Research & TechnologyMemoir No. 7

DISTRIBUTION OF HYDROCARBONS IN SEDIMENTARY BASINS

The importance of temperature

CONTENT

Introduction 3Hydrocarbon trapsHeat, pressure and diagenesisConfronting conventional wisdom

Porosity, permeability and hydraulic fractures 6Porosity and permeability evolution in sandstones and shalesHydraulic fracture mechanisms

Summary

The Golden Zone concept and its implications 10Thermal zonationPractical implicationsDenouement

Selective bibliography 14

AUTHORS’ NOTEThe key to reducing exploration risk is the combining of geological and geophysical approaches. The Golden Zone concept must therefore be seen as an exciting, yet somewhat provocative addition to the overall exploration toolkit.

Ongoing research may also reveal unforeseen modifi cations or even chip away at some of the basic tenets. Nevertheless, if exploration geoscientists are persuaded to pay more attention to the importance of temperature in predicting the global occurrence of hydrocarbon accumulations, the authors have done their job.

The text has been deliberately simplifi ed to clarify the concept, and the line drawings, although based on a wealth of genuine information, are likewise idealized models of reality.

ACKNOWLEDGMENTS The research summarized in this memoir was carried out by co-authors Per Arne Bjørkum, Paul Nadeau, Olav Walderhaug and associates, partly before but mainly after they were employed by Statoil. They would like to thank the following experts for helpful discussions on specifi c diagenetic aspects: Knut Bjørlykke, Stephen N Ehrenberg, Eric H Oelkers and Nils E Aase. Statoil publication was sanctioned by Ingve R Theodorsen, Bill Maloney, Tim Dodson, Morten Rye-Larsen and John Reidar Granli. Knut Georg Røssland kindly undertook a detailed review of the penultimate manuscript and Tony Boassen provided the ESEM/backscattered electron images.

AWARDPaul Nadeau received the 2000 Schlumberger Medal “in recognition of scientifi c excellence in mineralogy and its applications”. The award was presented at a meeting of the Mineralogical Society on the 4th of January 2001 in the Great Hall of Durham University (UK).

Antony T Buller (series author), Per Arne Bjørkum*, Paul Nadeau* & Olav Walderhaug* Designer: Bente Lie, GTS, Statoil Research CentrePublisher: Statoil ASAPrinter: NetprintPublication date: August 2005

*Contact for further information.

2 MEMOIR SERIES

MEMOIR SERIESThis R&D Memoir Series summarizes cumulative achievements made by Statoil researchers and their associates in key technical areas: care is thus taken to differentiate between achievements made by Statoil alone and those resulting from external cooperation. The intended readership is anyone with a technical overview of the petroleum industry. No specialist knowledge of the subject is required.

INTRODUCTION 3

INTRODUCTION

Statoil researchers have laid the foundation for a paradigm shift in exploration thinking that transforms perceived geological complexity into a global pattern of elegant simplicity.

Hydrocarbon traps

A trap requires a charge system, reservoir rocks and an effective seal

Now that many of the world’s largest fi elds have been accounted for, explorers are increasingly turning their attention to fi nding subtle traps in mature basins and opening up challenging frontier areas, such as the Arctic and ultra-deep water Atlantic margins.

The time is therefore ripe to introduce a step change in the industry’s understanding of how hydrocarbon accumulation works, starting with a summary of the basic principles.

Simply stated, the entrapment of oil and gas depends on the timely coincidence and fortuitous arrangement of three geological components: a petroleum charge system; high quality reservoir rocks; and an effective seal.

The charge system consists of organic-rich source rocks1 that are capable of generating and expelling hydrocarbons.

As source rocks are buried deeper and exposed to

increasingly higher temperatures, their kerogen content is chemically broken down and converted into hydrocarbons. Oil generation may start at about 110 °C (and continue to about 140 °C), followed by gas generation at about 120 °C (or higher).

During this process, the hydrocarbons move (migrate) through the source rock and are eventually expelled into the overlying sediment column where some of them may accumulate in reservoir rocks.

Accumulation, however, does not guarantee preservation. This depends on the sealing capacity of the overlying cap rock sequence, which is normally a low permeability mudrock or shale.

If the cap rock becomes fractured, some of the escaping hydrocarbons may accumulate in reservoir rocks higher up in the sedimentary succession – a process known as re-migration.

The trick, of course, is to fi nd present-day traps whose cap rocks are intact, and whose reservoir rocks are (i) suffi ciently porous2 to contain commercial quantities of hydrocarbons and (ii) suffi ciently permeable2 to allow them to fl ow fast enough towards production wells.

1 Source rocks normally consist of fi ne-grained sediments (mudrocks and shales) that are rich in organic matter derived from marine or lacustrine algae and land plants. The organic matter has to be insoluble to ensure its preservation during burial, and must therefore have been originally deposited in wet, muddy environments devoid of oxygen. This insoluble material is known as kerogen.

2 Porosity is expressed as the percentage bulk pore volume of a rock, irrespective of whether pores are interconnected or isolated. Permeability is a measure (in milliDarcies, mD) of the relative ease with which fl uid fl ows through a porous rock.

Spill point

Shale

Oil legGas-oil contact

Oil-water contact

Verticalclosure

Cap rock

Shale

Shale

Gas

Oil

WaterSource rock

Sandstone

The prerequisites of hydrocarbon entrapment and standard descriptive terms. Although there are many trap confi gurations, the one shown here – an anticlinal fold – is perhaps the simplest. The single-headed arrow depicts the primary migration of oil and gas from a maturing source rock into an overlying sandstone reservoir.

4 INTRODUCTION

Heat, pressure and diagenesis

The predominant dynamic controls on hydrocarbon distribution are heat, diagenesis and fl uid pressure

Heat is largely derived from deep in the earth’s crust and fl ows upwards through conductive, sediment-fi lled basins. The deeper one drills, the hotter the rocks and their contained fl uids become. This phenomenon is expressed by geothermal gradients, which defi ne the average, linear rate of increase in temperature per kilometre depth of burial.

Geothermal gradients can range from over 80 oC per kilometre in hot basins (e.g. the Bombay basin) to less than 20 oC per kilometre in cold basins (e.g. in parts of the Gulf of Mexico).

The global average for sedimentary, oil-bearing basins is about 30 oC per kilometre, which is slighly less than that encountered on the Norwegian continental shelf (NCS).

Pressure also increases with depth, but in a less obvious fashion. With reference to the fi gure, hydrostatic pressure is that imposed by a static, unbroken column of formation water held in the pores. This implies that if the water were free to rise in a borehole it would reach the surface. The curve to the right shows the lithostatic pressure gradient, which represents the total load of the overlying water-saturated sediments – the overburden.

These two curves defi ne the limits between which the pressure of pore fl uids in a sediment column normally varies.

Initially, the pore pressure closely follows the hydrostatic boundary, but at a certain depth in a given basin it swings towards the lithostatic limit.

From the point of departure, a state of overpressure is said to exist. In other words, at and beyond the overpressure ‘ramp’ the fl uid pressure at a given depth is considerably greater than the hydrostatic pressure.

The difference between the normal hydrostatic pressure and that approaching the lithostatic limit is thus a matter of fl uid containment, and is therefore related to the hydraulic conductivity or overall permeability of a sedimentary succession.

The depths at which overpressure ramps occur in nature vary considerably from basin to basin.

Both pressure and heat control diagenesis – the process by which unconsolidated sediments are converted with time and burial into sedimentary rocks through physical consolidation and compaction (mechanical compaction) and the chemical precipitation of new minerals (chemical compaction). New minerals, which may occur as grain coatings, pore linings or pore fi lls, often tend to cement and thereby strengthen the rock framework.

All of these phenomena alter the geometries, sizes and interconnections of pores, which usually lead to a loss in porosity and permeability. Reductions in pore space also result in the expulsion of vast quantities of formation fl uids from the rocks, which fl ow upwards through the sediments.

Pore water pressure

Effective stress

Overpressure

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Pressure (M Pa)

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Hydrostatic pressure gradient

Lithostatic pressure gradient

Ramp

Generalized depth plot of subsurface pressure regimes on the Norwegian continental shelf.

Note that the pore pressure ramp marks a departure of the pore fl uid pressure curve away from the hydrostatic pressure gradient towards the lithostatic pressure gradient.

This is accompanied by a build up of overpressure and a reduction of effective stress (the difference between lithostatic and pore water pressure).

Statoil geologists studying Jurassic sandstone and shale sequences in East Greenland. These rocks are very similar to hydrocarbon-bearing intervals encountered in sedimentary basins beneath the Norwegian Sea.

(Photos: Øyvind Hagen.)

INTRODUCTION 5

Confronting conventional wisdom Deep diagenesis results from thermo-chemical reactions

Subsiding sedimentary basins are therefore dynamic entities when viewed over geological time.

However, certain present-day geological features, such as the stratigraphic framework3 and the superimposition of tectonic and structural disturbances4, can be indirectly – if somewhat coarsely – determined by using geophysical techniques and information from wells that happen to be in the vicinity of an enticing prospect5. But the crucial aspects of hydrocarbon expulsion, migration and accumulation, which commonly take place over tens of millions of years, have to be predicted.

Up until now, quantitative models of porosity, permeability and pressure evolution in sedimentary basins have mainly been based on mechanical compaction. Porosity (and hence permeability) loss is thus thought to be controlled by effective stress; that is, the total pressure exerted on sediment grain contacts by the overburden minus the fl uid pressure. This physically pushes loose sand grains, silt particles and clay minerals ever closer and harder together while the interstitial water is

Quartz grain

Quartz cement

Feldspar grain

Clay mineral

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Porosity

squeezed out. This mechanism works well for the early stages of burial; however, it has been widely assumed that the same process (effective stress) controls the precipitation of mineral cements at deeper burial.

The validity of using effective stress as the controlling parameter for porosity loss at depth is hereby challenged, not least because the effective stress is at a minimum below overpressure ramps and may thereafter remain low and almost constant. Porosity loss and permeability reduction should therefore come to a halt, which is far from the truth.

After 15 years of studying the diagenesis of sandstones6 and shales7 on the NCS, Statoil researchers argue that beyond a certain depth the main controlling force behind the diagenetic reduction of porosity and permeability is temperature – not effective stress. Deep diagenesis consequently results from time-temperature controlled (thermo-chemical) reactions, which generate overpressure because the fl uids are unable to escape fast enough through the rock matrix as porosity is reduced.

As will be seen, this empirically verifi able, yet controversial theory helps to transform perceived geological complexity into a global pattern of elegant simplicity, and has important consequences on our understanding of hydrocarbon migration and accumulation.

3 The distribution and arrangement of sedimentary strata.

4 Tectonic and structural disturbances are manifested as folds, faults and fractures. A fault is a plane or zone of weakness along which rock masses break and whose sides are signifi cantly displaced relative to one another. A fracture is a small-scale rupture that may or may not involve displacement.

5 A prospect is a potential hydrocarbon trap judged worthy of detailed evaluation.

6 Unless otherwise stated, sandstones are medium-grained sedimentary rocks that consist mainly of sand-sized grains of the mineral quartz (SiO2).

7 Shales originate as watery mud and mudrocks that become harder during burial as the interstitial water is squeezed out. They often contain about 70% or more clay-sized minerals.

Cartoon illustrating the mechanisms and thinning of sedimentary rocks during burial as a result of mechanical and chemical compaction. The initially loose framework or packing confi guration of freshly deposited sand grains (left) is initially compacted by mechanical forces (centre) and thereafter by the chemical precipitation of quartz cement (right).

Examples of sandstone compaction, ranging from a shallowly buried, high porosity, un-cemented sample (left) to a deeply buried, extremely low porosity, quartz cemented sample (right). Compaction stages are schematically illustrated in the cartoon below.

(Images: Tony Boassen and Per Arne Bjørkum.)

6 POROSITY, PERMEABILITY AND HYDRAULIC FRACTURES

POROSITY, PERMEABILITY AND HYDRAULIC FRACTURES New approaches point to a common basis for describing all processes instrumental in reducing porosity and permeability in siliciclastic1 sediments, and predicting their impact on pressure development, fl uid migration and hydrocarbon entrapment.

Porosity and permeability evolution in sandstones and shales

Studies on the Norwegian continental shelf suggest that porosity and inter-dependent permeability loss are mechanically driven during early burial and thermo-chemically driven during deeper burial

It has long been known that diagenetic changes in deeply buried NCS sandstones and shales involve widespread chemical compaction. However, there has been a divergence of opinion as to how this takes place.

SandstonesOne view was that the source of the silica needed for quartz cementation – the main cause of sandstone porosity loss – is largely external to the rock; that is, the silica is sourced from the upward fl ow of formation water squeezed out from below. It was also believed that chemical diagenetic processes cease in the presence of hydrocarbons, because hydrocarbons block the fl ow of water.

An alternative view was that the chemical processes take place in a closed system (i.e. in the rock itself) and that the fl ow of water from beneath has little or no effect. This requires that the silica is sourced from the in-situ dissolution of the quartz grains themselves, and depends on the effective stress exerted at the points or areas of contact of the quartz grains – a phenomenon known as pressure solution.

In a seminal series of published papers (see pp. 14 to 15), Statoil authors and their co-workers agree that the source of quartz cement is indeed internal. However, they differ radically by asserting that dissolution is governed by a pressure-insensitive chemical catalytic process, which takes place at the interfaces2 between quartz grains and the minerals mica and/or illite3. The concept of pressure solution as a mechanism for providing

the source of the cement is therefore contested. What’s more, they argue that the process is time-temperature controlled, as in any chemical reaction.

Quartz cementation is therefore described as a three-stage process: quartz grain dissolution, followed by diffusion of the dissolved products and precipitation – the latter being the slowest of the three reactions. The rate of deep porosity loss is thus controlled by the rate of thermo-chemical quartz precipitation and the available area of the quartz grains over which quartz cement coatings (overgrowths) can be attached.

All that is needed to predict porosity loss in a sandstone with a certain quartz surface area is a relatively straightforward estimate of temperature history.

A micro-stylolite (outlined in red) weaving its way between interpenetrating (dissolving) quartz grains. Remnant pore spaces are blue. (Photo: Olav Walderhaug.)

Pore-fi lling quartz cement in the form of small quartz overgrowths, displaying well-developed crystal faces. (Image: Tony Boassen.)

2 The interfaces are micro-stylolitic; i.e. they consist of microscopic zigzag surfaces between interpenetrating (dissolving) quartz grains. They are made visible by insoluble residues of illitic clay minerals, micas and iron oxides.

1A collective term for silica-dominated sandstones and shales.

50.0 μm

0.5 mm

3 Micas are sheet silicates, which break up into thin elastic laminae and range in colour from transparent to silver and black. Illite is the name of a group of mica-like clay minerals.

POROSITY, PERMEABILITY AND HYDRAULIC FRACTURES 7

These conclusions have been built into a commercial software modelling package, EXEMPLAR™4. At temperatures below about 70 oC, the traditional principle of mechanical compaction is used because porosity loss is a function of effective stress. This is easily determined because the pore pressure is approximately hydrostatic.

At temperatures above about 60 to 80 oC, porosity loss is modelled as a function of thermo-chemical reactions.

This greatly simplifi es matters because it is no longer necessary to use effective stress as an input parameter, which at these temperatures is highly uncertain.

Further simplifi cation is achieved by refuting the idea that porosity reduction stops in the presence of hydrocarbons5.

Other signifi cant results are that: (i) at temperatures above 70 oC the rates of porosity loss due to quartz cementation – and therefore fl uid expulsion – increase exponentially; and (ii) at temperatures above 120 oC porosity loss is suffi ciently rapid to generate hard overpressures where drainage is limited (i.e. where there is no

opportunity for the pressure to be reduced by fl uids migrating through highly permeable rocks). Hard overpressure in sealed NCS pressure compartments starts at about 120 oC.

ShalesBroadly similar conditions apply to shales, which commonly undergo a widespread diagenetic mineral reaction that starts gradually at 60 oC when even minute quantities of the clay mineral smectite are converted to iIlite.

Traditionally, this reaction has been ascribed to a process involving the in-situ replacement of smectite by illite, accompanied by an increase in the amount of free water and the concomitant development of overpressure.

As illite has a smaller surface area than smectite, it was thought that shale permeability would slightly increase. In practice, however, permeability decreases. Neither this nor the observed increase in pore pressure was ever satisfactorily explained.

This paradox, however, was resolved by co-author Nadeau (prior to joining Statoil) and his associates at the Macaulay Institute. They convincingly showed that: (i) the precipitated illite occupies considerable volumes of pore spaces around dissolving smectite minerals (not in-situ replacement); (ii) the growth habit of the

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Smectite

MICRO-DARCY SHALE

NANO-DARCY SHALE:Prone to overpressure

Smectite

Smectitedissolution

Simplifi ed graph of the percentage of sandstone quartz cement and sandstone porosity loss versus temperature for the Norwegian continental shelf. Note the exponential increase in quartz cement and the rapid drop in porosity as temperature increases, especially above 120 oC.

Smectite-illite transition. The smectite dissolution products are re-precipitated as pore-bridging fi brous illite throughout a considerable volume of pore spaces in the vicinity of the dissolving smectite mineral. This causes a dramatic reduction in permeability but has little effect on porosity. Illitization commences at a temperature of about 60 oC, thereafter increasing rapidly.

The photograph on the left, taken with transmitted light, shows a quartz sandstone whose porosity has largely been destroyed. Without additional evidence, it may be thought that the porosity was lost through mechanical compaction and/or grain dissolution. However, the photograph on the right, taken with cathodoluminescence, reveals that the porosity has been obliterated by quartz overgrowths coating the host sand grains.

(Photos: Olav Walderhaug.)

4 EXEMPLAR™ was developed by Geologica (now Aceca Geologica) in Stavanger, Norway, based on concepts by co-authors Walderhaug and Bjørkum during their earlier tenure at Rogaland Research, and has been purchased by many oil companies and universities for reservoir quality prediction. It has also been incorporated in Aceca Geologica’s basin modelling program, Fobos Pro, which predicts overpressure build up due to temperature-controlled diagenetic reactions.

5 This statement is based on sound scientifi c grounds, which are too complex to deal with here.

0.2 mm 0.2 mm

8 POROSITY, PERMEABILITY AND HYDRAULIC FRACTURES

Hydraulic fracture mechanisms

Thermo-chemical driven porosity loss at depth sheds new light on the generation of hydraulic fractures and their role in hydrocarbon migration

Conventional thinking also suggests that hydraulic fractures7 are triggered by overpressure development in the pore fl uids of those sediments that are unable to expel their fl uids fast enough. Once fracturing has occurred, it is thought that the pressure rapidly normalizes and then gradually builds up again. The leakage of water or hydrocarbons through fractures would thus occur in fairly regular, intermittent bursts.

However, this idea is untenable in the light of Statoil’s claim that thermally-driven porosity and permeability loss is the controlling factor for fl uid expulsion. If so, the thermally controlled ‘chemical pump’ will continue to work, irrespective of the pore pressure it generates, until the permeability is so low that the pump is forced to create its own permeability in the form of open fractures. The fractures will typically remain open for several million years as long as the amounts of fl uid to be expelled are greater than the amounts that can escape via the pore network.

This mechanism differs radically from previous thinking, even though the fundamental rock mechanical principles of hydraulic fracturing are unchanged.

Cap rock integrity and re-migrationFurthermore, the textbook view of what constitutes a good cap rock is that it should be as impermeable as possible or have the mechanical strength to withstand fracturing. However, this diametrically opposes the view that low permeability is the prime cause of hard overpressure and cap rock fracturing.

Again conventional wisdom is contested by suggesting that ‘good cap rocks’ are fracture-prone!

precipitated illite is fi brous; and (iii) pervasive fi brous illitization leads to such intense subdivision of pore spaces that shale permeability is dramatically reduced, thus rendering the affected shales (and hence the deeper parts of basins) prone to overpressure development.

At temperatures above 100 to 120 oC, permeability may theoretically be further reduced to levels as low as 10-9 Darcies due to the illitization of the clay mineral kaolinite6 – a condition that is obviously conducive to the onset of extremely hard overpressure.

The classical inter-dependency between shale porosity and permeability loss in the mechanical compaction regime therefore breaks down when temperatures exceed 60 oC. This is due to the precipitation of fi brous illite, which causes a dramatic reduction in permeability but has little effect on porosity.

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Illite

in c

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Temperature (0C)

Thermal interval of illite formation

Idealized graph of the diagenetic illite content in the clay fraction of Norwegian continental shelf sandstones versus temperature. The sharp increase in the percentage of illite corresponds to the thermal zone of illite formation between 120 and 150 oC.

Examples of diagenetic fi brous illite cement are shown here in two sandstone samples, because its minutness in shales is impossible to photgraph.The central image shows a detail from the image on the left (within frame), where fi brous illite cement has been precipitated in a pore bounded by a corroded feldspar grain (left) and a quartz grain (right). The right-hand image (of another sample) shows the extremely delicate growth habit of fi brous illite, which strongly reduces permeability but has little effect on porosity. (Images: Tony Boassen.)

6 Kaolinite is a common clay mineral formed by the weathering or alteration of feldspars and other aluminous silicate minerals.

7 A similar situation may pertain where pre-existing tectonic zones of weakness are (re-)activated.

10 μm500.0 μm 50.0 μm

POROSITY, PERMEABILITY AND HYDRAULIC FRACTURES 9

Turning to re-migration, it is an incontrovertible fact that hydrocarbons almost always lie uppermost in traps, simply because they are more buoyant than water. They are therefore in direct contact with the overlying cap rock shale and will be the fi rst fl uids to leave a trap once the cap rock seal has been breached.

As a hydrocarbon trap subsides and eventually becomes subjected to temperatures over 120 °C, severe porosity reduction and associated pore pressure elevation may lead to the generation of fractures propagating upwards through the cap rock.

Initially, the permeability of the fractures will be small. However, as the permeability of the shale matrix decreases over time, the permeability of the fracture will increase. The volume and discharge rate of hydrocarbons leaving the reservoir through fractures will therefore increase.

This means that hydrocarbons probably remain trapped for only short periods of geological time before escaping to a lower temperature zone in which they may re-accumulate in more porous and permeable traps.

Prospects will therefore become increasingly separated from their ‘parent’ source rocks, and may no longer depend on primary migration but on vertical migration from one sandstone body to another via lengthy fractures formed in intervening shales.

The important point is that once hydrocarbons have been generated, they can sequentially re-migrate vertically through the overlying sediment column long after a source rock has ceased expelling signifi cant volumes.

Hydraulicfractures

Shale

Shale

Gas

Oil

Water

120 0C

Sandstone

Sandstone

Summary

1. Where subsurface temperatures are less than 60 oC, porosity and related permeability losses arise from mechanical compaction by squeezing out the interstitial formation water. Pore water pressures are either identical with or very close to hydrostatic. This conforms to conventional thinking and is easily simulated in predictive models.

2. Where subsurface temperatures are greater than 60 oC, there is a gradual transition from a mechanical compaction regime to a thermally-driven chemical compaction regime. At and above these temperatures, chemical compaction is largely caused by internally sourced quartz cement in sandstones and the precipitation of diagenetic clay (illite) in shales – the latter dramatically reducing permeability. At about 120 oC, shale permeability loss is so extreme that the accompanying loss in porosity triggers the development of hard overpressures and hydraulic fractures.

3. Widespread hydraulic fracturing may result in: (i) vertical fractures in shales serving as hydrocarbon conduits directly linking source rocks to overlying sandstones reservoirs; (ii) the fracturing of cap rocks whose properties were formerly regarded as favourable; and (iii) extensive re-migration of hydrocarbons to progressively shallower traps via intervening shales. These phenomena are largely related to the chemical compaction regime.

Everything therefore points to the existence of a general, process-based zonation of hydrocarbon-bearing sedimentary basins founded on temperature rather than pressure.

Conceptual illustration of re-migration showing the transference of hydrocarbons to higher level traps via vertical hydraulic fractures passing through intervening shales.

The notion that most present-day traps have to be directly charged from active source rocks is no longer the single most important issue. Moreover,

the belief that thermally mature source rocks will convert oil-prone basins into gas-prone basins no longer holds true, because the oil may simply have been transferred to higher levels.

10 THE GOLDEN ZONE CONCEPT AND ITS IMPLICATIONS

THE GOLDEN ZONE CONCEPT AND ITS IMPLICATIONS The Golden Zone concept is an empirically verifi able theory showing that hydrocarbons in siliciclastic sedimentary basins of the world generally occur in a predictable manner controlled by temperature. The impact of this theory on exploration practice is potentially profound.

Thermal zonation

The world’s siliciclastic basins can be modelled using an idealized thermal zonation scheme in which about 90 per cent of the world’s oil and gas resources are found between the 60 and 120 oC isotherms1

The assertion that overpressure development is controlled by temperature rather than effective stress is easily tested by plotting pore water pressure profi les in various worldwide basins against depth and temperature. As seen in the idealized fi gure, typical overpressure ramps occur at signifi cantly different depths but combine when plotted against temperature. Temperature is thus the controlling factor. What’s more, overpressure can typically start developing at about 60oC and reach near-lithostatic fracture pressures at about 120 oC.

Another general pattern emerges when the volumes of some 120 000 proven accumulations of oil and gas are cumulatively plotted against temperature2: about 90 per cent of the world’s oil and gas resources occur in a zone bounded by the 60 oC and 120 oC isotherms – the Golden Zone of Statoil. Above and below these isotherms, hydrocarbon volumes fall off dramatically.

What makes this result so remarkarble is that this global pattern is independent of location, basin type, geological age, sedimentation rate, subsidence rate, geothermal gradient, hydrocarbon volumes and the sizes of various fi elds. In other words, the perceived geological complexity of subsurface ‘plumbing’ in general has been reduced to a well organized system dominated by just one parameter – temperature.

If one knows the geothermal gradient, it is possible to predict the depth interval in any prospective basin in which the majority of hydrocarbons are likely to be found.

An idealized global model of fl uid migration and hydrocarbon accumulation can also be constructed

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Pressure Pressure

Hydrostatic pressure gradient

Lithostatic pressure gradient

Lithostatic pressure gradient

Hydrostatic pressure gradient

Three idealized pore water pressure profi les plotted versus depth (left) and temperature (right). Note that the overpressure ramps occur at different depths but coincide at the same temperature interval. The ramps start at temperatures of about 80 to 90 oC and reach hydraulic fracture pressure at about 120 oC.

1 Isotherms: lines of equal temperature.

by combining the above results with the revised processes summarized in the previous chapter. The conceptual model consists of a threefold, thermal zonation scheme.

The basal zone, which is bounded by the 200 oC and 120 oC isotherms, is where most hydrocarbons are generated from source rocks. Even so, only a minor percentage of the oil and gas is entrapped here. This strongly suggests that the greater majority of hydrocarbons have been expelled to lower temperature intervals. The zone is therefore named the expulsion zone, and is characterized by low permeabilities and (hence) high pore pressures capable of hydraulically fracturing the rock. This is the realm of intensive thermo-chemical compaction, powered by a thermo-chemical ‘pump’.

According to this model, much oil and gas will thus migrate upwards through hydraulically formed fractures into the zone above where the greater

2 The data have been assembled in a global database containing information from a variety of industrial, government and academic sources. The greater majority of them have been derived from producing fi elds. All of the data have been taken at face value, as it is impossible to undertake an independent quality control.

THE GOLDEN ZONE CONCEPT AND ITS IMPLICATIONS 11

Idealized distributions of oil and gas volumes plotted against temperature. Note that about 90 % of the world’s oil and gas resources fall within the 60 to 120 oC isotherms – the Golden Zone of Statoil. The volumes fall off rapidly above and exponentially below this zone where the pore pressure is close to or exceeds the hydraulic fracture pressure.

majority of them reside. This is appropriately named the accumulation zone, which corresponds to Statoil’s Golden Zone (as defi ned above)3. Here, hydrocarbon-charged reservoir sandstones will act as combined pressure relief and separation tanks, sealed by relatively impermeable cap rock shales that present insurmountable capillary barriers to the hydrocarbons but allow formation water to pass through them.

Sandstone porosities and permeabilities in this zone are still quite high because the volume of quartz cement is normally insuffi cient to fi ll more than a part of the available pore space. The upper limit of major entrapment – the 60 oC isotherm – is where hydraulic fractures are generally thought to peter out, simply because shale permeability is insuffi ciently low for them to propagate through the rock matrix.

The accumulation zone is a zone of transition between the thermo-chemical compaction regime of the expulsion zone and the overlying mechanical compaction regime of the so-called 'sealing' zone. Here, at temperatures below 60 oC, hydrocarbon volumes are low because the sealing zone is largely beyond the infl uence of vertical, fracture-controlled re-migration.

Those hydrocarbons that are present, apart from local biogenic gas4, have probably migrated upwards from the underlying accumulation zone through laterally extensive sandstone or siltstone ‘carrier’ beds.

It is also widely known that oil in this zone is vulnerable to bacterial degradation (biodegradation). The

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GOLDEN ZONE

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Terminology

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bacteria consume the lighter oil fractions, leaving behind a viscous mass of heavier oil fractions. This is a common phenomenon in oil reservoirs where temperatures are less than 80 oC. Indeed a plot of ‘heavy’ oil accumulations (API gravities < 25)5 against temperature (not illustrated) reveals that over 80 per cent occur at temperatures of less than about 60 to 80 oC.

4 Biogenic gases are formed by the physiological activities of organisms (bacteria).

5 High API (American Petroleum Institute) values characterize light, hydrogen-rich deposits, whereas low API values characterize heavy, carbon-rich deposits such as heavy oil.

Composite thermal zonation model for siliciclastic basins.

3 It is thought that about 5% of hydrocarbons in the Golden Zone will have migrated upwards via traditional fi ll/spill mechanisms. These will occur where laterally extensive sandstones are gently deformed but have not been subdivided into non-communicating, pressure-sealed compartments.

12 THE GOLDEN ZONE CONCEPT AND ITS IMPLICATIONS

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6

Basin A Basin C

Pressure Oil (%) Pressure Oil (%)

Hydrostatic pressure gradient

Lithostatic pressure gradient

Lithostatic pressure gradient

Hydrostatic pressure gradient

Dep

th (

km)

Practical implications

The Golden Zone theory not only indicates where the greatest potential hydrocarbon volumes may be found but also contributes to reducing exploration drilling costs and improving safety

As the Golden Zone illustration shows (p.11) the global totals of hydrocarbon volumes describe a normal distribution when plotted as percentages, with the highest volume concentrations corresponding to the 90 oC isotherm. This, of course, is a grand statistical average. Nevertheless, it is reasonable to assume that hydrocarbon resources in certain individual prospective basins will follow a similar pattern once all possible hydrocarbon accumulations have been accounted for. If so, a normal distribution can be used as a predictive tool.

For example, when entering basins that have only been partly explored, one could anticipate that the distribution of discovered hydrocarbon volumes might deviate from the norm (i.e. they would be skewed). Comparing the skewed distribution with a normal distribution may therefore yield important information about the potential of neighbouring temperature intervals.

At the other extreme, when entering unexplored frontier areas it would be wise to target prospects corresponding to the 90 oC isotherm. If subsequent drilling shows that they are all dry (i.e. they do not contain hydrocarbons), continued exploration in the basin should be questioned.

Golden Zone depths and thicknessesAnother potential outcome of the concept concerns the depths and thicknesses of Golden Zones. In hot basins, which are subject to extremely high geothermal gradients, Golden Zones should be relatively close to the surface and cover relatively thin depth intervals of about one to two kilometres. Conversely, in cold basins, which are subject to extremely low geothermal gradients, Golden Zones should be deeper and may extend vertically over three to four kilometres.

With this in mind, it is instructive to examine exploration drilling practices in both types of basin by comparing the (vertical) depths to the bases of proven hydrocarbon reservoirs with the total (vertical) depths of exploration wells.

In the North Sea, ‘thermal exploration drilling effi ciency’ is estimated to be about 60 per cent, which means that about 40 per cent of exploration wells have been drilled below the Golden Zone where the chances of discovering signifi cant hydrocarbons are much reduced.

The picture is considerably worse in the exceptionally

hot Bombay Basin where thermal exploration drilling effi ciency is estimated to be only about 10 per cent. Here the Golden Zone is only about one kilometre thick, and the largest accumulation – the giant Mumbai High oil fi eld – is encountered just 1.4 kilometres below the surface. The reservoir temperature is 112 oC!

Drilling unnecessarily below the Golden Zone may not only be risky in terms of the potential reward, but it is also expensive because exploration drilling costs increase exponentially the deeper one goes.

Comparison of Golden Zones in hot (high geothermal gradient) and cold (low geothermal gradient) basins. In a hot basin (left), the Golden Zone appears closer to the surface and is thinner than in a cold basin (right).

Uplift and erosionSo far, attention has been implicitly focused on sedimentary basins undergoing continual subsidence and sedimentation throughout their geological history. Some of them do, but many are subject to one or more periods of tectonic upheaval, resulting in the uplift and possible erosion of signifi cant sediment masses.

‘Sealing’ zone

Accumulation zone

Expulsion zone

HC

‘Sealing’ zone

Accumulation zone

Expulsion zone

(Depleted zone)

‘Sealing’ zone

Expulsion zone

Accumulation zone

(Depleted zone)

60

120

180

DEPOSITION DEPOSITION DEPOSITION

SUBSIDENCE

SUBSIDENCE

SUBSIDENCE

THEGOLDEN

ZONE

Tem

pera

ture

(0C

)

HC HC

Time

During continuous deposition and basin subsidence, sedimentary intervals progressively pass downwards through the various temperature windows (zones) as they become more deeply buried (dashed arrow). The greater majority of hydrocarbons, however, will always be concentrated in the Golden Zone, because subsiding hydrocarbon traps entering the expulsion zone will continually release their charge upwards due to hydraulic fracturing and re-migration (thin, vertical arrows).

THE GOLDEN ZONE CONCEPT AND ITS IMPLICATIONS 13

60

120

200

‘Sealing’ zone

Accumulation zone

Expulsion zone

HC

‘Sealing’ zone

(Depleted zone)

Deactivated expulsion zone

Former accumulation zone

Former 120 0C isotherm

Former 120 0C isotherm

(Depleted zone)

Deactivated expulsion zone

DEPOSITION EROSION EROSION

SUBSIDENCE

UPLIFT

UPLIFT

Time

Tem

pera

ture

(0C

)

(Depleted zone)

In general, uplift and erosion will contribute to the partial switching off of thermally-driven, fl uid dynamic processes, because the sediments will gradually be moved closer to the surface where the temperatures are lower. In these situations, the properties of the former zonation may essentially be ‘frozen’.

The amount of vertical displacement will obviously depend on how much a basin has risen and how much is eroded off the top. If the former 60 oC isotherm has been moved to the surface (i.e. the entire sealing zone has been swept away), the accumulation zone will start eroding and prospectivity will drop. If the former 120 oC isotherm ends up at the surface, few hydrocarbons will be left in the basin.

The advantage of uplift and erosion is that the depths to potentially viable prospects are less, thus reducing drilling costs. The main disadvantage is the risk of biodegradation in those reservoirs that were originally relatively hot to start with, and therefore initially hostile to oil-consuming bacteria. Drilling safety and the environmentOur ability to roughly calculate pore pressure curves in advance of drilling (using geothermal gradients) may also signifi cantly improve safety and lower environmental risks, both during exploration and production drilling operations.

A recommended practice in new areas is to identify the depth at which the 60 oC isotherm is likely to occur and design drilling programmes accordingly. In this way, drillers will be well prepared to manage the increased probability of penetrating overpressured, hydrocarbon-bearing sandstones, thereby diminishing the chance of potentially dangerous pressure ‘kicks’ (or blowouts).

Be aware, however, that overpressured reservoirs in the accumulation zone may be encountered in otherwise normally pressured sedimentary intervals.

The reason for this is that reservoirs are often broken into a number of compartments by impermeable (sealing) faults, and thus lack the means of relieving their pressure by lateral drainage.

Reservoir qualityAnother implication is that the idea of an ‘economic basement’ is devalued. The term refers to the common assumption that commercially viable reservoir rocks – i.e. those with adequately preserved porosity and permeability – may be found as long as temperatures around 150 °C are not exceeded. This may be so, but it is unlikely that they will be hydrocarbon-bearing because (as already stated) the development of hard overpressure and hydraulic fracturing begins around 120 °C.

The main implications are: (i) drilling to depths where temperatures greatly exceed 120 °C is probably unproductive; and (ii) exploration thinking should consider dispensing with reservoir quality as a crucial factor in favour of the thermally-controlled likelihood of encountering hydrocarbon accumulations.

DenouementThe Golden Zone concept has essentially evolved from new approaches to the established theories and descriptions of two key processes: the evolution of sandstone and shale porosity during burial; and the evolution of shale permeability.

This has led to a radical shift in thinking away from the mechanical approach to modelling basinal fl uid processes to a more self-regulatory system, involving thermo-chemical actions and reactions. Siliciclastic basins can thus be examined from an entirely new angle now that temperature is recognized as the overarching control.

What have emerged are two, simple, empirically verifi able global patterns – one for pore pressure profi les and one for volumetric hydrocarbon accumulations.

The fl uid dynamics of siliciclastic basins and their hydrocarbon systems are therefore more predictable and self-organized than previously thought, and seem to act fundamentally in similar ways. Statoil’s paradigm is thus helping to transform geological complexity into a uniformity that was hitherto unrecognized.

As an ASPO website article6 puts it: “It is impossible to exaggerate the importance of (this) discovery in terms of evaluating world oil and gas resources and the status of depletion”.

Uplift and erosion will lift a former accumulation zone (Golden Zone) to shallower depths and lower temperature intervals. As seen on the right, a former accumulation zone may be partly or completely removed by severe erosion.

6 Temperature control – a very important observation. November 2004. ASPO Newsletter, 47, p.10. ASPO is the Association for the Study of Peak Oil & Gas – a network of scientists affi liated with European institutions and universities having an interest in determining the date and impact of the peak and decline of the world’s production of oil and gas (www.peakoil.net).

14 SELECTIVE BIBLIOGRAPHY

SELECTIVE BIBLIOGRAPHY

A selective list of Statoil-authored and co-authored publications from 1981 to 2005, ranging from the theory of fundamental clay particles to the empirical verifi cation of the Golden Zone concept.

Bjørkum, P.A. 1996. How important is pressure in causing dissolution of quartz in sandstones? Journal of Sedimentary Research, 66(1), 147-154.

Bjørkum, P.A. & Nadeau, P.H. 1998. Temperature controlled porosity/permeability reduction, fl uid migration, and petroleum exploration in sedimentary basins. APPEA Journal, 38, 453-464.

Bjørkum, P.A., Walderhaug, O. & Nadeau, P.H. 1998. Physical constraints on hydrocarbon leakage and trapping revisited. Petroleum Geoscience, 4, 237-239.

Bjørkum, P.A., Walderhaug, O. & Nadeau, P.H. 2001. Thermally driven porosity reduction: impact on basin subsidence. In: Shannon, P.M., Haughton, P.D.W. & Corcoran, D.V. (eds), The Petroleum Exploration of Ireland’s Offshore Basins. Geological Society, London, Special Publications, 188, 385-392.

Bjørkum, P.A., Oelkers, E.H., Nadeau, P.H., Walderhaug, O. & Murphy, M.W. 1998. Porosity prediction in quartzose sandstones as a function of time, depth, temperature, stylolite frequency, and hydrocarbon saturation. AAPG Bulletin, 82 (4), 637-648.

Ehrenberg, S. N. 1990. Relationship between diagenesis and reservoir quality in sandstones of the Garn Formation, Haltenbanken, mid-Norwegian continental shelf. AAPG Bulletin, 74, 1538-1558.

Ehrenberg, S. N. 1993. Preservation of anomalously high porosity in deeply buried sandstones by grain-coating chlorite: examples from the Norwegian continental shelf. AAPG Bulletin, 77, 1260-1286.

Ehrenberg, S.N. & Nadeau, P.H. 1989. Formation of diagenetic illite in sandstones of the Garn Formation, Haltenbanken area, mid-Norwegian continental shelf. Clay Minerals, 24, 233-235.

Nadeau P.H. 1985. The physical dimensions of fundamental clay particles. Clay Minerals, 20, 499-514.

Nadeau P.H. 1987. Relationship between the mean area, volume and thickness for dispersed particles of kaolinites and micaceous clays and their application to surface area and ion exchange properties. Clay Minerals, 22, 351-356.

Nadeau, P.H. 1998. Fundamental particles and the advancement of geoscience: Response to ”Implications of TEM data for the concept of fundamental particles”. Canadian Mineralogist, 36, 1409-1414.

Nadeau, P.H. 1998. An experimental study of the effects of diagenetic clay minerals in reservoir sands. Clays and Clay Minerals, 46, 18-26.

Nadeau, P.H. 1999. The fundamental particle model: A clay mineral paradigm. In: Kodama H., Mermut A.R. & Torrance J.K. (eds.), Clays for our future. Proc. 11th Int. Clay Conference, Ottawa, Canada, 1997, pp. 13-19. Pub. ICC97 Org. Comt., Ottawa. 809 p.

Nadeau P.H. & Bain, D.C. 1986. Composition of some smectites and diagenetic illitic clays and implications for their origin. Clays & Clay Minerals, 34, 455-464.

Nadeau P.H. & Reynolds, R. C. 1981. Burial and contact metamorphism in the Mancos Shale. Clays and Clay Minerals, 29, 249-259.

Nadeau P.H. & Reynolds, R. C. 1981. Volcanic components in pelitic sediments. Nature, 294, 72-74.

Nadeau, P.H., Bjørkum, P.A. & Walderhaug, O. 2005. Petroleum system analysis: Impact of shale diagenesis on reservoir fl uid pressure, hydrocarbon migration and biodegradation risks. In: Doré, A. G. & Vining, B. (eds), Petroleum Geology: North-West Europe and Global Perspectives - Proceedings of the 6th Petroleum Geology Conference, 1267-1274. Petroleum Geology Conferences Ltd., published by the Geological Society, London.

Nadeau, P.H., Peacor, D.R., Yan, J. and Hiller, S. 2002. I/S precipitation in pore space as the cause of geopressuring in Mesozoic mudstones, Egersund Basin, Norwegian Continental Shelf. American Mineralogist, 87, 1580-1589.

SELECTIVE BIBLIOGRAPHY 15

Nadeau P.H., Tait, J.M., McHardy, W.J. & Wilson, M.J. 1984. Interstratifi ed XRD characteristics of physical mixtures of elementary clay particles. Clay Minerals, 19, 67-76.

Nadeau P.H., Wilson, M.J., McHardy, W.J. & Tait, J.M. 1984. Interstratifi ed clay as fundamental particles. Science, 225, 923-925.

Nadeau P.H., Wilson, M.J., McHardy, W.J. & Tait, J.M. 1984. Interparticle diffraction: a new concept for the interstratifi cation of clay minerals. Clay Minerals, 19, 757-769.

Nadeau P.H., Wilson, M.J., McHardy, W.J. & Tait, J.M. 1985. The nature of some illitic clays from bentonites and sandstones: implications for the conversion of smectite to illite during diagenesis. Mineralogical Magazine, 49, 393-400.

Nordgård Bolås, H. M., Hermanrud, C. & Teige G.M.G. 2004. Origin of overpressures in shales: constraints from basin modelling. AAPG Bulletin, 88 (2), 193-211.

Oelkers, E.H., Bjørkum, P.A. & Murphy, W.M. 1992. The mechanism of porosity reduction, stylolite development and quartz cementation in North Sea sandstones. In: Kharaka, Y.K. & Maest, A.S. (eds), Water-Rock Interaction, 1183-1186, Balkema, Rotterdam.

Oelkers, E.H., Bjørkum, P.A. & Murphy, W.M. 1996. A petrographic and computational investigation of quartz cementation and porosity reduction in North Sea sandstones. American Journal of Science, 296, 420-452.

Walderhaug, O. 1990. A fl uid inclusion study of quartz-cemented sandstones from offshore mid-Norway – possible evidence for continued quartz cementation during oil emplacement. Journal of Sedimentary Petrology, 60 (2), 203-210.

Walderhaug, O. 1994. Temperatures of quartz cementation in Jurassic sandstones from the Norwegian Continental Shelf – evidence from fl uid inclusions. Journal of Sedimentary Research, A64 (2), 311-323.

Walderhaug, O. 1994. Precipitation rates for quartz cement in sandstones determined by fl uid-inclusion microthermometry and temperature-history modeling. Journal of Sedimentary Research, A64 (2), 324-333.

Walderhaug, O. 1996. Kinetic modelling of quartz cementation and porosity loss in deeply buried sandstones reservoirs. AAPG Bulletin, 80(5), 731-745.

Walderhaug, O. 2000. Modeling quartz cementation and porosity in Middle Jurassic Brent Group sandstones of the Kvitebjørn fi eld, northern North Sea. AAPG Bulletin, 84 (9), 1325-1339.

Walderhaug, O. & Bjørkum, P.A. 2003. The effect of stylolite spacing on quartz cementation in the Lower Jurassic Stø Formation, southern Barents Sea. Journal of Sedimentary Research, 73 (2), 146-156.

Walderhaug, O., Oelkers, E.H. & Bjørkum, P.A. 2004. An analysis of the roles of stress, temperature, and pH in chemical compaction – discussion. Journal of Sedimentary Research, 74 (3), 447-450.

Walderhaug, O., Bjørkum, P.A., Nadeau, P.H. & Langnes, O. 2001. Quantitative modelling of basin subsidence caused by temperature-driven silica dissolution and reprecipitation. Petroleum Geoscience, 7,107-113.

Walderhaug, O., Lander, R.H., Bjørkum, P.A., Oelkers, E.H., Bjørlykke, K. & Nadeau, P.H. 2000. Modelling quartz cementation and porosity in reservoir sandstones: examples from the Norwegian continental shelf. Spec. Publs Int. Ass. Sediment., 29, 39-49.

Aase, N. E. & Walderhaug, O. In press. The effect of hydrocarbons on quartz cementation – diagenesis in the Upper Jurassic sandstones of the Miller Field, North Sea, revisited. Petroleum Geoscience, II (3).

Aase, N.E., Bjørkum, P.A. & Nadeau, P.H. 1996. The effect of grain-coating microquartz on preservation of reservoir porosity. AAPG Bulletin, 80 (10), 1654-1673.

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Milestones 2001

Milestones 2002

Milestones 2003

Milestones 2004

R&T Memoir 1 – Flow Assurance (2002)

R&T Memoir 2 – Offshore Geophysical Methods (2002)

R&T Memoir 3 – Offshore Produced Water Management (2003)

R&T Memoir 4 – Geological Reservoir Characterization (2003)

R&T Memoir 5 – Carbon Dioxide Capture, Storage and Utilization (2004)

R&T Memoir 6 – Liquefi ed Natural Gas: Snøhvit Process and Plant (2004)

R&T Memoir 7 – Distribution of Hydrocarbons in Sedimentary Basins (2005)

R&T Memoir 8 – Gas-to-liquids (GTL) Technology (in prep.)

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