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RICHARD SWARBRICK, STEPHEN O’CONNOR, and RICHARD LAHANN, IKON-GeoPressure 

High-pressure sediments in which oil and gas are generated 

and accumulate in traps are proven in many operating 

areas along the entire West African margin. Although classic 

areas for high pressure are found in Tertiary deltas, such as 

the Niger Delta, other types of basins in which young clastic 

sediments have accumulated also create the environment 

for high pressure and drilling challenges. The BP Macondo 

oil spill in the Gulf of Mexico has highlighted the technical 

challenge of drilling for oil in deep water, and the high 

pressures there added complexity to the control incident and 

the high volumes of fluids which blew out to the seabed. 

Understanding mechanisms which create high pressure, 

the context for pressure prediction, using all available data 

including seismic, and quantifying uncertainty are all required 

for successful, safe drilling in these challenging subsurface 

environments. Where there are many well penetrations 

with appropriate data, compilation of relevant data and 

their analysis within an integrated basin-scale pressure study 

allows the whole area to be contextualized for pressure. Such 

studies have been completed in Europe and North America, 

but along the West African margin so far only in the Niger 

Delta (Offshore, 2010), providing understanding of pressure 

distributions in the main reservoirs as well as relationships 

concerning seal breach and lateral drainage. 

This article places into context the reasons why and where 

high pressures are expected in drilling operations along the 

West African Margin and focuses on the challenges. Particular 

attention is paid to the Niger Delta where a major new regional 

initiative, in conjunction with DPR and NAPIMS and 

industry sponsors in Nigeria, is leading the way in regional 

interpretation of pressures leading to reduced drilling risk as 

well as new exploration opportunities. 

Why high pressure? 

High pressures are typically found in young, rapidly deposited 

clastic rocks (mainly sandstones, shales, siltstones) 

because of incomplete dewatering of the fine-grained rocks 

such as shales. This process is known as compaction disequilibrium 

(hence the more shale in the sedimentary succession 

the more the likelihood of high pressure). The amount of 

excess pressure (called overpressure) is a function of the permeability 

of the rocks (how fast the water can escape when 

buried) and the rate of burial. GeoPressure Technology has 

established an exclusive relationship between sedimentation 

rate and amount of overpressure for silty and shale-rich rocks, 

calibrated against a worldwide data set, which offers an early 

model of overpressure magnitude for predrill planning in 

these types of settings. However, there are other reasons for 

high pressure which are related mainly to deeper processes 

taking place in the rock column, at elevated temperatures. 

Gas generation is one of these mechanisms, creating pressure 

Figure 1. Pressure-depth plot for Niger Delta, illustrating the sharp 

pressure-transition zone at the base of the sand-rich section, leading to 

a narrow drilling window at depth. 

Figure 2. Example of pressures interpreted for a deepwater 

well, offshore West African margin, in which overpressure builds 

continuously from a relatively shallow position beneath the seabed. 

through volume increase during maturation of source rocks 

and/or the cracking of oil to gas (at temperatures in excess 

of 160°C and hence at burial depths generally greater than 

4–5 km). The effect on the rocks is an increase in overpressure 

and a corresponding reduction in effective stress (rocks 

fracture when the effective stress is significantly reduced 

so that the pore pressure approaches the fracture strength 

of the rock). Other mechanisms, also at high temperatures 

(e.g., about 100°C and higher), relate mainly to clay-mineral 

reactions in shales. There is much debate as to the volume 

change associated with such reactions, but it appears to be 

small (Swarbrick et al., 2002). What is much more potent at 

682 The Leading Edge June 2011 

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creating pressure is the collapse of the rock’s load-supporting 

framework (load transfer), potentially leading to high 

overpressures. Other mechanisms, believed to be minor in 

amount of overpressure generated, relate to water expansion 

on heating (aquathermal), selected mineral dehydration 

reactions and osmosis (where salinity differences are found). 

However, one or more of these other mechanisms can add to 

the overpressure already created by compaction disequilibrium 

and push the pressures toward the fracture pressure and 

tensile failure (a condition known as seal breach). In summary, 

multiple mechanisms are possible. The most effective 

is rapid burial of fine-grained rocks (when overpressure can 

commence within a few hundred meters of the sea-bed), but 

in deeper, hotter rocks many other mechanisms can add additional 

overpressure. 

 

Where does high pressure occur? 

It follows from the above description of the mechanisms that 

three main components control where overpressures occur: 

rate of sediment burial, temperature, and sediment permeability. 

Areas of high sedimentation rate will normally correlate, 

along a continental margin such as offshore West Africa, 

with high sediment input. Big river systems depositing 

large volumes of suspended sediment at their deltas are the 

most likely locations, the most visible of which are the Niger 

and Congo rivers exiting into the South Atlantic. The Niger 

Delta sediments are a mixture of sandstone (reservoirs) and 

shales (seals), deposited over time in a complex pattern of 

distributary systems running across the delta top, across the 

shoreface and into offshore deepwater environments where 

they interbed with marine sediments, largely shales. Tertiary 

deltas such as these typically exhibit a high sand content on 

the shelf and delta top, leading to near normal pressure conditions 

down to depths of 3000 m+ (10,000 ft), below which 

a sharp increase in overpressure (a rapid pressure-transition 

zone, Figure 1) leads to several drilling challenges. Firstly, 

the start of a rapid buildup in overpressure can be difficult 

to predict if the pressure change is accompanied by a facies 

change. Secondly, the rate of pressure increase can be high. 

In Brunei, for example, an increase in overpressure of 220 

bar (3200 psi) is reported (Ellenor, 1984) across a shale only 

17 m (55 ft) thick. Dickinson (1953) reports a > 230 bar 

(3300 psi) increase in overpressure over a 60-m vertical section 

at the base of the sand-rich facies in the Gulf of Mexico. 

Finally, the increase in overpressure can lead to a narrow 

drilling window (difference between pore pressure and fracture 

gradient, Figure 1). All these issues need to be assessed 

predrill and captured in the well-planning process for most 

likely and high-case pressure predictions and optimal positioning 

of casing to maintain wellbore stability, drilling 

safety, and minimize potential rig downtime. 

Further seaward, and especially down the continental 

slope, the sediments become more mud-rich and any sand 

reservoirs are confined to channel and fan systems, most likely 

enclosed in low-permeability shales. The pressure profile 

in more continuous shale sections is one of constant increase 

in overpressure, often with a gradient running parallel to the 

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overburden (Figure 2). From a drilling perspective, the rate of 

increase along the pressure-transition zone is gradual with less 

probability of a drilling surprise. However, the start of overpressure 

at relatively shallow depths of burial, typically 1000 

m (3000 ft) below seabed, leads to a long and continuous 

narrow drilling window, requiring frequent casing strings to 

maintain borehole integrity. Some wells along the continental 

margin of West Africa have had to set total depth prior to 

reaching all their expected targets because of these extensive 

pressure-transition zones. 

Thermal processes will occur at depths where the temperatures 

allow selected reactions in suitable rocks. Source rocks 

are required for gas generation and the overpressure generated 

with the source rock will, over geological time, influence other 

sediments both above and below. Similarly, clay-mineral 

reactions occur when the kinetics (time and temperature conditions 

for reaction) are met at depth. Once a single reaction 

has occurred, no further overpressure will be generated unless 

other reactions occur. Detailed knowledge of clay-mineral 

diagenesis remains relatively elusive. 

How do we predict high pressure? 

Traditionally, the method to predict the pressure of shale-rich 

rocks is to analyze seismic and well data, working with the 

principles that (a) high pressure is associated with higher than 

expected porosity; (b) the parameter used to capture porosity 

is of good quality with high data density; and (c) the only 

reason for the overpressure is compaction disequilibrium. The 

two main relationships used to quantify pore pressure are the 

(a) Eaton ratio method, an empirical approach in which Eaton 

provided constants for sonic velocity, resistivity and drilling 

exponent (Dxc) data, and (b) equivalent depth method, a 

deterministic approach, which is most commonly used with 

density and sonic velocity data. Ideally, pore-pressure prediction 

practitioners will use both methods applied to several data 

types to compare prediction profiles. In that way a measure 

of the uncertainty in the prediction can be usefully assessed. 

In Figure 3, four types of log data (sonic, density, neutron, 

and resistivity) have been used from a single well to estimate 

the pressures in a thick shale section. In this example, from 

offshore West Africa, there is good consistency of patterns of 

pressure estimation in the shales using all four log types. Because 

shale pressure cannot be independently verified, except 

in shallow sediments (< 200 m burial), it is imperative to build 

confidence of the overpressure magnitude, because drilling 

any sediments with high permeability will lead to a wellbore 

influx (potential kick) if the mud weight is not high enough to 

balance the formation fluid pressures. High confidence comes 

with consistency of results, combined with understanding the 

reservoirs and their relation to interbedded shales (and other 

lithologies). Isolated reservoirs often share similar overpressures 

with surrounding shales (good calibration to shale-based 

models), whereas interconnected reservoirs can allow pressure 

transfer leading to both higher and lower pressures than the 

surrounding shales (poor calibration for shale-based models). 

Laterally drained reservoirs in which reservoir pressures are 

significantly lower than the shales above and below are known 

along the West African margin. The thick reservoir in Figure 

3 has lower overpressure (from direct pressure measurements 

or MDTs) than the shales above, an indication of a laterally 

drained reservoir. 

Pressure prediction becomes more challenging and uncertain 

where pressure-generating mechanisms other than 

compaction disequilibrium are contributing to the overpressure 

and assessing which mechanisms may be contributors 

could benefit from plotting velocity against density, coded to 

depth (Chopra and Huffman, 2006). Figure 4 shows a schematic 

plot to illustrate trends of data with depth (arrows are 

from shallow to deep) to capture compaction disequilibrium, 

unloading (Bowers, 1994) associated with fluid expansion, 

such as gas generation, and the range of responses associated 

with chemical change in shales. The results of the plot help 

to guide the adaptation of the traditional approach to prediction, 

such as changes to the Eaton exponent, or application of 

a Bowers unloading model (Bowers, 1995). The confidence 

of any prediction in which multiple mechanisms are active 

is lower than for disequilibrium compaction alone, and careful 

calibration to any direct pressure measurements in offset 

wells becomes more critical. In addition, the effectiveness of 

seismic-based pore-pressure prediction (well suited to locations 

situated far from available well data) can be severely reduced. 

From a predrill prediction point of view, the inability 

to anticipate contributions to overpressure from fluid expansion 

and chemical processes and the associated modification 

of the rock properties used for pressure profiling can lead to 

substantial underprediction of reservoir pressures and hence 

add substantial risk to the safety of well operations. Realistic 

uncertainty estimates are important at this stage. 

Regional pressure studies 

Offset well data must always be examined carefully as the 

main calibration data for pressure prediction in undrilled areas. 

Where sufficient density of wells is available, compilation 

of the data basin-wide offers immense advantages. Successful 

Figure 3. Example of pressure-depth plot for a thick shale interval 

in which pressure is estimated from four log types (sonic, density, 

resistivity, and neutron). The reservoir beneath has lower overpressures 

on account of lateral drainage (see text). 



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pressure prediction does not only rely on local rock property 

data (such as porosity from velocity, density, or resistivity) 

coupled with direct pressure data from offset wells, but also 

must correspond to a realistic model for the development and 

distribution of basin fluids in the subsurface over geological 

time. Commercial fully coupled basin-flow modeling software 

offers a way to gain insights into fluid-flow behavior 

during progressive sedimentation, burial, and the influences 

of temperature. Basin models are particularly well suited 

where seismic definition is poor (for example under salt). 

However, they are not instantly available; building a model 

for an area of 100 km 2 is likely to take 3–4 weeks with the 

same amount of time to test and migrate from 1D through 

2D to 3D. GeoPressure Technology is currently interpreting 

the deepwater and ultra-deepwater areas of the Niger Delta. 

The outcome will be a set of maps and plots which describes 

the distribution of overpressure in all the main reservoirs and 

their relationship with each other. Each well has been examined 

not only for direct pressure data, but also for its relationship 

with shale pressures from a standard pressure-prediction 

interpretation (after testing for which mechanisms are active 

geographically and varying with depth and temperature). 

The entire data package provides a unique description of the 

subsurface plumbing of the Niger Delta. In addition, the 

data are rich enough for basin-wide compaction, overburden, 

and fracture-gradient algorithms to be generated and then 

tested. The deepwater Niger Delta project will be completed 

in the second quarter of 2011, after which other areas of the 

Niger Delta will be the prime focus. In addition to reduced 

risk (better definition of the drilling window based on both 

pore-pressure and fracture-pressure prediction), the description 

of the subsurface pressure relationship benefits exploration 

in areas such as seal breach risk (top seal failure prediction) 

as well as potential trap definition associated with fault 

sealing. Other areas of the West African margin which could 

benefit from regional or semiregional pressure studies of this 

nature include offshore Mauritania, Ghana, Angola, Gabon, 

and Cameroon. 

 

Regional informs the local 

Understanding the bigger picture through regional pressure 

studies (as done in Europe, the USA, and West Africa, for 

example) helps to improve prediction from local data as well 

as increase understanding of rock and fluid properties and 

distribution. Two direct applications are cited here, both of 

which apply to West Africa exploration. Mapping of overpressure 

and recognition of pressure compartments related 

to faults help to establish which faults preferentially leak and 

which seal, adding confidence to the search for downthrown 

fault traps. If higher overpressure exists on the upthrown 

side (Figure 5a), then prospectivity is enhanced (i.e., the trap 

is more likely to be successful). Where the opposite is true 

(Figure 5b, higher pressure on the downthrown side), then 

the prospect has a lower chance of trapping hydrocarbons. 

Pressure analysis then becomes part of the risking strategy 

associated with the trap. In the same way, top seal failure can 

be assessed by examining the relationship between the pore 



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pressure expected in the reservoir and seal, and the fracture 

strength of the top seal (see recent examples from the North 

Sea in Swarbrick et al., 2010). 

Another direct exploration benefit relating to understanding 

regional pressures occurs where reservoirs are connected 

over a large area and communicate to the surface, thereby 

drawing down the deeper reservoir overpressures relative to 

their intraformational shales. These conditions are known in 

the North Sea and South Caspian basins and similar geological 

conditions are found along the West African margin (Figure 

3). The lateral drainage from these reservoirs sets up a hydrodynamic 

flow through the reservoir over geological time. 

The changes of overpressure resulting from lateral drainage 

can be mapped. The map can be used to indicate the amount 

and direction of tilt of hydrocarbon-water contacts along the 

base of the hydrocarbons trapped above the hydrodynamic 

reservoir. Tilt depends on overpressure differences as well as 

the density contrast between hydrocarbons and water: the 

lighter the oil or gas the less the tilt. Examination of amplitude 

anomalies and their relationship with structure can 

improve confidence of assessing hydrodynamic trapping and 

the location and potential size of reserves. 

Pressures along the West African margin 

The geology of the West African continental margin is dominated 

by clastic sediments, which are therefore prone to the 

development of overpressures. Deeply buried sediments, 

mainly of Jurassic/Cretaceous age, include some of the main 

source rocks which make the margin a hugely successful petroleum 

province. Continuous Tertiary sedimentation has 

provided some world-class reservoirs but also significant sediment 

accumulation rates in which high overpressure is not 

uncommon. While the Niger Delta is the most well-known 

for its association with rapid sedimentation and overpressure, 

the signature of high pressure extends throughout the margin. 

The degree of overpressuring, and the location of narrow 

drilling margins both geographically and stratigraphically, 

varies. The shallowest overpressure is found down the 

continental slope (i.e., in the deepwater environments, where 

clay-rich sediments are at their finest-grained and have low 

permeability, even at shallow burial depths). A main challenge 

in drilling in such locations is that in deep water it is 

desirable to drill without a riser to set a deep conductor pipe 

to optimize well control later in the well. If overpressured 

reservoirs are drilled without a riser, there is a reduced capability 

to handle a well flow. Shallow-water flows are a feature 

of deepwater drilling in such environments and can be costly. 

Overpressure in shallow reservoirs is difficult to predict prior 

to drilling. (Note that shallow-water flows can also occur 

naturally and do not cause environmental damage.) 

In mud and shale-dominated sediments, overpressure continues 

to build with depth, and can lead to drilling challenges 

when the drilling window is long and narrow, requiring many 

casing strings (and hence high cost) to maintain well integrity. 

In regions, such as the Niger Delta, where the upper section of 

the sedimentary column has a high proportion of sand, the onset 

of overpressure is deeper, but the rate of overpressure buildup 

Figure 4. Trends of velocity versus depth which reveal patterns 

associated with the main processes which generate overpressure. 

Figure 5. Both (a) and (b) show overpressure differences on either 

side of a downthrown fault trap. (a) The lower overpressure on the 

downthrown side enhances trapping potential. (b) Higher overpressure 

on the downthrown side downgrades trapping potential, as updip, 

cross-fault flow is more likely. 

(the pressure-transition zone) is much more rapid, leading to 

drilling challenges. However, where clastic sediments anywhere 

along the West African margin are at temperatures < 100°C, 

there can be moderate-to-high confidence in pore-pressure prediction 

from shale properties using traditional approaches to 

well and seismic data. The principal challenges come with data 

quality, with the geology of reservoir distribution and connectivity, 

and the presence of other rock types, such as salt. 



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A more challenging predrill prediction environment occurs 

at depths at which temperatures exceed a threshold where 

thermal processes can create additional overpressure as well 

as change sediment properties used in routine approaches to 

pressure prediction. The deeply buried Jurassic/Cretaceous 

source rocks along the West African margin, in particular at 

temperatures in excess of 160°C, are prone to generate gas. 

Gas requires a higher volume than oil or water and hence increases 

the pressure on generation. Increases in pressure reduce 

the effective stress (the difference between the pore fluid pressure 

and the minimum stress required to fracture the rock), a 

sediment property used in pore-pressure prediction. There is 

a tendency to underpredict pore pressures if this effect is not 

recognized. Similarly, at temperatures in excess of 100–120°C, 

there are many processes, for typical burial rates, which modify 

shale properties (such as clay-mineral transformation of 

smectite to illite) that once again challenge the premises used 

to estimate pore pressures ahead of the bit. In areas, such as 

offshore Angola, where thick and sometimes mobile salt is 

present, pore pressures can be extremely difficult to predict, 

because seismic imaging is poor, both for structure and the 

velocities used in predrill prediction techniques. The amount 

of pressure found beneath salt largely depends on the extent 

of the salt as a rock unit and the ability of the salt to trap fluid 

beneath. Fluids can escape where salt is absent if there are sufficient 

volumes of connected reservoirs to allow high-pressure 

fluids to flow around the salt bodies. 

Summary 

Continental margins are characterized by geological conditions 

that favor development of high-pressure reservoirs, except 

where there is an overabundance of reservoirs, such as 

in the Niger Delta. Even here, deeply buried reservoirs can 

have extremely high pressures. There are multiple overpressure 

mechanisms operating simultaneously both in the shallow 

section (inability of water to escape from rapidly buried, finegrained 

sediments) and in the deep section (gas generation and 

changes in sediment fabric because of diagenesis). In all cases, 

the pressures found in reservoirs are closely related to the connectivity 

of reservoirs both vertically and laterally along and 

down the margin. High connectivity permits fluids to escape, 

while isolated reservoirs will maintain the pressures being generated 

in the surrounding fine-grained rocks. Regional mapping 

of overpressures along the West African margin, as being 

done in the current Niger Delta pressure study, has the potential 

to reduce drilling risk by illustrating pressure distributions 

as well as reducing the exploration risk associated with trapping, 

both conventional and hydrodynamic. 

References 

Bowers, G. L., 1994, Pore pressure estimation from velocity data: accounting 

for overpressure mechanisms besides undercompaction: 

SPE paper 27488. 

Bowers, G. L., 1995, Pore pressure estimation from velocity data: 

Accounting for overpressure mechanisms besides undercompaction: 

SPE Drilling and Completion, 10, no. 2, 89–95, 

doi:10.2118/27488-PA. 

Chopra, S. and A. Huffman, 2006, Velocity determination for pore 

pressure prediction: CSEG Recorder, April 2006, 28–46. 

Dickenson, G., 1953, Geological aspects of abnormal reservoir pressures 

in Gulf Coast Louisiana: AAPG Bulletin, 37, 410–432. 

Ellenor, D. W., 1984, quoted in The geology and hydrocarbon resources 

of Negara Brunei Darussalam: Brunei Shell Petroleum 

Company. 

Pressure study for Nigeria, Offshore, 2010, http://www.offshore247. 

com/news/art.aspx?Id=16868. 

Swarbrick, R. E., M. J. Osborne and G. S. Yardley, 2002, The magnitude 

of overpressure from generating mechanisms under realistic 

basin conditions; in: Pressure regimes in sedimentary basins and 

their prediction, A. R. Huffman and G. L. Bowers, eds. AAPG 

Memoir 76, 1–12. 

Swarbrick, R. E., R. Lahann, S. O’Connor, and A. Mallon, 2010, Role 

of the chalk in development of deep overpressure in the Central 

North Sea, in B. A. Vining and S. C. Pickering, eds., Petroleum 

geology from mature basins to new frontiers: Proceedings of the 

7th Petroleum Geology Conference, volume 1, 493–507. 

Acknowledgments: GeoPressure Technology (an Ikon Science company) 

and its Nigerian partner Sonar Limited are currently engaged 

with the Nigerian federal authorities, DPR and Napims, and with 

a group of six sponsor companies, in mapping pressures across the 

Niger Delta. Phase 1, covering the deepwater and ultra-deepwater 

areas was due to be completed in April 2011. Phase 2 (continental 

shelf and near-shore areas) and Phase 3 (onshore and swamp) will 

be completed between 2011 and 2014. 

Corresponding author: r.e.swarbrick@geopressure.co.uk

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