Distribution and mechanisms of overpressure … words: intrasalt reservoirs, Neoproterozoic to Cambrian South Oman Salt Basin, overpressure generation and deﬂation Received 13 January

Distribution and mechanisms of overpressure generationand deflation in the late Neoproterozoic to early CambrianSouth Oman Salt Basin

P. A. KUKLA1, L. REUNING1, S. BECKER1, J . L. URAI2 , 3 AND J. SCHOENHERR2 ,*1Geological Institute, Wuellnerstrasse 2, RWTH Aachen University, Aachen, Germany; 2Structural Geology, Tectonics and

Geomechanics, Lochnerstrasse 4-20, RWTH Aachen University, Aachen, Germany; 3Department of Applied Geoscience,

German University of Technology in Oman (GUtech), North Ghubrah, Sultanate of Oman

ABSTRACT

Late Neoproterozoic to early Cambrian intra-salt Ara reservoirs of the South Oman Salt Basin represents a unique

self-charging petroleum play with respect to hydrocarbon and overpressure generation and dissipation. Reservoir

bodies (termed ‘stringers’) are isolated in salt and frequently contain low-permeable dolomites that are character-

ized by high initial production rates because of hard overpressures. A database of more than 30 wells has been

utilized to understand the distribution and generation of overpressures in intra-salt reservoirs that can be separated

by up to 350 m of salt. A temporal relationship of increasingly overpressured reservoirs within stratigraphically

younger units is observed, and two distinctly independent trends emerge from the Oman dataset; one hydrostatic

to slightly above hydrostatic and one overpressured from 17 to 22 kPa m)1, almost at lithostatic pressures. Struc-

tural, petrophysical and seismic data analysis suggests that overpressure generation is driven by fast burial of the

stringers in salt, with a significant contribution by thermal fluid effects and kerogen conversion. Structural and geo-

metric information indicates that present-day hydrostatic stringers have been overpressured in their earlier geologic

evolution. Evidence for these initial overpressures in currently hydrostatic reservoirs is provided by hydrocarbon-

veined cores from halite overlying the reservoirs. A proposed pressure deflation mechanism can be related to the

complex interplay of salt tectonics and fast deposition of early Cambrian to Ordovician age clastics.

Key words: intrasalt reservoirs, Neoproterozoic to Cambrian South Oman Salt Basin, overpressure generation and

deflation

Received 13 January 2011; accepted 20 May 2011

Corresponding author: Peter A. Kukla, Geological Institute, Wuellnerstrasse 2, RWTH Aachen University, D-52056

Aachen, Germany.

Email: [email protected]. Tel: +49 241 8095720. Fax: +49 241 8092151.

*Present address: ExxonMobil Upstream Research Company, 3319 Mercer St., Houston, TX 77027, USA.

Geofluids (2011) 11, 349–361

INTRODUCTION

Overpressures still represent one of the major challenges of

modern hydrocarbon exploration because of their impact

on safety, prospect risking and ranking, cost-effective dril-

ling and field development strategies. Overpressure in this

context refers to the difference between the fluid pressure

measured in a stratigraphic unit and the ‘normal’ hydro-

static fluid pressure in the pore structure of this unit. They

are encountered in many areas worldwide and have been

described frequently in clastic Tertiary delta sequences,

from carbonates of the Caspian region and from the North

Sea Basin (e.g. Huffman & Bowers 2002).

The mechanisms for generating overpressures have been

discussed extensively in the literature (e.g. Swarbrick et al.

2002 for review). These include compaction disequilibrium

because of rapid sedimentation which is regarded as a

major cause of nonhydrostatic pore pressures in low-per-

meability layers such as shale (Neuzil & Pollock 1983;

Audet & McConnell 1992; Luo & Vasseur 1995). Further

main mechanisms are attributed to fluid phase changes

(kerogen conversion, aquathermal expansion), mineral

transformations (e.g. smectite to illite transition) and lat-

eral pressure transmission (Swarbrick et al. 2002).

Each of these mechanisms can produce significant

overpressures if the geological conditions are favourable.

Geofluids (2011) 11, 349–361 doi: 10.1111/j.1468-8123.2011.00340.x

� 2011 Blackwell Publishing Ltd

However, in order for the fluid pressures to rise, the pres-

sures have to be contained by rocks with sufficiently low

permeability. Overpressures are transient and gradually leak

away over long periods of time when the generation mech-

anism ceases to operate. In cases of low-permeable rocks

(such as salt and shales), this process may take hundreds of

millions of years (Swarbrick et al. 2002).

Many authors have suggested that hydrocarbon genera-

tion can lead to fluid overpressure (Barker 1990; Forbes

et al. 1992; Luo & Vasseur 1996). Kerogen maturation

(‘kerogen to gas’) is still considered by some authors to

represent the major contributing factor to deep overpres-

sured basins that statistically are in most cases high-pres-

sured gas basins (Holm 1998). For calculation of volume

increase during kerogen conversion, most studies employed

simple fluid state approaches or assumed constant fluid

density. To date, there is still no general consensus as to

the relative importance of mechanisms chiefly influence

pressure development during hydrocarbon maturation

(Swarbrick et al. 2002). A more recent approach was pre-

sented by Hansom & Lee (2005) who utilized a combina-

tion of basin hydrology simulation including temperature

and pressure distribution with thermal maturation simula-

tion. The above model uses the Arrhenius kinetic model to

simulate conversion processes that result in an increase in

fluid volume and overpressures. In their model, the excess

pore pressure generated rose by 40% during oil generation

and up to 150% during contemporaneous oil and gas

(methane) generation. The addition of hydrocarbons, even

though they are more compressible than water, will act like

as an additional source of fluid and thus increase the fluid

pressure. In some instances, such as the North Sea, where

undercompaction does not appear to be the single main

pressure engine, the presence of a thick regional seal

together with hydrocarbon expulsion and cracking may

provide a plausible mechanism for generating hard over-

pressures.

Mineral transformation is another process that can con-

tribute to an early build-up of overpressures. In evaporite

settings, this is especially valid for the dewatering of thick

gypsum beds to anhydrite (Warren 2006). The depth of

transformation varies between a few metres to more than a

kilometre, depending on temperature, pressure and pore-

water salinities. At larger burial depth, pressure solution

contributes to overpressures in carbonates through the

generation of porosity-occluding subsurface cements. Sty-

lolitization usually affects limestones after a minimum

depth of 500 m of burial. Where dolomites are associated

with limestones, the former tend to be more resistant to

pressure solution.

Calculations of aquathermal effects in sedimentary basins

have shown that these are negligible over a wide range

of sedimentation rates and associated temperatures in

high-pressure basins (Swarbrick et al. 2002). Nevertheless,

although aquathermal pressuring is unlikely to be an impor-

tant pressure generation mechanism, it may be important in

some cases. Where reservoir rocks are sealed within near

perfect seals early in their burial history, aquathermal effects

can generate significant overpressures.

The generation and dissipation mechanisms of overpres-

sures encountered in reservoirs (and source rocks) isolated

in salt are to date only known from the North Sea Basin

(Permian Zechstein floaters in salt, Williamson et al. 1997)

and the Precambrian to Cambrian Ara Formation of Oman

which forms part of the South Oman Salt Basin (SOSB).

The latter system forms a unique setting in which both res-

ervoirs and source rocks constitute self-charging pressure

cells, sealed by salt. Such large rock inclusions encased in

salt (so-called rafts, floaters or stringers) are of broad eco-

nomic interest as they can constitute profitable hydrocarbon

reservoirs, but may also represent potential drilling risks

because of their hard fluid overpressures (Williamson et al.

1997; Al-Siyabi 2005; Schoenherr et al. 2007a, 2008).

The study of such stringer bodies also has strongly influ-

enced our understanding of the internal deformation

mechanisms in salt diapirs (Talbot & Jackson 1987, 1989;

Talbot & Weinberg 1992). Stringer geometries and associ-

ated deformation were extensively studied in surface pierc-

ing salt domes (Kent 1979; Jackson et al. 1990; Peters

et al. 2003; Reuning et al. 2009), and within mining gal-

leries in structurally shallow levels of various salt diapirs

(Richter-Bernburg 1980; Talbot & Jackson 1987; Geluk

1995; Behlau & Mingerzahn 2001). Additionally, recent

improvements in seismic imaging now allow the illustration

and analysis of large-scale 3D stringer geometries (van

Gent et al. 2011; Strozyk et al. in press). All these studies

reveal highly complex stringer geometries, such as open to

isoclinal folding, shear zones and boudinage over a wide

range of scales. These observations give valuable insights

into the processes occurring during final diapir evolution.

However, most salt structures have undergone a combina-

tion of passive, reactive and active phases of salt tectonics

(Mohr et al. 2005; Warren 2006; Kukla et al. 2008;

Reuning et al. 2009) which complicates the interpretation

of their stringer geometries. Moreover, the influence of

stringer deformation is of major importance for the

understanding of the diagenetic and fluid pressure evolu-

tion and hence reservoir properties of such stringer plays

(Schoenherr et al. 2008; Reuning et al. 2009).

Here, we use seismic and well data made available by

Petroleum Development Oman (PDO) with the objective

to present for the first time an evolutionary model for this

unique overpressure system. Key questions to be answered

were:

(1) Which of the numerous mechanisms of overpressure

generation apply to the Neoproterozoic SOSB and to

intra-salt carbonate reservoir and source rock sequences

in general?

350 P. A. KUKLA et al.

� 2011 Blackwell Publishing Ltd, Geofluids, 11, 349–361

(2) What are the controlling factors for overpressure dissi-

pation in the SOSB?

(3) What are the conditions for pressure deflation and leak-

age of hydrocarbons into rock salt?

GEOLOGICAL SETTING

The SOSB that constitutes the geologically oldest presently

known commercial hydrocarbon province worldwide is one

of three late Neoproterozoic to early Cambrian subsurface

salt basins of the interior Oman. They belong to a belt of

restricted evaporitic basins, which span from Oman to Iran

(Hormuz Salt) and Pakistan (Salt Range) and further to

the East Himalaya (Mattes & Conway Morris 1990; Allen

2007; Reuning et al. 2009). The western margin of the

SOSB is formed by the ‘Western Deformation Front’

(Fig. 1), a structurally complex zone with transpressional

character (Immerz et al. 2000). The eastern margin is con-

stituted by the so-called ‘Eastern Flank’ (Fig. 1), a struc-

tural high (Amthor et al. 2005).

The formation of the SOSB started with the

sedimentation of the Huqf Supergroup from the Late

Neoproterozoic until the Early Cambrian (approximately

725–530 Ma) on crystalline basement (Gorin et al. 1982).

Evaporite sedimentation dominated the Ediacaran to Early

Cambrian Ara Group that, together with the siliciclastic

Nimr Group, form the uppermost part of the Huqf Super-

group (Fig. 2). Radiometric dating of ash beds brackets

the age of the Ara Group in the SOSB between approxi-

mately 547 and 540 Ma, encompassing the Precambrian to

Cambrian boundary (Amthor et al. 2003; Bowring et al.

2007). In contrast to the underlying Nafun Group, the

Ara Group is characterized by tectonic compartmentaliza-

tion, strong subsidence and an onset of volcanism associ-

ated with sedimentation in a retro-arc setting between the

subducting margin of eastern Gondwana and the East

African Orogen (Allen 2007). During deposition of the

Ara Group, the SOSB was subdivided into three N–S

trending palaeogeographic domains. The Northern and

Southern Carbonate Domains were separated by a deeper

stratified basin with a water depth of up to several hundred

metres (Mattes & Conway Morris 1990; Amthor et al.

2005). At least six cycles of inter-layered carbonates and

evaporites were deposited in the carbonate domains of the

SOSB, termed A1 to A6 (Fig. 2) from bottom to top

(Al-Siyabi 2005). Increases in salinity led to the deposi-

tional succession carbonate-sulphate-halite, which in turn

proceeded into the succession halite-sulphate-carbonate

during the following brine-level rise and highstand (Mattes

& Conway Morris 1990; Schroder et al. 2003, 2005).

These carbonates formed partially isolated platforms that

are completely encased by evaporites and hence form the

stringers in the salt. The thickness of the Ara Salt varies

between 10 and 150 m in the A1 to A4 cycles and can

exceed 1000 m in the halokinetically stronger influenced

A5 and A6 sequences (Schroder et al. 2003). The sulphate

layers encasing the 20–220 m thick carbonate units are up

to 20 m thick. Bromine geochemistry of the Ara salt

(Schroder et al. 2003; Schoenherr et al. 2008) and marine

fossils (Amthor et al. 2003) clearly indicate a seawater

source for the Ara evaporites. The gypsum, later replaced

by anhydrite, formed in shallow hypersaline salinas (Schro-

der et al. 2003). The shallow-water carbonate ramp facies

consists of grainstones and laminated stromatolites, while

the platform margin is formed by stromatolites and

thrombolites. The slope facies includes organic-rich lami-

nated dolostones, and the basinal facies is dominated by

Fig. 1. Overview map of the Late Ediacaran to Early Cambrian salt basins

of Interior Oman (modified after Schroder et al. 2005 and Reuning et al.

2009). The study area (marked by the yellow rectangle) is located in the

southwestern part of the South Oman Salt Basin. The eastward-thinning

basin with sediment fill of up to 7 km is bordered to the west by the trans-

pressional ‘Western Deformation Front’ and to the east by the structural

high of the ‘Eastern Flank’.

Overpressure generation and deflation 351


Fig. 2. Top: Chronostratigraphic summary and burial history of rock units in the subsurface of the Interior Oman. The geochronology was adopted from

Al-Husseini (2010). The lithostratigraphy of the lower Huqf Supergroup was adapted from Allen (2007) and Rieu et al. (2007). The lithostratigraphy of the

upper Huqf Supergroup and the Haima Supergroup was adapted from Boserio et al. (1995), Droste (1997), Blood (2001) and Sharland et al. (2001). The

lithostratigraphic composite log on the right (not to scale) shows the six carbonate to evaporite sequences of the Ara Group, which are overlain by siliciclas-

tics of the Nimr Group and further by the Mahatta Humaid Group. Sedimentation of the siliciclastics on the mobile evaporite sequence led to strong haloki-

nesis, which ended during sedimentation of the Ghudun Formation (Al-Barwani & McClay 2008). Bottom: Burial graph (modified after Visser 1991) indicates

major phases of uplift and subsidence. Note fast burial associated with clastic sedimentation in the Cambrian and Ordovician during the salt-tectonic and

postsalt tectonic eras. Grey line represents iso-VRE curve (0.62) for base of oil generation window in this area (after Visser 1991).



sapropelic laminites (Al-Siyabi 2005). During seawater

highstands, oil kitchen areas have been formed in the dee-

per, periodically anaerobic to dysaerobic parts of the basin

(mainly slope and basinal mudstones). Density stratification

of seawater allowed preservation of a sufficient amount of

organic material in the bottom layers (Mattes & Conway

Morris 1990). The main reservoir facies of the A4 interval

comprises ‘crinkly’ laminites of the outer ramp and stro-

matolites and thrombolites of the inner ramp (Schroder

et al. 2005). The existence of A-norsterane biomarkers

unequivocally confirms that the hydrocarbon accumula-

tions originate from within the Ara group (Grosjean et al.

2009). The SOSB stringer play thus represents a unique

self-charging and self-contained petroleum system.

Subsequent deposition of continental siliciclastics on the

mobile Ara-Salt led to strong salt tectonic movements

(Al-Barwani & McClay 2008). Differential loading formed

clastic pods and salt diapirs, which led to folding and further

fragmentation of the carbonate platforms into isolated

stringers floating in the Ara-Salt (Figs 3 and 4). Early stages

of halokinesis started already in the early Cambrian with

deposition of the siliciclastic Nimr Group, sourced from the

uplifted basement high in the Western Deformation Front

(Figs 1–4). The main phase of salt tectonic movements con-

tinued during the deposition of the lower part of the Haima

Supergroup (Mahatta Humaid Group) until salt ridge rise

could not keep pace with the massive sedimentation of the

early Ordovician Ghudun Formation (Figs 2 and 3). Later

(A)

(B)

Fig. 3. (A) Un-interpreted seismic line crossing the study area. (B) Interpretation of the seismic line shown in A. The formation of salt pillows and ridges is

caused by passive downbuilding of the siliciclastic minibasin (Nimr Group) leading to strong folding and fragmentation of the salt embedded carbonate plat-

forms and the formation of the Ara stringers.



halokinetic movements because of reactivation of basement

faults or salt dissolution were of only local importance (Al-

Barwani & McClay 2008). Maximum burial depths

(temperatures), somewhat higher than the present 3 to

>5 km (60–125�C), were reached during Ordovician to

early Silurian times (Fig. 3) with a peak in hydrocarbon gen-

eration during the early Paleozoic (Visser 1991; Terken

et al. 2001; Schoenherr et al. 2007b). Fluid properties

within the carbonate stringers are highly variable with a wide

range in gas ⁄ oil ratios and API units (approximately 23� to

52�; Grosjean et al. 2009). Catogenesis likely was retarded

by the relatively low geothermal gradient of about

20� C km)1 in salt basin and the very high overpressures in

some of the stringers (Al-Siyabi 2005; Schoenherr et al.

2007a,b, 2008). The carbonate stringers have undergone

intense diagenetic modifications with locally extensive

cementation by halite and solid bitumen (Al-Siyabi 2005;

Schoenherr et al. 2008). Pore lining and filling solid bitu-

men is a common diagenetic phase that represents one of

the greatest risks for hydrocarbon exploration in the area

(Al-Siyabi 2005; Schoenherr et al. 2007a,b, 2008).

OVERPRESSURES IN THE SOUTH OMANSALT BASIN

Pore pressure data analysis

It has been shown in other parts of the world, especially the

North Sea Basin, that careful data analysis and quality con-

trol of pressure and leak-off data is an important first step

for studying the pressure generation mechanisms within a

basin (Gaarenstroom et al. 1992; Bloch et al. 1993).

To date, more than 70 wells drilled by PDO have pen-

etrated evaporite and intrasalt carbonate sequences in the

SOSB. For the purpose of this study, data from the main

producing stringer intervals A1 to A4 have been rigor-

ously checked for test type and test quality. The final

database that was utilized for further analysis and inter-

pretations consequently only included valid data from

Repeat Formation Tester (RFT) and production test

tools. Individual tests have been screened using field test

reports.

‘Brine correction’, which takes into consideration the

additional (capillary) pressures produced by the hydrocar-

bon fill of a reservoir, is in many basins essential for pro-

viding a common reference pressure to correlate and to

interpret pore pressures and aquifer continuity on a basin

scale. This correction was carried out for selected wells to

assess the magnitude of pressure difference. Depending on

the hydrocarbon column and geometry of the trap, addi-

tional pressures calculated at top reservoir range between

164 and 533 kPa which can be neglected given the overall

pressure magnitudes and depths.

The data plots provided in Fig. 5 clearly show two for-

mation pressure ‘populations’:

(1) One at near hydrostatic pressures with a mean pore-

pressure coefficient k = 0.49.

(2) One at near-lithostatic pressures with a mean pore-

pressure coefficient k = 0.87. Gradients range from

17 kPa m)1 to a maximum of 22.0 kPa m)1.

One field shows a gradient of 12.8 kPa m)1 (see Discus-

sion below).

Comparison of the data on a well to well basis and on

common trends or structures suggests a large degree of

compartmentalization of the respective reservoirs across

most fields. This is interpreted from a lack of common

hydrostatic gradients and hydrocarbon contacts. There are

cases however where data suggest communication between

hydrostatic reservoir intervals while overpressured reservoirs

are isolated (Fig. 4).

Leak-off pressure data analysis and prediction

In general, the relationship between the vertical and mini-

mum horizontal stresses, and the failure envelope of a rock

type as a function of depth, is a method for establishing

the conditions under which a trap will fail as a function of

increasing fluid pressure. The commonly performed leak-

off tests, usually carried out at casing shoe to estimate the

formation strength, provide the most readily available data

to assess formation strength. Leak-off pressure (LOP) mea-

surements can be shown to be greater than the minimum

principal stress.

Because of the unknown tensile strength of the rocks

and the inherent measurement errors, LOP measurements

are not a good measure of the minimum principal stress by

Fig. 4. 3D view of the Ara Formation in the study area derived from seis-

mic data (5· vertical exaggeration). Top and base salt horizons are colour-

coded according to depth. The top salt horizon demarcates the position of

siliciclastic minibasins and salt diapirs. Carbonate stringers of different strati-

graphic intervals (A1–A3) embedded in the salt are either hydropressured

(blue) or at near lithostatic pressures (red).



themselves. However, if quality controlled LOP data are

plotted together with RFT data from a regional dataset in

an overpressured area (Gaarenstroom et al. 1992), then a

pattern such as shown in Fig. 5 can be observed.

The LOP data from 17 SOSB wells (Fig. 5) show a distri-

bution in which 60% of the data plot at 22–23 kPa m)1

(Median 22.5) and 40% of the data plot at 23–25 kPa m)1

(Median 24.7). The mean value of all data is 23.5 kPa m)1.

Only tests that could clearly be identified as ‘leak-off’ and

not ‘limit tests’ have been included in the database and pres-

sure ⁄ depth graphs.

Note that there is little overlap between the RFT and

LOP data suggesting that the lower bound of the LOP

data defines the maximum fluid pressure that the rock can

hold. Indeed, in highly overpressured terrains, leaky traps

correspond to those with fluid pressures which lie on this

lower bound of the LOP data. Failure by hydraulic fractur-

ing would be expected to occur when the fluid pressure

(Pf) exceeds the sum of the minimum principal stress (r3)

and the tensile strength of the rock. The minimum hori-

zontal stress envelope, encompassing minimum LOP data

and maximum RFT data, has a gradient of 22 kPa m)1 in

the SOSB (Fig. 5).

Overburden stress has been carefully calculated using

average formation densities determined from density logs.

Combining this with measurements of differential stress

from subgrain size piezometry shows that the minimum

and maximum principal stress in the salt surrounding the

stringers is within the thick line drawn in Fig. 5 (little is

known of the orientations of the principal stress in salt).

Overpressures and structure

In considering the evolution of overpressured basins, the

role of tectonics cannot be overemphasized. Especially in

large salt basins like the SOSB or the North German Basin,

a complex structural evolution can only be handled by

linking palinspastic restoration with multi-dimensional

basin modelling (Mohr et al. 2005; Kukla et al. 2008).

Considering structuration, it is important to note that all

A3-aged stringers drilled so far in the SOSB have been

overpressured with only one exception in the northern part

of the licensed cluster. In contrast, A2-aged reservoirs have

been encountered both overpressured and hydropressured

(Figs 4 and 6) where hydropressured wells occur in the

central basin and a strongly overpressured domain occurs

further south (Figs 4 and 6).

Based on the available map database, a regional 3D over-

view of the respective stringer intervals, shown in Figs 4

and 6, confirms their heterogeneous size and distribution.

A2 shows a separation in one exploration cluster compris-

ing a connected central ⁄ northern area with hydropressured

wells and a southern area with disconnected A2 ‘rafts’.

These show different magnitudes of overpressures which

suggest that they represent individual pressure cells. The

large siliciclastic pod (Nimr to Mahatta Humaid Group)

Fig. 5. Selected formation pressures of the Ara carbonates (circles) versus depth. The plot shows two different pressure populations: one at near-hydrostatic pres-

sures, with a mean pore-pressure coefficient k = 0.49 (black circles), and one at near-lithostatic pressures, with a mean pore-pressure coefficient k = 0.87 (grey

circles). Black triangles are leakoff test (LOT) data, and z is depth in metres. The thick black band represents the range of differential stress difference (r1–r3

[maximum principal stress - minimum]) in rock salt as derived from integrated density logs and subgrain size piezometry. tvdbdf, true vertical depth below derrick

floor (updated from Schoenherr et al. 2007a).



on A2 level represents a striking feature in this area

(Figs 3, 4 and 6). Regionally less widespread are A3 string-

ers in the south of this minibasin.

A more detailed 3D-analysis of the areas characterized

by hydropressured and overpressured stringer domains

revealed that large structural boundaries separate the

northern hydropressured A2 domain from the southern

overpressured domain between which pressure differentials

of up to 12 kPa m)1 can be maintained (Fig. 6).

The hydropressured stringers close to the centre of the

siliciclastic minibasins are structurally highly segmented

(Figs 4 and 6). A strong influence of minibasin formation

on stringer breakage was also predicted by finite-element

modelling (Li et al. in press). Seismic sections show that

stringers underneath the clastic pods nearly touch the

flanks of the minibasins (Fig. 4). As a consequence, pres-

sures and hydrocarbons could have bled off into the over-

lying formations of the Haima Supergroup (Fig. 2) during

the early structural evolution.

Pressures and the sealing capacity of rock salt

It has been an observation in the SOSB since about

15 years that retrieved salt cores were occasionally stained

black (Fig. 7). In some cases, up to 10 m of vertical salt

core section contained hydrocarbons mostly above stringer

intervals (Schoenherr et al. 2007a). Petrographic and fluid

inclusion analysis confirmed that halite samples contain

bands with lm-sized fluid inclusions, which alternate with

thin fluid inclusion-free bands. Hydrocarbon-impregnated

microcracks are frequently filled with solid bitumen

(Fig. 8), and samples also contain fluid inclusion trails with

oil inclusions and gas bubbles. Microstructural analysis fur-

ther shows evidence for crystal plastic deformation and

dynamic recrystallization (Schoenherr et al. 2007a). Sub-

grain-size piezometry following the method of Schleder &

Urai (2005) indicates a maximum differential paleostress of

<2 MPa (Schoenherr et al. 2007a) in rock salt adjacent to

carbonate stringers. The experimentally derived dilatancy

criterion by Popp et al. (2001) indicates that at a differen-

tial stress of <2 MPa, rock salt can dilate only at near-zero

effective stresses (Fig. 7). This is only possible at great

depth when fluid pressure in the rock salt is very close to

the minimum principal stress r3.

A model for the pore-fluid connectivity in the deeply

buried SOSB has been proposed by Schoenherr et al.

(2007a), based on the results of Lewis & Holness (1996),

who measured the equilibrium water-halite dihedral angles

at grain boundary triple junctions in experiments. If the

dihedral angle is higher than 60�, small amounts of pore

fluids in the halite are distributed in micrometre-sized iso-

lated fluid inclusions, and the permeability is reduced to

zero. At temperatures and pressures corresponding to a

depth of approximately 3 km in a ‘normal’ geothermal gra-

dient, the dihedral angle decreases to 60� and below, lead-

ing to a redistribution of the pore fluid into a

thermodynamically stable three-dimensional network of

Fig. 6. Map view of the area shown in Fig. 4. Top salt horizon is colour

coded according to depth. Light blue indicates siliciclastic pods, yellow to

red colours represent salt diapirs. Two regional pressure domains can be

distinguished. Hydropressured carbonate stringers of the A2 interval (blue)

are situated underneath a large siliciclastic minibasin. Overpressured string-

ers of the A2 and A3 interval (red) are located adjacent to the minibasin

centre.

Fig. 7. Effective stress versus differential stress diagram for rock salt (modi-

fied from Popp et al. 2001). The dilatancy boundary separates domains

where microcracking is suppressed (compaction domain) from those where

rock salt dilates. If the differential stress values obtained by subgrain size

piezometry are combined with the dilatancy criteria of the Ara Salt, the

effective stress in the Ara Salt is inferred to be <1 MPa (modified after

Schoenherr et al. 2007a). Inset shows salt plug sample from an interval

between two presently hydropressured carbonate stringers. The salt is

stained black by solid bitumen.



connected, fluid-filled, channels at grain boundary triple

junctions (Fig. 8). If halite contains several per cent of

brine in connected triple-junction tubes, and this brine is

at pressures less than lithostatic, halite should compact and

expel some of the brine, thereby decreasing its permeabil-

ity. This will lead to an interconnected, brine-filled poros-

ity along the triple junction tubes with a near-lithostatic

fluid pressure.

DISCUSSION

The data presented above can be integrated to represent a

model for the burial, pressure conditions (and hence fluid

movement) and ultimately the sealing potential of rock salt

embedded with a unique self-charging carbonate source

rock and reservoir petroleum system in the deep subsurface

of southern Oman.

Figure 9 displays our preferred model for the burial

and fluid pressure path of an Ara formation reservoir

stringer. Compaction and cementation leads to nearly

zero porosity in rock salt below a burial depth of 30 m

(Casas & Lowenstein 1989), marking the change from

diagenetic open to closed system conditions in the under-

lying carbonate platform. The isolation of the stringer

sequence leads to an increase of fluid pressures by a dis-

equilibrium compaction mechanism. Salt-sealed overpres-

sured intervals can be as shallow as a few hundreds of

metres below the surface because of the salt’s very low

permeability (Hunt 1990). The pressure boundaries

between a salt seal and a reservoir beneath can be very

abrupt, which represents a potential operational risk when

drilling through laterally constrained ‘stringers’ or ‘rafts’

of overpressured anhydrite and dolomite enclosed in hal-

okinetic salt. Compaction of the encased stringers is

increased because of the higher mean stress than in a salt-

free sequence because of the very high principal stress.

However, compared to mud-rich siliciclastic systems, the

effects of disequilibrium compaction are reduced because

of the very early onset of cementation in carbonates, e.g.,

(A)

(B)

(C)

(D)

Fig. 8. Diagram of the mechanism of diffuse dilatancy of the Ara Salt. (A)

Diagram of Lewis & Holness (1996). The basic assumption of our model is

that the Ara Salt had a connected pore-fluid topology at the time of leak-

age. This is based on paleotemperature calculations and pressure data (e.g.;

approximately 95�C and approximately 65 MPa for one of the stringers).

These data (black dot) plot in the light-grey area, in which permeability in

halite is already significant (h approximately 60�). (B) Detailed view of the

interface of stringer reservoir and Ara Salt. Halite has a low interconnected

porosity represented by the triangular space between the grains (cut per-

pendicular to the triple junction tubes). The black dot in the schematic pres-

sure-versus-time diagram inset indicates that the oil pressure (Poil) is equal

to r3 in the Ara Salt at a certain point in time. (C) Because of further over-

pressure build-up by mechanisms described in the text, Poil in the stringer

exceeds the minimum principal stress (r3) of the salt by the capillary entry

pressure (Pc), allowing the entry of oil into the triple junction tubes of the

salt, leading to a diffuse dilation of the Ara Salt by grain boundary opening

and intragranular microcracking. (D) Continuous layer of solid bitumen

(confirmed by EDX analysis) in grain boundaries (white arrow). Scanning

electron microscopy image of a broken salt sample (modified after Scho-

enherr et al. 2007a).



during reflux dolomitisation. This will lead to a rapid

development of close to lithostatic pressures in the string-

ers, constrained by the minimum stress in the salt indi-

cated in the diagram.

At a certain point in time, the hydrocarbon generation

window will have been reached, and an additional contri-

bution of pressure generated by this mechanism will fur-

ther add to the overpressure magnitude as modelled by

Hansom & Lee (2005). The oil pressure in the carbonate

reservoirs increases until it is equal to the fluid pressure in

the interconnected porosity of the Ara Salt plus the capil-

lary entry pressure (Figs 8 and 9).

In our model, the oil pressure in the stringers slightly

exceeded the minimum principal stress in the salt (near

lithostatic fluid pressure) at some stage in the geologic

evolution. During this process, the oil pressure is high

enough to open the grain boundaries and to displace the

brine in the pore throats of the salt, causing a diffuse

dilatancy. Most likely, this violation of the minimum stress

criterion marks the ultimate sealing capacity of halite in the

deep subsurface whereby its permeability increases by

orders of magnitude (Popp & Minkley 2010). It is impor-

tant to note that the sealing capacity is regained, if the

fluid pressure drops below the minimum principal stress, at

which point rock salt will re-seal to maintain the fluid pres-

sure close to lithostatic values (Fig. 9).

Hydrocarbon-impregnated black rock salt in and adja-

cent to hydrostatic and overpressured reservoirs hence

shows that it has repeatedly lost and then regained its seal-

ing capacity. It also confirms that currently hydrostatic res-

ervoirs have been overpressured in the past. The black

staining is caused by intragranular microcracks and grain

boundaries filled with solid bitumen formed by the alter-

ation of oil (Fig. 8).

In triaxial deformation experiments of Lux (2005), rock

salt became permeable by the formation of grain boundary

cracks at low rates of fluid-pressure increase. If the fluid

pressure (Pf) is increased rapidly to a sufficiently high excess

Fig. 9. Schematic figure illustrating mechanisms of overpressure generation and pressure deflation in the Ara Stringers. The hydrostatic pressured stringers

become overpressured as soon as the stringers are sealed by impermeable salt. Hydrocarbon generation inside the self-charging stringers causes an additional

fluid pressure increase. If the overpressured stringers come in contact with a siliciclastic minibasin, they will deflate and return to hydrostatic pressures (A).

When the connection between the minibasin and the stringers is lost, they regain overpressures because of further oil generation and burial (A’). If hydrocar-

bon generation in undeflated stringers stops relatively early, the fluid pressures do not reach lithostatic pressures (B). If hydrocarbon generation continues,

the fluid pressures exceed the lithostatic pressure (red star), leading to dilation and oil expulsion into the rock salt (C, D and E). A stringer enclosed by black-

stained salt below the lithostatic gradient likely indicates a later deflation event causing either a complete (C) or partial (E) loss of overpressures. Alternatively,

stringers at overpressures but below the lithostatic gradient (E) might be explained by regional cooling or some other hitherto unexplained mechanism.



pressure (Pf > s3), rock salt leaks by hydrofracturing. Peach

& Spiers (1996) proposed that this process could also occur

under low effective stress during natural deformation of

rock salt at great depth and high pore-fluid pressures. Based

on our observations and calculations, we infer that the oil

pressure did not rise to significantly higher values because

this would have generated discrete hydrofractures which to

date have not been observed in the SOSB instead of fea-

tures interpreted to be caused by diffuse dilation.

Two other mechanisms that likely contributed to the

observed overpressures are gypsum dewatering and hydro-

thermal processes. Petrographic evidence indicates that

anhydrite largely replaced primary gypsum in the Ara suc-

cession (Schroder et al. 2003). The anhydrite layers encas-

ing the 20–220 m thick carbonate units are up to 20 m

thick. Dewatering of gypsum to anhydrite is accompanied

by the release of approximately 60% water per unit volume

gypsum (Hardie 1967). In the presence of highly saline

porewater, anhydrite to gypsum transformation can start at

burial depth of a few metres and is completed at less than

approximately 125 m depth (Bauerle et al. 2000). A signif-

icant fraction of the generated water hence might have

escaped before the stringers were completely sealed by salt.

The contribution to overpressure generation therefore

remains difficult to quantify.

A hydrothermal influence is indicated for at least one of

the Ara stringers by extremely high bitumen reflectance

values, which point to maximum paleo-temperatures of

more than 100�C above the maximum burial temperatures

(Schoenherr et al. 2007b). The influx of hydrothermal fluids

into the carbonate stringers is considered a possible contri-

bution to the overpressures (Schoenherr et al. 2007b), but

might have been of only local importance.

The observed 3D geometrical distribution of the two

pressure domains suggests that the siliciclastic minibasins

may have acted as a pressure valve at some point in time

during sedimentary downbuilding into the salt (Fig. 9).

The duration of the deflation event would have been

restricted in time, but both timing and duration cannot be

constrained at present. The geometrical position of the

individual stringer bodies in relation to the clastic

sequences thus determines the pressure history through

time. In one of the hydrocarbon fields mentioned above,

an intermediate pressure gradient of 12.8 kPa m)1 has

been observed. Separate hydrocarbon phases and pressure

gradients in up-dip fields suggest that the stringer

sequence is currently disconnected. Structural modelling

indicates however that these have been connected in the

past (Li et al. in press) and that deflation has occurred dur-

ing connection with the minibasins. Subsequent movement

of the stringer has led to breakage, resealing and re-pres-

suring of the stringer. Present-day intermediate overpres-

sures thus reflect the additional pressure re-charged by

kerogen maturation since the leakage event (Fig. 9).

The pressure data from fields being very close to the

minimum principal stress in the surrounding salt suggest

that these reservoirs are at present leaking fluids into the

surrounding salt or are very close to doing so. However,

the pressure data of many other overpressured fields are up

to 5 MPa below the minimum principal stress in the sur-

rounding salt and therefore at pressure significantly below

leaking (Fig. 5). If we assume that these have all leaked at

one point in the past, the deflation to the present-day pres-

sures is puzzling. It may be explained by regional cooling

or some other hitherto unexplained mechanism (Fig. 9).

CONCLUSIONS

(1) The Late Neoproterozoic to early Cambrian SOSB

contains a unique self-charging system with respect to

hydrocarbon and overpressure generation and dissipa-

tion. Reservoir intervals of low-permeable dolomites

and anhydrites frequently contain hard overpressures

and are fully enclosed in large Ara salt diapirs. The ver-

tical and lateral distribution of pressure and hence res-

ervoir compartmentalization could be quantified based

on a quality-controlled unique dataset comprising

structural, petrophysical and seismic data.

(2) Pressure generation and deflation mechanisms are con-

trolled by salt tectonic, microstructural (grain bound-

ary network) and thermo-kinetic (burial and kerogen

conversion) constraints and parameters.

(3) The sequence of events includes initially fast burial and

early overpressure generation by disequilibrium com-

paction, thermal fluid effects and kerogen conversion.

Pyrobitumen confirms local contribution by a high-

temperature hydrothermal event.

(4) Pressure deflation responsible for presently hydropres-

sured reservoirs is conceivable by structural configura-

tions to adjacent clastic minibasins or by further

isolation and fluid injection into surrounding rock salt

once minimum principal stress levels have been

reached to dilate the salt. This is witnessed by black,

hydrocarbon-stained cores of Ara salt directly above

and below some of the stringer reservoirs.

(5) The processes revealed in this study are considered sig-

nificant for other evaporite basins.

ACKNOWLEDGEMENTS

The authors are grateful to Petroleum Development Oman

LLC (PDO) and to the Ministry of Oil and Gas Oman for

granting permission to publish this study. We thank PDO

for sponsoring and for providing the samples and support-

ing data. Especially PDO staff Aly Brandenburg, Joachim

Amthor, Jean-Michel Larroque, Zuwena Rawahi, Hisham

Al Siyabi and Paul Taylor are thanked for their invaluable

input to the project. Till Popp and an anonymous reviewer



are thanked for their thorough reviews that greatly

improved the manuscript.

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Volume 11, Numbers 4, November 2011ISSN 1468-8115

Geofluids

This journal is available online at Wiley Online Library. Visit onlinelibrary.wiley.com to search the articles and register for table of contents and e-mail alerts.

Geofluids is abstracted/indexed in Chemical Abstracts

CONTENTS

343 Geologically driven pore fluid pressure models and their implications for petroleumexploration. Introduction to thematic setS. O’Connor, R. Swarbrick and R. Lahann

349 Distribution and mechanisms of overpressure generation and deflation in the lateNeoproterozoic to early Cambrian South Oman Salt BasinP.A. Kukla, L. Reuning, S. Becker, J.L. Urai and J. Schoenherr

362 Overpressure generation by load transfer following shale framework weakening dueto smectite diagenesisR.W. Lahann and R.E. Swarbrick

376 Velocity modeling workflows for sub-salt geopressure prediction: a case study fromthe Lower Tertiary trend, Gulf of MexicoJ. Taylor, T. Fishburn, O. Djordjevic and R. Sullivan

388 Integrating a hydrodynamically-titled OWC and a salt-withdrawal depositional modelto explore the Ula TrendS. O’Connor, H. Rasmussen, R. Swarbrick and J. Wood

gfl_11_4_content_OC 10/24/2011 4:25 PM Page 1

Documents

Distribution and mechanisms of overpressure … words: intrasalt reservoirs, Neoproterozoic to Cambrian South Oman Salt Basin, overpressure generation and deﬂation Received 13 January