From seismic to biomarkers—the value of additional data in continually refining geological models

203

From seismic to biomarkers — the value of additional data in continually refining geological models Nigel Mills, Rolando di Primio, Sven Hvoslef, Daniel Stoddart, Ingar Throndsen and Mike Whitaker

This paper discusses the necessity of being data-driven in petroleum exploration and how important it is to investigate anomalies or unusual observations rather than dismissing them as unreliable data because they do not fit with existing models. We suggest that some (often small-scale) techniques are often in danger of being ignored, or at the very least reduced to a minimum, in times of emphasis on economy or when it is considered that an area has become mature in an exploration sense. We show through a number of short examples that developing high-quality databases and ensuring sufficient numbers of the right kinds of data can have an enormous impact on geological understanding of an area both for exploration and production. Relegating some small-scale and relatively cheap analytical tools to the ranks of 'luxury' items may lead to oversimplifications and lost opportunities or wasted investments. We would contend that any model not successfully explaining all observations at all scales from seismic to atomic is by definition incomplete and potentially misleading. The examples given here are brief and concentrate on emphasising 'the value of additional data' rather than detailed descriptions of the total petroleum system in each area discussed. They show how: (1) based on high-resolution bio stratigraphy, new potential reservoir horizons may be postulated and how an expensive and potentially inefficient producer was avoided; (2) use of laboratory derived kinetics for oil generation and oil destruction can better explain observations than default parameters; (3) applications of widely available PVT data in exploration problems can support, confirm or improve interpretations from other techniques; and (4) the generation and application of petroleum population data can improve understanding of actual migration routes in two areas of different exploration maturity. The reader is referred to some of the references cited with each example for more detailed geological discussions of the individual areas.

Introduction

The exploration process has come a long way since the days when 'near cemeteries but not sawmills' (Blakey, 1985) was good advice and advanced thinking (proto play models almost!). Today the arsenal of tools available to the explorationist is formidable. These range in scale from global understanding of what type of basins may be petroleum yielding to regional gravity magnetics and seismic studies and at the opposite extreme atomic information, for example neodymium/samarium data. All of these and many more, if used correctly, can in some instances be the key to successful exploration and the real competitive edge. The scales over which these techniques are performed clearly vary from kilometres to nanometres or even smaller and the resolution is usually reflected in this. However, the degree to which the many techniques, which fall in the gradation from macro- to micro-scale, can be used, may vary immensely from technique to technique, from application to application and from case to case. It is this great variation in tools and scales that provides us with both the

challenge and the possibility to continually develop our understanding of subsurface processes. This is becoming more and more essential in order to find continually more elusive petroleum accumulations. Integrating the many disciplines and scales in a dynamic manner, having an eye for the anomalies and daring to make decisions and redefine 'accepted' models or theories, is the key to successful exploration in both mature and virgin areas. All too often, though usually dictated by economics, we tend to perhaps subconsciously divide activities into essential and additional (luxury). We would question the traditional view of this and the division into these groups and would warn against neglecting studying the details which often also incur only minor relative expense. Fig. 1 is an attempt to illustrate the scale aspect of several exploration tools (though it is obviously not to scale itself) together with the approximate sequence of performing these techniques and their level of resolution/detail/order. Virtually all explorationists these days would suggest that seismic is an essential part of any exploration programme (indeed any discussion being more along the lines of whether 2D is

Improving the Exploration Process by Learning from the Past edited by K. Ofstad, J.E. Kittilsen and P. Alexander-Marrack. NPF Special Publication 9, pp. 203-229, Published by Elsevier Science B.V., Amsterdam. © Norwegian Petroleum Society (NPF), 2000.

204

o

I CO

€0

"3

Li

CO

O)

o

f v. ^

-

-

—

•

~- : .•-'-

1 !~:; ^VJ* •^W^!

1

•

-

;

-

^

_

-

^fv^+tA^k,

-3|eos-

~^L\

c CO

*•••

;•

' t

/

.

*

+* r3fe# CO

CO

ft-

1

j iOH

<

o 0

MMM

** 3

3 o "S o

2s (0

p

k.

•o

o

^f J -H


*3

o too

N. Mills et al.

»»• * • / • 1

-*

'

1

v

*V?/^

- *****£ f

••;-,3En^afs^a

r"

*

LI \*

_ ; —f-4

•r"

^^SE^g

o Ssi^p^ cc

~T"'~~Tr:t .j

iV

*0

1EL

c3

o

o

«3

^3

upp

4-»

o IS* m

-l-

^^T^

Unsaturated vapor

From seismic to biomarkers — the value of additional data in continually refining geological models sufficient or 3D is called for). Once a well is decided upon and drilling under way the explorationist also considers logging to be essential for interpreting the results of the well. At the other extreme many exploration geologists would consider routine biomarker analyses on fluids, reservoir cores or source rocks to be somewhat additional to the minimum requirements of a well programme and these would be viewed as somewhat of a luxury. Between these extremes there are many techniques that fall into a grey zone with respect to whether they are viewed as essential or additional and this may (and perhaps ought to) change from case to case. Often this sequence of analyses becomes self correcting and self steering in that fluid inclusion, biomarker or neodymium/samarium work may overturn seismic interpretation which may develop new exploration models, leading to drilling, logging, coring etc. This paper sets out to show with the help of a few simple case studies that data types often considered to be additional (luxury) may often prove essential and overturn established 'truths' about exploration models or regional understandings. High-resolution biostratigraphy Fig. 2 shows an example of the power and resolution it is possible to attain with high-resolution biostratigraphic analyses (in this case palynology). Highresolution biostratigraphy is simply tight sampling frequency especially at or around known problem intervals or previously poorly dated, critical sands. Here an example of the level of resolution attainable is shown for the Toarcian to Bathonian interval, which is divided into ten 'palyzones' (A to J), of which the Bajocian interval comprises eight zones. Each of these palyzones may be further subdivided into various numbers of events, determined mainly by 'Top', 'Influx' or 'Base' of given palynomorphs or assemblages thereof. As shown in detail to the left in Fig. 2, Bajocian palyzone 'H' may be subdivided into fully 23 events. Events may be related to depositional units as shown and a relationship between the formations can be established as shown to the right in Fig. 2. This power of resolution and regional applicability allows the use of such analyses to make wide ranging decisions regarding both exploration models and production scenarios. Well 34/7-18, Tampen Spur The first case study comes from well 34/7-18 on the Tampen Spur in the northern North Sea (Fig. 3). Well 34/7-18 was drilled in a relatively mature exploration area and routine biostratigraphic analyses were performed based on available core fragments plus

205

available side wall cores above the coring point. The main reservoirs in this area are Brent Group or Upper Triassic/Lower Jurassic sandstones and the area was considered reasonably well understood with respect to reservoir development and stratigraphy. Sand was encountered at ca. 2295 m and coring immediately initiated (Fig. 4). Prior to entering the sand clear Cretaceous lithologies had been observed. On completion of the well the routine biostratigraphic analyses were initiated utilising available side wall cores just above the sand and the core chips scattered throughout the reservoir interval which comprised two sand units separated by a shale (Fig. 4). Using the data that could be extracted from the sample distribution shown in Fig. 4 the chronostratigraphy was interpreted as shown to the left in this figure designated 'Before'. The interpretation was initially unquestioned as the first sand that was expected to be encountered was Brent Group sand. However, the total absence of any Upper Jurassic sediments, the observation of possible Cretaceous sands in two wells in the Gullfaks area (34/10-14 and 34/10-34), the availability of core in both of the sand intervals and natural curiosity provoked interest in a higherresolution biostratigraphic study and several more core samples were carefully taken through the uppermost sand. On the right hand side of Fig. 4 a revised chronostratigraphy based on these extra analyses is presented, designated 'After'. This shows a very significant difference in that the majority of the upper sand is now dated as Cretaceous (CampanianSantonian) whilst due to the careful sampling and high-quality, high-resolution biostratigraphy it could even be shown that the lowermost part of this sand was in fact remnants of Brent sands. Since these observations and due to the excellent and clear proof of the existence of Cretaceous sands in the area that this work on well 34/7-18 was able to provide, Cretaceous sands have been interpreted in other wells and may represent a significant new reservoir possibility in the general area. This also has implications for understanding the general regional configuration and sand sourcing possibilities at the time of deposition (Early Cretaceous). Tordis East, block 34/7, Tampen Spur The Tordis East Field was discovered by well 34/7-22, which is the subject of another case study in this article (see below). The field was initially considered to be a relatively simple structure with almost layer cake reservoir intervals as shown in the cross-section in Fig. 5a between wells 34/7-2 and 34/7-22. Production from the main Tarbert Formation reservoir was envisaged using a horizontal

206

9= i CO

ii s

_ j <

Sru.

£ oca: oo UJ

20

oi

CO

<

h CL

CO

HI Q

z LU > LU

3NOZ -AlVd 39V

CO CO

>

<

LU CO

CD .CV3

c: co

.a d o

& E .^ "6 o

9>J5

1 o CO

d CL

^

CO

s S S 10

C/5

5 .9>

o

o

x

P> CO

1 O

2

*o c

2

*— o c

CL CL CO CO

.•2

c: o a .S3 x E -2 co .to

s

—

2

»— O

CO

Q)

a: b CO

o

CO CO

CD

.to 45

CO ^5 V-.

c-

CD

£t

en C: CD

^

CO

f

__ co .«0 CD

t

CD C CD CO

O

(M

^

CD

^

^5

^

CO

-» ^

.£ .£ .S d .g ^

3

co S -i Q

2

'//

CX 0

Q.

-S3 o

XSX

> > > )£.

X X X

CD

Q. Q. CO CO

.a C:

o CL

E

s "6 o 4_i

s. 0

^i

CD CO CO

m |2

Q. CO CO

NVINOHlVe

CL Q. CO CO

.a

m * 53 § E

.0) 45 Q

o c J9 is o X =

r - w n ^ L n c o N c o o )

Q. CL

OUI

z UJ

o o

z UJ > UJ

UJ

z

o N

inf lux uen

CL CL CO CO

Is I 8 O CO CL

cl S CT "-, X

5^ PF

co

o CO

E

.to

CD

-S5 ^5 c co

cj d c

CL

CO

"c

CO

~o c 13 .Q

CO

CO

•a c 3 X)

CL

O

•S£

to

CJ

.TO

c

x

CD C CD CO

<3 x

3

^

3

,o ,o S F F

^

CL CL

co co

o

'C:


CD

c

CO

to .to

CD

*b iS

.8•s co

CO

<

3 -Q

c

CO

a:

5 CD

c:


CD CO CO CD

i_

o ^ c

m C D h - C X ) C D O i - < M C O

N. Mills et al.

73

03 O

6

o

fe

o CO

\ >

CO

o o

o o

co

CD CO

•*—»

5

C/)

El

58

From seismic to biomarkers — the value of additional data in continually refining geological models

o

CD CO

CO

IT) CO

l0il 1

CM i

o o

°co

o CM °CO

o o °co

o o CO

o

LEGEND

CM CO

CO CO

eg CO

CO

o CNJ

o o °co

207

N. Mills et

•

' .

.

. '

:

'.

' •

'

11 II

III

;


'.'

.'

CT7~~

.

Statfjord?

_

' .

I Rannoch^

••y>

•

"

Rannoch

-

' !

I |

|

v.J

| Dunlin

[Ness | Heather Ness

1 ••

, X

< h' i

) •

•

*

UU

<

*

u.

:•!. 1

Mi

I"'ti

a>

JD

P

2

CD

"sriiii . * J"lti.

'V^V^ 1

UL

(0

x:

*

X

u.

w

;';•••

•0i^ a>

;

12

••'-••.

Of- J • a>

UJ

•is

209

o

3

H

=3 O

W) T3 C "1

c

ctf t-J

PM

T3 O

tru uce S-i

o

-1—>

4= S-! (1)

3

PH


>,

OH

-D O

-s C 03

&n T 3

lO

U


o

UH

aC

a o a) C£3

o

=4H

c

T-)

ers izo

!'

!

Etive /

Dunlin

From seismic to biomarkers — the value of additional data in continually refining geological models

m

; Tarbert

1 7H 1 n

1 Heather

ENCOUNTERED^ SEQUENCE 1 | EXPECTED SEQUENCE ! |

210

producer. Well 34/7-7H was drilled and it was intended to kick off the future producer from this well. Fig. 5b shows the stratigraphy that was anticipated for well 34/7-7H, based on the discovery well, with a straightforward, traditional development of the Brent Group. Also shown in this figure is the stratigraphy as interpreted based on high-resolution biostratigraphy. Clearly the reality is much more complicated than what was expected and the presence of several (at least four) faults even within the relatively low deviation well-7H was predicted. Due to the obvious implications for a horizontal producer if the Tarbert Formation were not continual and flat as supposed, it was decided to drill well 7AH (as a side-track of 7H) to improve understanding of the area. The encountered stratigraphy (again based on high-resolution work employing both core and sidewall core material) again shows a complicated situation with repeated formations and the presence of several faults (Fig. 5c). The revised structural overview (Fig. 5d) shows a very complex situation and suggests that by performing high-resolution biostratigraphic analyses and interpretation to an additional cost of some few tens of thousands of kroner (since the necessary sample types were already available) drilling of a costly and potentially useless producer was avoided.

N. Mills et al

Energy Extent of Reaction (generation)

b)

Measured kinetics data

Modern basin modelling requires that parameters for the rates of generation and destruction of hydrocarbons be defined. Traditionally this has been by 'default' and so-called 'global' values (e.g. Tissot and Espitalie, 1975). However, most basin modelling software allows the user to define any set of kinetic parameters for both oil generation and oil cracking. The process of oil generation can be seen as a series of reactions each requiring a different amount of energy to initiate it and each contributing a different portion of the overall process, known as the reaction potential (Fig. 6a). The number of such reactions, their energy requirements and each one's relative contribution to the total process are governed by the chemical complexity or simplicity of the kerogen present in the source rock. Once we know this breakdown of energy requirements and relative contributions (from laboratory analyses, e.g. Ungerer and Pelet, 1987; Schaefer et al., 1990) we can express the whole thing in a more geological way such as shown in Fig. 6b, in terms of extent of total reaction (i.e. oil generation) versus any time and temperature combination (i.e. burial history). Such oil generation kinetics may be measured as 'bulk' reaction or as 'compositional kinetics' treating certain groups of compounds separately (Dieckmann et al., 1998).

Fig. 6. (a) Schematic showing how the oil generation process may be described by a series of reactions requiring different energies and contributing different proportions to the overall result, (b) These data may be represented as generation versus depth.

For oil cracking bulk kinetics were used for a long time but in recent years much work has been performed on understanding the rate at which oil cracks to gas and residue and what factors control these rates (Tissot et al., 1974; Quigley and MacKenzie, 1988; Horsfield et al., 1992; Kuo and Michael, 1994; Pepper and Dodd, 1995; Schenk et al., 1997). It is a general observation that crude oils progressively increase in gas-oil ratio with increasing maturity and transform from petroleum systems of dominantly oil, into systems of gas and condensates. This transition may lie anywhere between temperatures of 90 to 200°C depending on the basin and the thermal history. Another knowledge is that crude oils are unstable, as well as kerogen, and will degrade to form gas and other petroleum products while exposed to sufficient thermal stress. Oils are commonly considered to breakdown via hydrogen transition reac-

From seismic to biomarkers — the value of additional data in continually refining geological models 100

A—

211

• Quigley and MacKenzie, 1988

90

• Horsfield etal., 1992

80

A Platte River BasinMod

70 >. u 60 c a> 3 50 a>

40

• •

30

•

20 10

•

•

:

1 1

A=1.1*1013sec"1 Quigley and MacKenzie, 1988 A=1.0*1013sec"1 Platte river Basinmod A=1.1*1016sec"1 Horsfield etal., 1992 A= frequency factor

0 0

20

40

60

80

Activation energy Ea(kcal/mole) Fig. 7. Distribution of activation energies of oil-to-gas cracking based on experimental data.

tions (Connan, 1974) and the conversion is assumed to follow first-order constituent reactions (Tissot et al., 1974; Quigley et al., 1987; Ungerer et al., 1988; Behar et al., 1991). In natural systems, however, the reaction paths of oil to gas conversion are difficult to follow in time and space since gas may originate from both kerogen and oil. Another complicating factor is the dynamic situation resulting in enhancements of petroleum compositions in reservoirs where fill-andspill mechanisms operate. The study of the oil to gas conversion reaction is therefore limited to laboratory experiments where the time factor is widely different from the geological system. Most experiments conducted have applied hydrous pyrolysis or other closed systems experimental approaches, determining pre-exponential factors using different heating rates. By extrapolation, reaction rates in geological situations have been determined and the outcome of these experiments have often been applied in basin models to determine the base of the 'oil floor' (i.e. the limit of the depth in which oil can exist in a reservoir). Most authors have operated with one single activation energy for this reaction (Tissot et al., 1974; Welte and Yalcin, 1988) or a set of reactions using either discrete (Tissot and Espitalie, 1975) or gaussian (Quigley et al., 1987; Quigley and MacKenzie, 1988) distributions of activation energies and a single pre-exponential factor. Based on some of these studies, a temperature in the order of 150°C (Andreev et al., 1968; Pusey, 1973) or a temperature range of 150-190°C (Quigley et al., 1987) has been established as the highest stability domain for oil. Either using discrete or gaussian distributions, these models are based on the assumption of distinct sets of reactions but provide no insight into the changes in oil composition during progressive gas formation.

Horsfield et al. (1992) used the micro-scale sealed vessel (MSSV) pyrolysis technique to collect quantitative information on crude oil compositional changes as a function of increasing temperature, whereby gas generation rate curves for each individual step were determined by gas chromatographic analysis. The determination of oil to gas cracking kinetics on a typical black oil from the North Sea using MSSV pyrolysis indicated that oil is more stable than previously assumed (Fig. 7). The activation energy distribution calculated based on these analyses centred around 66 kcal/mol with a pre-exponential factor of 1 x 1016 s~~l. Application of these kinetic parameters to the burial history of well 2/4-14 offshore Norway indicated that liquid hydrocarbons would be stable at the reservoir temperatures of 165°C. In fact well 2/4-14 encountered liquid hydrocarbons, whereas earlier basin modelling results using a single activation energy for oil-to-gas conversion (Andresen et al., 1993) predicted only gas in this reservoir. Assuming a thermal gradient of 30-35°C/km and the kinetics of oil to gas cracking determined by Horsfield et al. (1992) the oil floor becomes deepened by at least 400-500 m, indicating the possibility of future oil discoveries on the Norwegian shelf at depths between 4.9 and 5.7 km beneath the seabed. It is not possible within the scope of this paper to discuss this work in detail and the reader is referred to the many excellent articles cited above and references therein. This type of input into basin modelling is vital in areas where prospects are deeply buried and/or geothermal gradients are excessively high as they will help to define economic basement for oil.

2

™*

>

*

3

>

?

o

CM

o

^

C\J

y

>

ft

W

JF'

•cs.

GO)

>• Q

<

in

wk-j

00

O)

o>

10

o in

1

0

i

A

1

1

N. Mills et al.

CO Q

2s

i

O

o

bo

From seismic to biomarkers — the value of additional data in continually refining geological models

213

Oil generation kinetics, block 2/2, southern Norwegian North Sea Well 2/2-5 was drilled in 1991-92 on the so-called 'Jurassic Ula Trend' (Spencer et al., 1986) and was plugged and abandoned as a 'minor oil discovery' (Fig. 8a). However, the oil that was tested proved to be compositionally and isotopically the most unusual oil discovered offshore Norway and did not resemble any of the oils from the Ula, Gyda or 2/2-1 discoveries. In addition the oil was discovered in only one thin Upper Jurassic sand despite the fact that the whole Upper Jurassic sequence comprises alternating sand/shale (Fig. 8b) and the Upper Jurassic is considered to be the main if not sole source in the area. The anomalous nature of the oil and its restricted stratigraphic occurrence prompted studies to try to understand the source facies, stratigraphic distribution and implications for the general area. Detailed analysis of all available and suitable potential source facies samples within the well was performed but these did not correlate with the oil. Simultaneous with this work a regional evaluation of Upper Jurassic revealed the presence of a source facies in certain wells that had at least some of the unusual characteristics of the 2/2-5 oil. This was initially reported by Bailey et al. (1990) who describe an isotopically heavy and super rich source sequence in the midst of a normal Upper Jurassic shale development in the Danish sector of the North Sea. The well was subsequently identified as 'Diamant-1' and sampling and detailed analysis revealed that the super rich and isotopically heavy section also showed evidence of the other unusual characteristics seen in the 2/2-5 oil, namely excessive amounts of isoprenoids and abundant gammacerane. Other wells in the Norwegian part of the Central Graben were also observed to contain this facies as evidenced in Stoddart et al. (1995). Of interest but not crucial was the fact that within the limits of the available biostratigraphy it appeared that this facies was more or less developed at about the same time and often at basin/graben edge faults. Despite less than optimum samples due to operational difficulties during drilling of 2/2-5 it could be seen that the one sand containing this unusual oil was at approximately the 'right' stratigraphic level to coincide with other observations elsewhere; however, the source shale could not be seen in the well (it is possible that it is the ca. 1 m thick shale immediately above the oil leg but this was not sampled). As part of the thorough analysis of the source facies and to try to explain why this sand is full of the oil whilst none of the other moderate to good shales in the well appear to have generated or expelled hydrocarbons, kinetic analyses on the unusual source

I1 liL

I

Energy

b)

p. I

1

Energy

Fig. 9. Comparison of reaction distribution for a typical marine shale (a) versus those derived for the presumed source of the 2/2-5 oil (b).

facies were performed. The results are schematically shown in Fig. 9 where activation energies for a traditional marine type II kerogen are compared with the derived kinetics for the source facies. Here it can be seen that the new analyses suggest a much more restricted activation energy distribution, starting generation at later energies but completing the process much more quickly than the default type II kinetics would predict. The consequences of using these measured parameters in the 2/2-5 kitchen area are shown in Fig. 10. Here we can see that versus depth the generation from the measured kinetics is slightly later getting started but quickly overtakes the default kinetics and at this location, depending upon other input parameters may result in achieving 50% generation at up to 500 m shallower depth. The effect this has on the area of active source rock (and hence hydrocarbon volumes available for expulsion and migration) is also shown in this figure. The new data make it possible to understand the presence and distribution of unusual hydrocarbons in the well. The presence of this source facies may also be significant in local marginal basins, potentially opening up areas where traditional evaluation would had risked source severely. Oil cracking kinetics, block 6406/2, Norwegian North Sea One example of the importance of specific oil cracking kinetics may be the exploration assessments

214

c o c

CD

c o o

CO
c LU

(0

• * • • •

CO

o o m i o o

(9WJJ. PUB 9jniBJ8dlU91=)

mdOQ

-'

«4 ,

--***,

1

10

J

W

•'

.•

.

/

; \ i L -

J^*%S'

"

-;;,;™-. • .*r;

•

.

'

.':

'•

,-< "••*":" ':Q •"<

,-:-^T

i

' :

v.. o

N. Mills et al

^'j'•' : 7,: }} yy

.

/^hr (
X

\-/j*-¥x?-•:

• - \

•V? '\$«

^ \ > S # yr\ J

X\

£N cvi N \

, '

From seismic to biomarkers — the value of additional data in continually refining geological models made by the oil industry prior to the award block 6406/2 offshore Mid-Norway in the 14th licensing round in 1993. Presence of several deeply buried Jurassic rotated fault blocks had been known for a few years but were considered 'high risk' due to presence of gas and/or lack of sufficient porosity and permeability in the reservoirs. A common observation had been that reservoirs buried deeper than 4000 m sub-sea mainly were gas discoveries and that reservoir quality often was low at these depths. In block 6406/2 the source rocks and reservoirs were expected to be present between 4500 and 5000 m with corresponding temperatures between 160 and 180°C. As well as high gas contribution by cracking from the kerogen, any oil trapped at these depths was considered to become thermally unstable. These assumptions were supported by previous experimental results, showing oil degradation to become significant at temperatures greater than 150°C. The kinetic parameters resulting from these experiments could easily be implemented in basin models to reach the same conclusion. On the other side, the discovery of oil at 5200 m and temperatures in the order of 160°C in block 2/12 (the Mj0lner Field in the Central Graben) gave clear evidence that oil could be stable even at these temperatures, giving indications that either the composition of the oil had vital influence on its thermal stability, or that the previous experimental results were incomparable with what happened in nature. In modelling of the Kristin Field, three different kinetic models of oil to gas cracking have been applied in oil stability assessment using the general temperature history for the field (Fig. 11). While the first model uses a single activation energy of 54 kcal/mol, the result shows that oil degradation would start at 4100 m and become nearly complete at 5100 m. A similar result is achieved for the Quigley and MacKenzie (1988) kinetic model, but with a less severe effect between 4100 and 4700 m. As for the single activation energy model, the oil degradation is nearly complete at 5100 m. The Horsfield et al. (1992) kinetic model marks a significant difference showing very little oil degradation throughout most of the reservoirs down to 5100 m. Below this level oil degradation is initiated, and may be completed at a depth even greater than 6000 m. Subsequently, the difference in outcome of laboratory experiments on oils severely change the depths to a presumed 'oil floor' which again may impact the exploration strategy. For the Kristin Field case, GORs were measured

215

in the order of 760 Sm 3 /Sm 3 showing oil contents of nearly 50% by mass. Apparently, in-reservoir degradation of oil in the case of the Kristin Field reservoir may not be severe and more in accordance with the Horsfield et al. (1992) model. On the other hand, the neighbouring Lavrans Field is characterised by much higher GORs which may oppose this conclusion. However, the Kristin reservoirs are severely overpressured, while the pressures in the Lavrans reservoirs are nearly hydrostatic. As a consequence, more oil can be dissolved in the Kristin reservoirs, while the gas in the Lavrans Field has less capacity to contain oil components. In addition, a previous oil in the Lavrans reservoirs may more easily have been lost by a fill-and-spill mechanism since its petroleum system is in communication with the seabed. PVT data in the North Sea and Barents Sea Standard PVT analyses, performed on almost all conventional oil tests, contain a wealth of information, which has until now been used predominantly by reservoir engineers for the evaluation of reservoir fluids in a production-related context. The analysis of large PVT datasets on a field to regional scale, however, has revealed that this type of data can be used to recognise and quantify the response of hydrocarbon fluids to changing geological conditions during their generation and migration (di Primio et al., 1998). A typical fluid analysis, for use as input for PVT simulators, consists of detailed gas composition (molar contents of methane, ethane, propane, n- and iso-butane, n- and iso-pentane) and a bulk characterisation (molar abundance, molecular weight and density) of the C6 to (commonly) C9 boiling ranges as well as of the residual fraction of the petroleum (called plus fraction, i.e. C10+). Such fluid compositions allow the calculation of the physical properties of the fluids at a range of different pressure and temperature conditions. These calculations are performed by PVT simulation software packages using equations of state (EOS). These EOS provide a mathematical description of the fluid behaviour for reservoir simulation and reserve estimation. Phase envelopes of reservoir fluids, also calculated using EOS, depend strongly on the composition of the fluid analysed, and hence offer a simple graphical representation of a complex dataset. Fig. 12a shows an example of a phase envelope. It consists of a region where the fluid occurs in a single phase state and a region where it

Fig. 10. The implication of using laboratory-derived kinetic parameters versus traditional default parameters for marine type II kerogen. (a) Generation versus depth for 2/2-5 burial history, (b) Comparison of mature (50% generation) kitchen area for well 2/2-5 (depth map of top Mandal Fm., blue deepest, pink shallowest).

216

N. Mills et al. (-J- =Measured temperatures)

Kristin Field

Fm.

HC(mg/gTOC) Lysing Lange shale I

Lange shale II

Lange sst. I (Albian)

Lange shale III Lange sst. II (Aptian) Lyr /Lange

Garn

Quigley and MacKenzie, 1988

He

Tilje

Single activation energy (default from Platte River BasinMod software)

Are

Horsfieldetal., 1992 t=o Temperature (C) Fig. 11. Modelled oil-to-gas transformation for petroleum in the Kristin Field, offshore Mid-Norway. The results are based on default kinetic parameters used in Platte River 'BasinMod' software, and kinetic parameters generated experimentally by Quigley and MacKenzie (1988) and Horsfield et al. (1992). The three transformation curves show how an oil being generated from an imagined type II kerogen in the reservoirs is transformed into gas as a function of temperature and depth.

exists as two separate phases. The latter is enclosed by a bubble point curve and a dew point curve. The bubble point curve marks the pressure and temperature (PT) conditions where separation of a gas phase from a supercritical liquid phase takes place, while the dew point curve is defined as the PT-area where separation of a liquid phase from a supercritical gas phase occurs. The critical point, located where bubble point and dew point curves meet, characterises fluid conditions intermediate between those of a liquid and a vapour phase. Based on theoretical considerations di Primio et al. (1998) described the evolution of phase envelopes of fluids (1) generated from a source rock as a function of maturity (Fig. 12b), (2) as a function of pressure and temperature reduction (i.e. vertical migration or uplift of a reservoired fluid) on a given fluid composition (Fig. 12c), and (3) as a function of mixing

(Fig. 12d). The results were compared to natural reservoir systems where maturity sequences were present (i.e. greater Ekofisk area, Snorre Field; Fig. 13a,b) and where reservoired fluids had been severely affected by uplift (Barents Sea; Fig. 13c). This comparison confirmed the theoretical assumptions, allowing thus the use of regional PVT data for the recognition of the processes leading to the present-day fluid composition (maturity, phase separation, mixing). An example of the potential of regional PVT analysis in the recognition of mixing sequences is discussed below. Mixing of fluids and predicting fluid relationships and probable phases — Norwegian North Sea

Mixing of fluid phases during migration or in the reservoir results in a re-equilibration of thefinalfluid

From seismic to biomarkers — the value of additional data in continually refining geological models

A \ f

Undersaturated liquid

217

Undersaturated va P°ur

Fig. 12. Phase envelope nomenclature (a) and theoretical evolution of (c) and mixing (d).

composition to the local pressure and temperature conditions. Such a re-equilibration can result in a drastic shift of end-member fluid compositions, e.g. deasphalting of an oil during gas influx or undersaturation of a formerly saturated oil due to mixing with a lower maturity (undersaturated) fluid. The ability to characterise fluid relationships and recognise and quantify mixing sequences through PVT analysis and interpretation proved crucial in the evaluation of a prospect in the North Sea. This case history will be discussed in detail in order to demonstrate the use of PVT analysis in petroleum exploration. The prospect was located in a position between three discoveries. Fig. 14 shows a map of the top reservoir formation with the location of the wells of interest. Wells A, B and C belonged to a field

tase envelopes as a function of maturity (b), uplift or vertical migration

containing an undersaturated oil, well D had tested a saturated oil with a gas cap and well E had encountered a supercritical gas/condensate. The position of the prospect respective to these discoveries made the prediction of communication between the individual wells difficult to assess. Accordingly the question was raised if an alternative evaluation method could shed light on possible fluid relationships in the area and hence predict the most likely fluid type in the prospect. A regional PVT evaluation was performed using the data already available in house. The oils from wells A, B and C showed a relatively similar molecular composition. All samples were characterised by relatively high molecular weights and densities of the Cio+ fraction and by a relatively low GOR of roughly 100 Sm3/Sm3 for well A, 134 Sm3/Sm3 for well B and 144 Sm3/Sm3 for well C

218

N. Mills et al.

600

(a)

300

200

100

200 300 400 Temperature (°C)

500

600

500

600

100

200 300 400 Temperature (°C)

500

600

400 r

100 +

-100

0

100

200

300

400

Temperature (°C) Fig. 13. Phase envelopes of reservoir fluids from (a) the Greater Ekofisk area, (b) the Lunde Formation of the Snorre Field and (c) the Barents Sea.

(calculated from flash to surface conditions, i.e. by mathematically moving the liquid from reservoir P and T conditions to surface conditions and monitoring changes in the physical properties of both vapour and liquid phase as well as the surface GOR). The liquid produced from well D was characterised, as the undersaturated oils discussed above, by high molecular weight and density of the Cio+ fraction. The main difference to the previous liquids was that the oil in well D was at bubble point (i.e. saturated) under reservoir conditions. The GOR of the fluid was the highest encountered in the study area reaching 228 Sm3/Sm3 (calculated from flash to surface conditions). The gas/condensate from well E was characterised by a relatively wet composition and by the fact that it was also undersaturated under reservoir conditions (i.e. in a 'supercritical' state under reservoir P and T). With respect to fluid relationships, it proved impossible to relate the gas/condensate to any of the other fluids in the study area. The fact that it occurred as an undersaturated fluid implied that explaining its existence as a function of phase separation from any

of the other liquids was impossible. Hence it was assumed that the gas/condensate discovery in well E was unrelated to any of the other liquids encountered in the area. Possible relationships among the liquids of wells A to D were addressed by analysing their phase envelopes and through the use of crossplots of specific physical properties of the fluids. The phase envelopes of all samples studied are shown in Fig. 14. As compared to the theoretical phase envelope evolutions, presented in Fig. 12 and discussed above, the phase envelopes of the oils from wells A to D show no indication of representing either a maturity sequence or a migration sequence. From theoretical and experimental considerations one should expect the molecular weight and density of a fluid to decrease during maturation, hence the cricondentherm (location of the point at which the phase envelope, more specifically the dew point curve, reaches the highest temperature) should be found at decreasing temperatures with increasing maturation. Additionally the critical point is expected to shift initially towards higher pressures and lower

From seismic to biomarkers — the value of additional data in continually refining geological models

219

450

Well A

Prospect

Kilometers

100

200

300 400

600

Temperature (°C) Fig. 14. (a) Contour map of the top reservoir of the study area discussed in the text (contour intervals of 50 m). (b) Phase envelopes of the fluids tested. Solid lines represent measured compositions, dotted lines show the phase envelopes derived from a recombination of well A and D compositions to reconstruct well B and C compositions.

temperatures (Fig. 12b). None of these features were noticeable in the comparison of phase envelopes of the liquid samples shown in Fig. 14. In fact the locations of the cricondentherms and critical points of the phase envelopes of the samples from wells A to D point towards a relatively similar maturity of all fluids despite the differences in GOR. However, the very systematic evolution of GOR and phase envelope shape, as well as the comparable bulk composition of the fluids, indicated that the differences observed may have been due to the mixing of two fluids from different sources (as exemplified in Fig. 12d). The mixing of two fluids, with end member compositions represented by the well A and well D compositions, was addressed using PVT modelling. Assuming that the oil encountered is actively spilling along the ridge shown in Fig. 14 towards well A, PVT simulation demonstrated that fluid compositions encountered in wells C and B could be reproduced almost perfectly by varying degrees of mixing. A mathematical recombination of well A and well D fluid compositions at a ratio of 1:1 (mol/mol) led to an exact match of the well C phase envelope including even the locations of the critical point, cricondenbar and cricondentherm (Table 1). Recombination of well A and well D compositions at a ratio of 0.65 (mol/mol) resulted in a fair fit to the well B fluid composition (Table 1).

The excellent reconstruction of well B and C fluid compositions through mixing of well A and well D indicated that the assumption of a mixing relationship among these wells was well founded and could represent the natural situation. Based on these considerations it additionally must be assumed that, given structure, seal and reservoir the mapped prospect must be filled to spillpoint by a liquid at or close to saturation pressure. Petroleum population studies

Although oil-oil and oil-source rock correlations have been important exploration tools for a long time, terminology regarding whether similar oils constitute a 'family' or a 'population' etc. was eloquently summarised and systematised by Horstad and Larter (1995). The classification proposed by Horstad and Larter (1995) allows petroleums to be classified according to both geological origin and subsequent transformations during migration and after accumulation. Fig. 15, modified from Horstad and Larter (1995), schematically shows the relationships between populations and families, whilst Fig. 16, also modified from Horstad and Larter (1995), shows the possible advantages of performing petroleum population work even (or especially?) in relatively mature areas, in order to focus on which of several 'possi-

220

N. Mills et al.

TABLE 1 Comparison of mathematically recombined and natural fluid phase envelopes

Cricondentherm (degree/bar) Critical point (degree/bar) Cricondenbar (degree/bar)

Cricondentherm (degree/bar) Critical point (degree/bar) Cricondenbar (degree/bar)

WellC

Recombined fluid (A + D, 1:1 mol/mol)

Difference

525/51.9 389.8/210.8 213/262.1

522/52.3 390.3/210.6 211.7/265.2

0.6/0.8 0.13/0.1 0.62/1.18

WellB

Recombined fluid (A + D, 0.65 mol/mol)

Difference

522/52.3 390.3/210.6 211.7/265.2

517.9/50.1 392.6/193.4 217.1/242.7

0.79/4.21 0.42/8.2 2.55/8.49

ble' migration routes have actually been active. This figure shows how migration routes are often evaluated using (1) structure maps derived from seismic, (2) predictions of where active source kitchens may be located, based on measured maturity observations from wells and/or from maturity modelling, and (3) reservoir facies distribution maps which are based on lithostratigraphical and chronostratigraphical correlations between wells together with general palaeogeographical considerations. These approaches, when combined, will indeed show possible migration routes which oil may have followed', however, in many cases the result is still that several possibilities remain. It is our contention that the use of petroleum population

(%)

(%)

studies, where possible, building on this plethora of possibilities will at the very least reduce the number of likelihoods and hopefully result in a clear definition of which routes were actually taken by the petroleum. Careful, detailed and consistent use of organic geochemical data integrated with sedimentological and structural work in an area, can result in the development of petroleum populations based migration models that become reliable and predictive in nature. The potential payback from investing in this type of work which is often considered an unnecessary luxury (analytical and interpretation work) can be enormous as discussed below. Any migration model that does not account for and explain observed variations in the

JI

Petroleum Population

Biodegradation

Fig. 15. Definition of petroleum populations and petroleum families with examples of some secondary effects that result in different families within the same population. Modified from Horstad and Larter (1995).

From seismic to biomarkers — the value of additional data in continually refining geological models

Reservoir Distribution Maps

Maturation Maps

Structural Maps

221

°t 0.75B a> £

0.7-|

CL 0.65 |W^«a b

0.6

E 055

l

. ReldA m Field B m Field C

i

0.5 40.4

0.^5

0.5

0.55

0.6

Biomarker Parameter t

Possible Migration Routes

Petroleum Population Work

Actual Migration Routes

Fig. 16. Schematic highlighting the major input parameters to evaluating migration routes. Traditional approach often results in definition of several possibilities. Use of petroleum populations refines this considerably. Modified from Horstad and Larter (1995).

chemistry of discovered petroleums is by definition incomplete and erroneous. Southern Triangle, block 34/7, Tampen Spur Fig. 17 shows a series of migration models for the Tampen Spur area. The 1985 example (Fig. 17a) is a conceptually driven model based on gross regional structuring and known oil-water contacts in the area. At this time no attempt had been made to interpret and incorporate geochemical data from fluids in a regional context. The gross model was that oil migrated through the Statfjord Field and eastwards and northwards into the Snorre Field before continuing southwards to the regional high point in the Gullfaks Field (Thomas et al., 1985; Karlsson, 1986). During the late 1980s a significant effort was devoted to

gathering both fluid and core samples throughout the area and analysis of the large database resulted in the identification of significant differences in the fluid characteristics at biomarker and carbon isotope levels (Horstad et al., 1995), despite the prevailing attitude that "everything is generated from the Kimmeridge Clay equivalents, isn't it?". The immediate result of this work is represented in Fig. 17b, showing the status as of 1989. Here it became obvious that although the simple picture portrayed in Fig. 17a represents a gross, possible migration history, it could not be the whole truth. It was now possible to see that for example the oil migrating north, through the Statfjord Field (the green population in Fig. 17b) did not reach the Snorre Field but rather moved into the Statfjord East Field and subsequently east to east-southeast into the Tordis

222

O)

00

o


o

E c 0 >

i.

"O (0 +•* (0

Q

N. Mills et at.

o

I

T3

c3

ia UH

W)

E cd a)

c o

3

die

>

o

O

OH

3

lati

From seismic to biomarkers — the value of additional data in continually refining geological models

Field and finally further down into the western part of the Gullfaks Field. The Snorre Field seemed to represent a population of its own (red in Fig. 17b) and more interestingly (and a main argument for oil not having migrated north into the Snorre Field) the Vigdis West and Statfjord North fields (blue in Fig. 17b) are significantly different to both the 'Snorre' and the 'Statfjord' populations. These results proved so interesting and were evaluated against upcoming prospects (see Horstad et al., 1995 for details), passing with flying colours such that further work was instigated to fill any geographical or stratigraphical gaps in existing wells/fields and each new well drilled was thoroughly analysed and the results plugged into the regional picture. This has resulted in the picture as seen in Fig. 17c, where now two populations are identified within the Snorre Field and the Vigdis Field is considered to be a mixture of the southernmost Snorre population and the 'Statfjord North-Vigdis West' population (Horstad et al., 1995). In Fig. 17c, additional discoveries in the area between the Statfjord East Field and the Tordis Field have confirmed the proposed relationships and migration routes between these two fields (the 34/7-21 discovery is discussed in Horstad et al., 1995). The 'Southern Triangle' is the area delineated by the southern border of block 34/7 and the southwestnortheast fault immediately south of the Tordis Field and the southeast-northwest trending part of the inner Snorre fault up to where it meets the former fault (Fig. 18). The 'Southern Triangle' area was part of a larger area facing relinquishment and the license had to decide on a 'drill or drop'. Consensus of opinion had long been that the 'Southern Triangle' was in a migration shadow since well 34/7-2 to the north was dry and this ruled out migration from the north whilst migration from the east was considered unlikely due to a combination of structural and source maturity considerations. In addition, from the long established structurally defined migration model the Tordis Field would spill southwards and into the western part of the Gullfaks Field (and indeed the geochemical analyses had shown that the oil in the Tordis Field is the same population as that in the Gullfaks Field). As part of the general background work and to contribute to the relinquishment discussion the hydrocarbons found at several levels in the 34/7-21 and -21A wells were analysed, together with some other, previously uninvestigated oils in the area (i.e. 34/10-18 and 34/10-34) and key oils from the Tordis Field (well 34/7-14) and the western part of the Gullfaks Field (well 34/10-14). Fig. 18 shows some data from these samples together with a location map. The x-y plots show the data for these oils for a selection of the biomarker

223

parameters that had proved useful in establishing the general petroleum population distribution on the Tampen Spur. Here it is clear that even within this geographically reasonably well confined area there are clear differences between the fluids. The most important aspect with respect to the relinquishment discussion is the observation that some oil from wells 34/7-21 and -21A differs from the other oil in the same wells and from the oils from the Tordis and Gullfaks Fields (wells 34/7-14 and 34/10-14, respectively). However, this same 'different' oil is also picked up in wells 34/10-18 and 34/10-34 which lie south of the 'H' discovery and south of the Tordis Field, respectively. This led to the proposal that since the oil in the southernmost well in the Tordis Field was different from the oil in well 34/10-34 (through which any oil spilling south from the Tordis Field would have had to migrate, according to accepted models), then the Tordis Field could not have contributed to the Gullfaks Field by this route and the spill from the Tordis Field must have been via some other direction. The only remote possibility for this was established to be by spill from the Tordis Field towards the east and thereby through the 'Southern Triangle'. Confidence in the predictive power of petroleum populations in the area and the ability to document this convinced the license to choose to drill rather than drop the area. Well 34/7-22 was spudded and discovered approximately 35 million barrels of oil. In Fig. 19 data from well 34/7-22 are superimposed on two of the plots of Fig. 18 and it is clear that the predicted relationship is confirmed. Thus the acquisition of large amounts of high-quality, reproducible biomarker data and the integration of this into the regional framework in a consistent manner resulted in this technique being responsible for (1) making a discovery, (2) retaining acreage, and (3) to date (due to a subsequent well in the area (34/7-25) which proved an additional 11 million barrels and identified probable reserves of 32 million barrels), accounting for total reserves, in an area almost given away, reaching approximately 78 million barrels. The east flank of the Northern Viking Graben The Gj0a discovery lies in blocks 35/9 and 36/7 on the northern part of the Uer Terrace (Fig. 3). The Uer Terrace is situated east of the tectonic transition zone between the Northern Viking Graben and the Sogn Graben. The reservoir sections comprise sandstones of the Lower, Middle and Upper Jurassic. The main reservoir units are sandstones belonging to the Fensfjord, Sognefjord and Draupne Formations and the Dunlin Group. The Gj0a discovery and surrounding satellites lie to

224

'*
fa:H_

d

d

TS C CD C

as C0

c

"U

K.

(D

c

Sr

co

a. 3 £ a


X Q.

Ho

CM

3

+ £ o o

8 3

s o o T—

Z>

i

On

« • • < ! >

•

(mi) ©uedotMOusui Isjjeinidc^

S x: X

T

+

$


o

1

£

T3


a H

o

fa

^£ X)
•o

o

E

CO

& ©

"3K

ff

X

hCM

n

o

N. Mills et al.

E

f sele UH

bo

oo

Plo

8 euedomou oe - (H)*HZ '(H)QZl + euBdogJOu zz - (H)BZI 'lAiflem Bgt, eiredoijjouzg - (H)ez L 'lAgjetu egi.

o o o ©uedoqiou oe - (HfalZ lH)«ZI auia^dusjq oe¥2 :TH)qi2TH)B8l. '(H)ezT

for para

ane 21a norh

ath

CM CM €0

.[ +CC

mc4

^Q

o o

^

TP—

„C O T OS T3

T

-—•»

xr

ffi X N. OS

,.D X CJ (0 T— sr>

T

£1

"O

"O

m 03

!

i 1 Q. 3 CS Q

c

c cs C/) a>


CL

x

*©s

!

I 1

cy

| |2 < 1

h*

"* CO

T5

CO

t^ ^t

w

<

H

Q a. i2

<$

© c CL 3

CO

C

I 4

I

1 1 1 I

1

1 1

#

60 W +J CD

m m +-*

6 t>

CM

CO

2~

o

o CM

«#

CD

^

CO

^r CO

fr

•^r

it

V> m C0 13 ~3

Ci

09

rr

o

^r

O

£

CO

+ «*~*

2 Q.

IE ©

0

c/> © c

Q. 3

Q.

S5 o

CD

^ CO

rv.

^t

£ CM Is*

«# CO

•

w m 5

C6 i_

3 " " •

1

> 1 m • I

+ IB

Iv

CO

^

6

Tt CO

Cre

From seismic to biomarkers — the value of additional data in continually refining geological models

o o o o ©uedOMJOO oe - {H)mz 4(H)Qa + euedoyjou iz - (H)^Zf 4i_At#euj e g i '""euidoupb^

9uedOi|ioy oe - (H)Qt2 '{H)ezi etedotiiOiji^

Intra and

O o

T3 O

a c o

H

^o

H o

225

226

i

CM

CO

t: 00

Wd

LiTHO,

dnojo

T~ ~ ~~

®s

f

ONWIA

1

I

||

J

j

—' -i

J

J

dnoj©

i^id

i_

:::^^^~dl|

• I III 111 II 1 1

> O >

1

F

LL

DLL

P ^ *or 00 l-g co §

5> CO

•

liS

•>a:

[

ONWIA

J3 J

—i

3

liiiil •

AlN03dSNn QNV113HS

E LL •o

o CMtpr

a*«^j

-s31 s

-^ ^ — Jm\ -^SSjJI DLL

h: <5 c co

E LL "D O

• t/5 CO § DLL

—

-

i

_=a ~~3i

z:d!& »°?;,-r;-r~~B&ittil*

N. Mills et al

o T3

o

o u T3

£

£ si

E

227

From seismic to biomarkers — the value of additional data in continually refining geological models the east of the Sogn Graben. It is generally recognised that the primary source rocks for liquid petroleum generation in the Sogn Graben are thought to be the Upper Jurassic Draupne and Heather Formation organic-rich lithologies. In the Sogn Graben the depth of the base Cretaceous ranges from 6000 m to 2000 m, and based on basin modelling studies oil generation started ca. 40 Ma BP and continues to the present day. The Gj0a discovery and surrounding satellites are characterised by having different phases of hydrocarbons (gas/oil/water) at various sandstone horizons in the Brent and Viking Groups (Fig. 20). The lowermost oil-bearing horizons of wells 35/9-1 (Dunlin Group - DST1) and 36/7-1 (Fensfjord Formation - DST1) are characterised by rc-alkane envelopes stretching from Ce to C35; however, the upper horizons (Fensfjord Formation and Brent Group) in 35/9-1 and 35/9-2 contain petroleum exhibiting a narrower n-alkane range (n-C^ to n-C22) (Fig. 20). A cross-plot of two independent geochemical parameters (saturate fraction carbon isotopes and 28,30 bisnorhopane/C29 abhopane - Fig. 21) splits the oils into two distinct oil families, oil family 1 consists of well 35/9-1 DST1, 2, and 3, and well 36/7-1 DST1, and oil family 2 contains well 35/9-2 DST1, 2, and 4. From hopane and sterane biomarker maturity parameters the oils from well 35/9-2 are thermally less mature than the oils from well 35/9-1. Oil family

1 oils have been generated from source rocks residing at peak oil generation, and oil family 2 oils at maturity levels equating to beginning of the oil window. The striking difference in the rc-alkane envelopes between the oils in the lower intervals of wells 35/9-1 (DST1) and 36/7-1 (DST1) and those present in higher horizons can be attributed to phase separation. When placed into the geological context it is considered that the oil generated in the Sogn Graben from Draupne and Heather Formation shales, migrated updip through Draupne Formation sands and probably via faults and fractures into Dunlin and Brent Group, Fensfjord and Sognfjord Formation sands. As the oil migrated updip, phase separation occurred, the exsolved gas then migrated faster as a separate phase and at the very top of the carrier bed filling sandy intervals of the Brent Group of well 35/9-1 and the Fensfjord and Sognefjord Formations of well 35/9-2. This process may have been aided by faults and fractures which are prominent in the area. The PVT data show that all the oils in the area are saturated, indicating that the oils have lost a gas component. The depth at which the bubble point is reached is not known and therefore the connectivity and lateral extent of the sands can not be assessed. Oil family 1 oils in comparison to oil family 2 oils show significantly different biomarker distributions and saturate fraction carbon isotope compositions inferring that there has

0.70 A

35/9-1 DST1

X 35/9-1 DST2 +

35/9-1 DST3

•

35/9-2 DST1

•

35/9-2 DST2

•

35/9-2 DST4

•

36/7-2 DST1

0.60

0.50 c5

Q_ O

0.40

oj O co

0.30

CL O

o c w !Q

o 0.20 co 00 CM

4 0.10

-+-30.00

-29.80

-29.60

-29.40

-29.20

•+-29.00

0.00

-+-28.80

-28.60

-28.40

-28.20

-28.00

Saturate fraction del 13C PDB Fig. 21. Cross-plot of saturate fraction carbon isotopes versus a biomarker source parameter for DST oils from blocks 35/9 and 36/7. The data split into two distinct groups suggesting two oil families.

228

probably been no communication between the two structures. This lends credence to the seismic data which suggests that Upper Jurassic sediments between wells 35/9-1 and 35/9-2 have been eroded and replaced by Cretaceous shales. Well 36/7-1 DST1 plots with Group 1 oils and shows a similar n-alkane envelope to that of well 35/9-1 DST1, implying that oil has spilled from the Dunlin Group of well 35/9-1 into the Fensfjord Formation of well 36/7-1. The difference in the biomarker distributions (source facies and thermal maturity) between the two groups of oils indicates that they were sourced from different sections of the Sogn Graben. The oil family 1 oils were probably sourced from Upper Jurassic shales lying to the northeast, and oil family 2 oils directly to the west. The oil in well 36/7-2, which lies updip of well 36/7-1, is heavily biodegraded and no biomarker correlation was possible. The integration of petroleum population work with PVT data and the general geology of the area has resulted in a better understanding of fluid migration and present-day distribution. Conclusions

The explorationist has a formidable and sometimes bewildering array of tools available in his or her prospect evaluation arsenal. These have a tremendous range in scale from megaregional seismic studies to subatomic investigations of minerals or fluids. The resolution and applications of these many weapons vary, complement and occasionally overlap. All of these approaches can yield vital information to aid in improving understanding of the subsurface with respect to Generation, Expulsion, Migration, Accumulation and Sealing of hydrocarbons (GEMAS). Several of the more detailed and small-scale techniques may produce data whose interpretation has such far reaching consequences that previous 'knowns' must be revised and interpretations from the larger-scale approaches modified, perhaps with major regional or semi-regional implications. Any or all of the erroneously dubbed 'luxuries' discussed above may at some point result in discovery of petroleum, development of new exploration plays, contribute to placement or otherwise of expensive wells. It is vital that the correct amounts of the right types of data are gathered and that these data are used — anomalies are trying to tell us something and may be the key to the whole puzzle. Look after the data and the models will look after themselves! Acknowledgements

We would like to acknowledge Saga Petroleum and the partners in licences PL089, PL066, PL 153 and

N. Mills et al.

PL199 for permission to use data from these licences. Liv Ravdal is acknowledged for help with drafting the figures. The laboratory staff in Saga Petroleum deserve thanks for producing good-quality data. References Andreev, P.F., Bogomolov, A.I., Dobrayanskii, A.F. and Kartsev, A.A., 1968. Transformation of Petroleum in Nature. Pergamon Press, London. Andresen, P., Mills, N., Schenk, HJ. and Horsfield, B., 1993. The importance of kinetic parameters in modelling oil and gas generation — a case study in 1-D from well 2/4-14. In: A.G. Dore, J.H. Augustson, C. Hermanrud, D.J. Stewart and 0 . Sylta (Editors), Basin Modelling: Advances and Applications. Norwegian Petroleum Society (NPF), Special Publication 3. Elsevier, Amsterdam, pp. 563-571. Bailey, N.J.L., Burwood, R. and Harriman, G.E., 1990. Application of pyrolysate carbon isotope and biomarker technology to organofacies definition and correlation problems in North Sea Basins. In: B. Durand and F. Behar (Editors), Advances in Organic Geochemistry 1989. Pergamon, Paris, pp. 1157-1172. Behar, F , Ungerer, P., Kressmann, S. and Rudkiewics, J.L., 1991. Thermal evolution of crude oils in sedimentary basins: experimental simulation in a confined system and kinetic modelling. Rev. Inst. Fr. Pet., 46(2): 129-154. Blakey, E.-S., 1985. Oil on Their Shoes, Petroleum Geology to 1918. American Association of Petroleum Geologists, Tulsa, OK. Connan, J., 1974. Time-temperature relation in oil genesis. Am. Assoc. Pet. Geol., Bull., 58: 2516-2521. di Primio, R., Dieckmann, V. and Mills, N., 1998. PVT and phase behaviour analysis in petroleum exploration. Org. Geochem., 29: 205-220. Dieckmann, V., Schenk, H.J., Horsfield, B. and Welte, D.H., 1998. Kinetics of primary and secondary generation and cracking by programmed-temperature closed-system pyrolysis of Toarcian shales. Fuel, 77:23-31. Horsfield, B., Schenk, H.J., Mills, N. and Welte, D.H., 1992. An investigation of the in-reservoir conversion of oil to gas: compositional and kinetic findings from closed-system programmed-temperature pyrolysis. In: C.B. Eckardt, J.R. Maxwell, S.R. Larter and D.A.C. Manning (Editors), Advances in Organic Geochemistry 1991. Org. Geochem., 19: 191-204. Horstad, I. and Larter, S.R., 1995. Petroleum migration, alteration and remigration within Troll Field, Norwegian North Sea. Am. Assoc. Pet. Geol., Bull., 81(2): 222-248. Horstad, I., Larter, S.R. and Mills, N., 1995. Migration of hydrocarbons in the Tampen Spur area, Norwegian North Sea: a reservoir geochemical evaluation. In: J.M. Cubitt and W.A. England (Editors), The Geochemistry of Reservoirs. Geol. Soc, Spec. Publ., 86: 159-183. Karlsson, W., 1986. The Snorre, Statfjord and Gullfaks oilfields and the habitat of hydrocarbons on the Tampen Spur, offshore Norway. In: A.M. Spencer, C.J. Campbell, S.H. Hanslien, E. Holter, P.H.H. Nelson, E. Nysaether and E.G. Ormaasen (Editors), Habitat of Hydrocarbons on the Norwegian Continental Shelf. Norwegian Petroleum Society, Graham and Trotman, London, pp. 77-85. Kuo, L.-C. and Michael, G.E., 1994. A multicomponent oil-cracking kinetics model for modeling preservation and composition of reservoired oils. Org. Geochem., 21(8/9): 911-925. Pepper, A.S. and Dodd, T.A., 1995. Simple kinetic models of petroleum formation, Part II. Oil-gas cracking. Mar. Pet. Geol., 12(3): 321-340. Pusey III, W.C., 1973. The ESR-kerogen method: a new technique of estimating the organic maturity in sedimentary rocks. Pet. Times, 77: 21-26. Quigley, A.T., MacKenzie, A.S. and Gray, J.R., 1987. Kinetic theory of petroleum generation. In: B. Doligez (Editor), Migration of

From seismic to biomarkers — the value of additional data in continually refining geological models Hydrocarbons in Sedimentary Basins. Editions Technip, Paris, pp. 649-666. Quigley, A.T. and MacKenzie, A.S., 1988. The temperatures of oil and gas formation in the sub-surface. Nature, 333: 549-552. Schaefer, R.G., Schenk, H.J., Hardelauf, H. and Harms, R., 1990. Determination of gross kinetic parameters for petroleum formation from Jurassic source rocks of different maturity levels by means of laboratory experiments. In: B. Durand and F. Behar (Editors), Advances in Organic Geochemistry 1989. Pergamon Press, Oxford, pp. 115-120. Schenk, H.J., di Primio, R. and Horsfield, B., 1997. The conversion of oil into gas in petroleum reservoirs, Part 1. Comparative kinetic investigation of gas generation from crude oils of lacustrine, marine and fluviodeltaic origin by programmed-temperature closed system pyrolysis. Org. Geochem., 26(7/8): 467-481. Spencer, A.M., Home, PC. and Wiik, V., 1986. Habitat of Hydrocarbons in the Jurassic Ula Trend, Central Graben Norway. In: A.M. Spencer, C.J. Campbell, S.H. Hanslien, E. Holter, P.H.H. Nelson, E. Nysaether and E.G. Ormaasen (Editors), Habitat of Hydrocarbons on the Norwegian Continental Shelf. Norwegian Petroleum Society, Graham and Trotman, London, pp. 77-85. Stoddart, D.P., Hall, P.B., Larter, S.R., Brasher, J., Li, M. and Bjor0y, M., 1995. The reservoir geochemistry of the Eldfisk Field, Norwegian North Sea. In: J.M. Cubitt and W.A. England (Editors), The Geochemistry of Reservoirs. Geol. Soc, Spec. Publ.,

N. MILLS R. DI PRIMIO S. HVOSLEF D. STODDART I. THRONDSEN M. WHITAKER

229

86: 257-279. Thomas, B.M., M0ller-Pedersen, P., Whitaker, M.R and Shaw, N.D., 1985. Organic facies and hydrocarbon distribution in the Norwegian North Sea. In: B.M. Thomas, A.G. Dore, S.S. Eggen, PC. Home and R.M. Larsen (Editors), Petroleum Geochemistry in Exploration of the Norwegian Shelf. Graham and Trotman, London, pp. 3-26. Tissot, B. and Espitalie, J., 1975. L'evolution thermique de la matiere organique des sediments: applications d'une simulation mathematique. Rev. Inst. Fr. Pet., 30: 743-777. Tissot, B., Espitalie, J., Deroo, G., Tempere, C. and Jonathan, D., 1974. Origin and migration of hydrocarbons in the eastern Sahara (Algeria). In: B. Tissot and F. Bienner (Editors), Advances in Organic Geochemistry 1973. Edition Technip, Paris, pp. 315-334. Ungerer, P. and Pelet, R., 1987. Extrapolation of the kinetics of oil and gas formation from laboratory experiments to sedimentary basins. Nature, 327: 52-54. Ungerer, P., Behar, R, Villalba, M., Heum, O.R. and Audibert, A., 1988. Kinetic modelling of oil cracking. Org. Geochem., 13(4-6): 857-868. Welte, D.H. and Yalcin, M.N., 1988. Basin modelling — a new comprehensive methodology in petroleum geology. Advances in Organic Geochemistry, Venice 1987. Pergamon, Oxford, pp. 141— 151.

Applied Petroleum Technology A/S, Instituttveien 18, N-2007 Kjeller, Norway Norsk Hydro Research Centre, P.O. Box 7190, N-5020 Bergen, Norway . Norsk Hydro Oil and Gas, Kj0rboveien 16, P.O. Box 490, N-1301 Sandvika, Norway Norsk Hydro Oil and Gas, Kj0rboveien 16, P.O. Box 490, N-1301 Sandvika, Norway Norsk Hydro Oil and Gas, Kj0rboveien 16, P.O. Box 490, N-1301 Sandvika, Norway Norsk Hydro Research Centre, P.O. Box 7190, N-5020 Bergen, Norway