method is used to interpret the expected geopressure profile at the Deep Blue subsalt exploration well in Green Canyon 723 in the deep water Gulf of Mexico. The Deep Blue prospect is distinct from other prospects in the play fairway in that the prospective section is overlain by a salt withdrawal minibasin, whereas the offsetting fields are positioned either along the flanks of minibasins or under a thick allochthonous salt canopy. Predrill geopressure interpretations using numerous tomographic imaging velocity data sets shows a large degree of consistency with the magnitude of geopressure encountered in offsetting supra salt and subsalt fields. Results from the Deep Blue 1 exploration well indicate the predrill geopressure interpretation from interval seismic velocities failed to anticipate the extreme degree overpressure encountered in the subsalt section of the well due to poor deep velocity resolution and an “unloaded” compaction signature. The magnitude of overpressure in the primary section is attributed to the emplacement of an unconformable halokinetic sequence over the primary subsalt basin. An interpretive paradigm is described in which the Deep Blue pressure cell is created through two halokinetic episodes: (1) rapid progradation of a salt canopy followed by (2) subsequent salt withdrawal and emplacement of an overlying minibasin. The linkage between halokinetic sequences, burial history, and the development of overpressure can be used to predictively characterize subsalt geopressure environments.

Effects of cross-wise obstacle position on methane–air deflagration characteristics

A vented chamber, with internal dimensions of 150 mm × 150 mm × 500 mm, is constructed in which the premixed methane–air deflagration flame, propagating away from the ignition source, interacts with obstacles along its path. Three obstacle configurations with different cross-wise positions are investigated. The cross-wise obstacle positions are found to have significant effects on deflagration characteristics, such as flame structure, flame front location, flame speed, and overpressure transients. The rate of flame acceleration, as the flame passes over the last obstacle, is the highest at the configuration with three centrally located obstacles, whereas the lowest is observed at the configuration with three obstacles mounted on one side of the chamber. Compared with the side configuration, the magnitude of overpressure generated increases by approximately 80% and 165% for the central and staggered configurations, respectively. Furthermore, flame propagation speeds and generated overpressures for both the central and staggered configurations are greater, which should to be avoided to reduce the risk associated with turbulent premixed deflagrations in practical processes.

Evidence for overpressure generation by kerogen-to-gas maturation in the northern Malay Basin

Gas generation is a commonly hypothesized mechanism for the development of high-magnitude overpressure. However, overpressures developed by gas generation have been rarely measured in situ, with the main evidence for such overpressures coming from source rock microfractures, the physical necessity of overpressures for primary migration, laboratory experiments, and numerical modeling. Indeed, previous in-situ observations suggest that gas generation only creates highly localized overpressures within rich source rocks. Pore-fluid pressure data and sonic velocity–vertical effective stress plots from 30 wells reveal that overpressures in the northern Malay Basin are primarily generated by fluid expansion and are located basinwide within the Miocene 2A, 2B, and 2C source rock formations. The overpressures are predominantly associated with gas sampled in more than 83% of overpressure measurements and have a sonic-density response consistent with gas generation. The association of fluid expansion overpressures with gas, combined with the sonic-density response to overpressure and a regional geology that precludes other overpressuring mechanisms, provides convincing in-situ evidence for basinwide gas generation overpressuring. Overpressure magnitude analysis suggests that gas generation accounts for approximately one-half to two-thirds of the measured excess pore pressure in the region, with the remainder being generated by coincident disequilibrium compaction. Thus, the data herein suggest that gas generation, if acting in isolation, is producing a maximum pressure gradient of 15.3 MPa/km (0.676 psi/ft) and not lithostatic magnitudes as commonly hypothesized. The gas generation overpressures in this article are not associated with a significant porosity anomaly and represent a major drilling hazard, with traditional pore-pressure prediction techniques underestimating pressure gradients by 2.3 ± 1.5 MPa/km (0.1 ± 0.07 psi/ft).

Offshore sediment overpressures of passive margins: Mechanisms, measurement, and models

Fluid pressure in excess of hydrostatic equilibrium, or overpressure, in offshore environments is a widespread phenomenon that contributes to the migration and storage of fluids, solutes, and energy and to the potential mechanical instability of these sediments. Overpressure exists in deep and shallow systems and is most likely to be found where low‐permeability (<10−16 m2) layers have inhibited pore fluid escape or there have been large forcing mechanisms (e.g., rapid sedimentation, tectonic stressing, heating, and volume‐creating reactions). The genesis and magnitude of overpressure can be controlled by physical processes (e.g., rapid sedimentation (>mm/yr), tectonic loading, and lateral fluid transfer) and thermal and chemical processes (e.g., aquathermal expansion, hydrocarbon generation, mineral diagenesis, and organic maturation). In systems where near‐lithostatic overpressures are generated, potentially unstable sediments are created. Failures of these sediments can create large‐scale natural disasters, generate fractures, and damage seafloor and subseafloor infrastructure. Detailed characterization of overpressured systems has been accomplished through geological and geotechnical analyses, including investigation of physical‐mechanical properties (mainly porosity, consolidation state, and shear strength), inversion of geophysical data (e.g., compressional and/or shear velocities), measurement of in situ properties, and postevent analyses. Process‐based models have been developed to explain the origin of overpressure in terms of rate of overpressure genesis. This allows identification of potentially unstable zones and assessment of the potential for failure. Future development in measurements and in coupling of models will lead to more accurate analysis and prediction of fluid pressure in offshore sediments, which in turn will facilitate better hazard analyses and will enable safer and more cost‐effective offshore drilling practices and other offshore infrastructure development.

Role of effective permeability distribution in estimating overpressure using basin modelling

Overpressure generation is a function of the rates of sedimentation, compaction, fluid generation from kerogen and dehydration of minerals, and most importantly the lateral distribution of permeability within a basin as this controls lateral drainage. Sedimentary basins, however, are typically highly heterogeneous with respect to primary sedimentary facies, diagenesis and tectonic development. While fluid flow models based on idealised homogeneous basins may further our understanding of the processes that influence overpressure development, the results are very sensitive to the distribution of rock properties, particularly permeability. The absolute permeability of sedimentary rocks varies from more than 1 Darcy to less than 0.01 nanodarcy (nD) (10 −11 Darcy). Simple calculations, assuming vertical flow and no lateral drainage within the basin, show that overpressures approaching fracture pressure in the overburden will be reached if the effective permeability of the shale forming the seal is less than 0.1–0.01 nD (1.10 −22–1.10 −23 m 2). The permeability of shales varies greatly as a function of primary textural and minnerlogical composition and it is not possible to accurately predict the effective permeability of a sequence of shales forming pressure barriers. Overpressure in uplifted basins, where there is no compaction taking place, can only be maintained over geological time if the permeabilities are much lower. Overpressure is often controlled by lateral drainage but the effective permeabilities for fluid flow across faults and the offset of permeable layers are also difficult to predict. In most cases, uncalibrated basin modelling is unable to accurately predict the magnitude and distribution of overpressures because the vertical and horizontal permeabilities in sedimentary basins cannot be determined in sufficient detail. In basins that have been extensively explored and developed, incorporation of prior geological knowledge into basin models may allow overpressures to be predicted ahead of the drill bit. However, with such a large body of information already gathered about the basin it is debatable what extra value basin modelling is providing to pressure predictions.

Role of the Chalk in development of deep overpressure in the Central North Sea

Abstract A high magnitude of overpressure is a characteristic of the deep, sub-Chalk reservoirs of the Central North Sea. The Upper Cretaceous chalk there comprises both reservoir and non-reservoir intervals, the former volumetrically minor but most commonly identified near the top of the Tor Formation. The majority of non-reservoir chalk has been extensively cemented with average fractional gross porosity of 0.08, and permeability in the nano- to microDarcy range (10 −18 –10 −21 m 2 ), and sealing properties comparable to shale. Hence deeply buried chalk is comparable to shale in preventing dewatering and allowing overpressure to develop. Direct pressure measurements in the Chalk are restricted to the reservoir intervals, plus in rare fractured chalk, but reveal that Chalk pressures lie on a pressure gradient which links to the Lower Cenozoic reservoir above the Chalk and the Jurassic/Triassic reservoir pressures below. Hence a pore pressure profile of constantly increasing overpressure with increasing depth is indicated. Mud weight profiles through the Chalk, by contrast, show many borehole pressures lower than those indicated by these direct measurements, implying wells are routinely drilled underbalanced. The Chalk is therefore considered the main pressure transition zone to high pressures in sub-Chalk reservoirs. In addition to its role as a regional seal for overpressure, the Base Chalk can be shown to be highly significant to trap integrity. Analysis of dry holes and hydrocarbon discoveries relative to their aquifer seal capacity (the difference between water pressure and minimum stress) shows that the best empirical relationship exists at Base Chalk, rather than Base Seal/Top Reservoir, where the relationship is traditionally examined. Using a database of 65 wells from the HP/HT area of the Central North Sea, and extending the known aquifer gradients from the Fulmar reservoirs via Base Cretaceous to Base Chalk, leads to a risking threshold at 5.2 MPa (750 psi) aquifer seal capacity. Discoveries constitute 88% of the wells above the threshold and 36% below, with 100% dry holes where the aquifer seal capacity is zero (i.e. predicted breached trap). This relationship at Base Chalk can be used to identify leak points which control vertical hydrocarbon migration as well as assessing the risk associated with drilling high-pressure prospects in the Central North Sea.

An experimental investigation of gravity-driven shale tectonics in progradational delta

Many deltas exhibit gravitational deformation of their sedimentary cover. In these systems, the décollement layers do not always consist of rock salt but sometimes of overpressured shale. Unlike salt, the efficiency of detachment in shale depends on the magnitude of fluid overpressures and it varies through time and space, as rapid sedimentary burial progrades into deeper water. As a result, the gravity deformational domains are progressively translated seaward. Sandbox models involving high air pore pressures were used to simulate such gravity-driven shale tectonics in prograding deltas. Models were built with sand of various permeabilities and air was injected to simulate the mechanical effects of fluid overpressure. Our apparatus for the injection of air allowed us to control subsurface pressures in space and time during the experiments, and it was used to simulate the advance of the front of the overpressured domain during the sedimentary progradation. In our models, sand kept obeying a frictional behavior, for medium to high pore pressures, and the detachment appeared as very thin shear bands. Compressional belts that formed during the experiment were dominated by asymmetric basinward-verging fore-thrusts, as is often observed in deep-water, shale-detached foldbelts. Where the value of fluid pressures approached that of the lithostatic stress, sand was fluidized, resulting in ductile strains analogous to what occurs in highly overpressured mobile shale. During progradation, ancient buried thrustbelts were reactivated, thereby controlling later extension. During the experiments, sand volcanoes, analogous to mud volcanoes, formed in relation with tectonic structures. Some of them developed near normal faults but many of them formed directly above old buried thrusts.

Relationship between structural style, overpressures, and modern stress, Baram Delta Province, northwest Borneo

The Baram Delta differs from most large (passive margin) deltas because of its location on an active postcollisional margin. Structural style and evolution is influenced both by gravity‐driven deformation and regional stress. Key structural features of the delta include (1) late development of the toe fold and thrust belt (latest Miocene‐Recent) with respect to 17 Ma recent development of growth faults on the shelf; (2) a narrow active region of extension on the outer shelf upper slope; (3) absence of well‐developed shale diapirs; and (4) inner shelf onshore folding, thrusting, and growth fault inversion. Overpressure magnitude, type, distribution, and principal stress orientation and magnitude for the shelfal area were determined from well data. The inner shelf onshore area of inversion displays decreasing vertical stress gradient offshore and pronounced transfer of disequilibrium compaction overpressure from the Setap (shale) Formation into the overlying Belait Formation. This loss of overpressure permitted partial recoupling of once detached deltaic sediments with basement. Evidence for partial recoupling includes decreasing minimum horizontal stress gradient from NE (area of maximum inversion) to SW across the shelf and coast‐perpendicular inner shelf Shmax directions appropriate for inversion, but with stress magnitudes insufficient to cause deformation. These observations constrain models to explain why toe fold‐thrust belt activity occurred relatively late, while inner shelf folding developed early and is inactive today. During delta progradation disequilibrium compaction overpressures developed in the outer shelf slope area and helped decouple the section from basement late in the delta history, hence compressional deformation shifted further offshore. Conversely onshore inner shelf inversion caused late overpressure loss, resulting in partial recoupling of the deltaic section with basement.

Hydraulic connection and fluid overpressure in upper crustal rocks: Evidence from the geometry and spatial distribution of veins at Botrona quarry, southern Tuscany, Italy

Veins are the geologic record of fluids that filled fractures at depth in the crust. In southern Tuscany (Italy), well-exposed Oligocene–Early Miocene sandstones hosting vein systems provide insight into the role of pore fluid and the stress state at the time of vein formation. The stress ratio ( Φ = ( σ 2 − σ 3)/( σ 1 − σ 3)) and driving stress ratio ( R′ = ( P f − σ 3)/( σ 1 − σ 3)) were determined by analysing the distribution, length and aperture of fractures and veins and the magnitude of fluid overpressure. The derived fluid overpressure for the whole vein system ranges from 30 MPa to 64 MPa, with an average of 43 MPa; these values indicate that veins formed under supra-hydrostatic pressure conditions. Despite their spatial contiguity, two different vein arrays show very different stress and driving pressure ratios. One vein system is characterised by Φ = 0.62 and R′ = 0.60, the other by Φ = 0.54 and R′ = 0.78. The described vein systems are an example of a close spatial association of two non-hydraulically connected vein systems representing fluids focused through the upper crust.

Mechanisms of conduit plug formation: Implications for vulcanian explosions

We explore physical mechanisms controlling formation of a confining conduit plug using 1D, steady‐state numerical models of magma ascent. Model results for the well‐documented 1997 Vulcanian explosions at Soufrière Hills volcano were compared against subsurface conditions constrained by geophysical and petrologic analysis. We suggest that, if magma is permeable and overpressured and rock surrounding the conduit is permeable, degassing occurs both vertically and through conduit walls. This outgassing creates a region of low‐vesicularity, dense magma near the surface (magma plug) which eventually seals the conduit and promotes system overpressure. Driving pressure increases with increasing magma flow rate, hindering volatile exsolution and shifting open‐system degassing to shallower levels of the conduit. As a result, increasing magma flow rate for a fixed conduit width creates a vertically thinner plug and increases the magnitude and vertical extent of conduit overpressure. Plug thickness and density are also controlled by magma and edifice permeability.

Modelling the Central North Sea pressure history

High pore pressures in compartmentalized Mesozoic reservoirs in the Central North Sea are a challenge to predict using conventional porosity-based methods applied to shale mudrocks. Porosity and effective stress relationships, which work well in young and rapidly deposited basins such as Tertiary deltas, are not readily applicable to older, high-temperature sediments, and cannot be applied to non-reservoir chalk carbonates in which diagenesis is the principal control on porosity change. Basin modelling offers an alternative and complementary approach to conventional pressure prediction. New compaction and fluid flow relationships have been applied in commercial basin modelling software to model a 74 km 2D profile across the Central North Sea extending from the Fulmar Field in Block 30/16 across the Judy-Joanne High (Block 30/7) to the UK-Norwegian border in Block 30/8. The resulting models also tested chemical compaction simulation as a way to handle porosity change in non-reservoir chalks. The models were calibrated using porosity and permeability data collected as part of the study. When rock property data were satisfactorily matched, predicted pore pressures were compared with pore pressure measurements from multiple reservoirs in several boreholes. The model results closely match actual pressures from thin base-Tertiary reservoirs, which are likely to be close to their equilibrium with overlying shale mudrocks. The models underestimate the pore pressures in the deeply buried Mesozoic reservoirs. We interpret the deep pressures in relation to the contribution to overpressure from compaction disequilibrium (principally Tertiary sediment loading) relative to other, fluid inflation processes, such as gas generation. Future modelling, incorporating new data on fluid volume change when kerogen generates gas or oil cracks to gas, is now necessary to examine the magnitude of overpressure from these secondary sources.

Overpressure associated with a convergent plate margin: East Coast Basin, New Zealand

The East Coast Basin of New Zealand lies in the frontal arc of the Hikurangi subduction zone. Overpressure forms a major hazard for exploration in the basin. Fluid pressures of 12.8 MPa at 600 m depth have been encountered, equivalent to 90% of lithostatic pressure, and mud weights of up to 19.5 ppg are required to control formation fluids at subsurface depths of only 1400 m. The distribution and magnitude of overpressure shows no relation to present-day depth. Lithostratigraphy controls the distribution of overpressure and widespread low-permeability bathyal mudstones form seals to overpressure across the basin. The transition from normal pressure to overpressure is not associated with any single stratigraphic unit. The Neogene evolution of the plate boundary has given rise to rapid Miocene sedimentation (400 m Ma −1 ) in areas of the basin and has caused disequilibrium compaction. Late Neogene compression has subsequently uplifted the overpressured, undercompacted sediments by up to 3000 m at rates of 1000 m Ma −1 . Lateral tectonic compression associated with the plate boundary has also caused undrained shear of thick mudstones, leading to extremely high overpressures in deformed sediments independent of depth.

Ascent and decompression of viscous vesicular magma in a volcanic conduit

During eruption, lava domes and flows may become unstable and generate dangerous explosions. Fossil lava‐filled eruption conduits and ancient lava flows are often characterized by complex internal variations of gas content. These observations indicate a need for accurate predictions of the distribution of gas content and bubble pressure in an eruption conduit. Bubbly magma behaves as a compressible viscous liquid involving three different pressures: those of the gas and magma phases, and that of the exterior. To solve for these three different pressures, one must account for expansion in all directions and hence for both horizontal and vertical velocity components. We present a new two‐dimensional finite element numerical code to solve for the flow of bubbly magma. Even with small dissolved water concentrations, gas overpressures may reach values larger than 1 MPa at a volcanic vent. For constant viscosity the magnitude of gas overpressure does not depend on magma viscosity and increases with the conduit radius and magma chamber pressure. In the conduit and at the vent, there are large horizontal variations of gas pressure and hence of exsolved water content. Such variations depend on decompression rate and are sensitive to the “exit” boundary conditions for the flow. For zero horizontal shear stress at the vent, relevant to lava flows spreading horizontally at the surface, the largest gas overpressures, and hence the smallest exsolved gas contents, are achieved at the conduit walls. For zero horizontal velocity at the vent, corresponding to a plug‐like eruption through a preexisting lava dome or to spine growth, gas overpressures are largest at the center of the vent. The magnitude of gas overpressure is sensitive to changes of magma viscosity induced by degassing and to shallow expansion conditions in conduits with depth‐dependent radii.

Integrated study of the Judy Field (Block 30/7a) — an overpressured Central North Sea oil/gas field

The Triassic reservoirs of the Judy Field, an overpressured petroleum accumulation in the Central North Sea, have been studied to determine their pressure and petroleum filling history. The magnitude of overpressure in the Pre-Cretaceous aquifer is similar across the field at about 24 MPa (3500 psi), but with some higher pressure laterally in areas closest to the major depocentres. Pressure modelling shows that the magnitude of the overpressure can be attributed almost entirely to disequilibrium compaction, and largely due to late rapid Tertiary burial, although modelling does require nanoDarcy (i.e. shale-like) permeability in the Cretaceous chalk section. The contributions from other mechanisms, which may be relevant in this setting, i.e. gas generation and lateral transfer, appear to be small. The existence of both aqueous and petroleum phases in secondary fluid inclusions in microfractures in quartz and feldspar grains allows estimation of palaeopressure. The data show fracture healing from 115 to 136°C during a time when reservoir palaeopressures were above hydrostatic. Reconstruction of the temperature history of the reservoir places the timing of the fluid inclusion formation during fracture healing at between 3 and 1 My ago, coincident with a period of rapid burial. The palaeopressure estimation using fluid inclusions validates the pressure modelling studies, which are derived independently from commercial basin modelling software. The fluid inclusions also revealed a low-GOR oil over the whole field, prior to late stage flooding by gas leading to the variable (low to high) GOR fluids plus gas condensates within the field today.

Overpressures: Causal Mechanisms, Conventional and Hydromechanical Approaches

Abnormal fluid pressure regimes are commonly encountered at depth in most sedimentary basins. Relationships between effective vertical stress and porosity have been applied, since 1970 to the Gulf Coast area, to assess the magnitude of overpressures. Positive results have been obtained from seismic and basin-modeling techniques in sand-shale, vertical-stress-dominated tertiary basins, whenever compaction disequilibrium conditions apply. However, overpressures resulting from other and/or additional causes (tectonic stress, hydrocarbon generation, thermal stress, fault-related transfer, hydrofracturing. . . ) cannot be quantitatively assessed using this approach. A hydromechanical approach is then proposed in addition to conventional methods. At any depth, the upper bound fluid pressure is controlled by in situ conditions related to hydrofracturing or fault reactivation. Fluid-driven fracturing implies an episodically open system, under a close to zerominimum effective stress regime. Sound knowledge of present-day tectonic stress regimes allows a direct estimation of minimum stress evolution. A quantitative fluid pressure assessment at depth is therefore possible, as in undrained or/and compartmented geological systems, pressure regimes, whatever their origin, tend to rapidly reach a value close to the minimum principal stress. Therefore, overpressure assessment will be improved, as this methodology can be applied to various geological settings and situations where present-day overpressures originated from other causal mechanisms, very often combined. However, pressure trends in transition zones are more difficult to assess correctly. Additional research on cap rocks and fault seals is therefore required to improve their predictability. In addition to overpressure assessment, the minimum principal stress concept allows a better understanding of petroleum system, as fault-related hydrocarbon dynamic transfers, hydrofractured domains and cap-rock sealing efficiency depend on the subtle interaction, through time, between overpressure and minimum principal stress regimes.

THE ORIGIN AND INFLUENCE OF OVERPRESSURE WITH REFERENCE TO THE NORTH WEST SHELF, AUSTRALIA

The dominant cause of overpressure in basins is rapid loading of fine-grained sediments in which incomplete dewatering leads to additional overburden load being supported partly by the pore fluids. The principal controls on the magnitude of overpressure created are permeability and compressibility of the fine-grained rocks, coupled with the loading or sedimentation rate. High magnitude overpressure requires rapid sedimentation and/or evolution of sediment permeability to nanoDarcy values at shallow depth. By contrast, most fluid expansion mechanisms can be shown to be ineffective at generating large magnitude overpressure at realistic basin conditions. Only gas generation (either directly from kerogen or by oil to gas cracking) has the potential to create large magnitude overpressure, and only if the connected reservoir volume is very restricted.The origin of overpressure in the North West Shelf, especially the Northern Carnarvon Basin has previously been suggested to be due to petroleum generation, principally because the top of overpressure is coincident with, or lies below, the hydrocarbon generation window. To achieve high magnitude overpressure by this mechanism requires large volumes of gas generative source rocks connected to reservoirs of extremely limited extent. The volume of reservoir rocks in the basins is relatively high, and gas generation appears to be only a secondary mechanism. The most likely origin of overpressure is burial of the Jurassic and Lower Cretaceous group sediments (including the Muderong Shale) with early development of the Muderong Shale as a pressure seal. Lateral stress cannot be discounted as an additional mechanism of overpressure generation. However, lateral strain appears to be significantly less than vertical strain.Overpressure has the potential to influence the petroleum system in the North West Shelf if there has been high magnitude overpressure for prolonged periods of geological time. Normally pressured units today may have had a history of overpressure in the geological past. Reservoir quality can be enhanced by overpressure, but trap seal integrity either strengthened or weakened by overpressure. Timing of maturation and migration of hydrocarbon can also be affected.