The Fulmar Oil-field (Central North Sea): geological aspects of its discovery, appraisal and development

The Fulmar Oil-field (Central North Sea): geological aspects of its discovery, appraisal and development Howard D. Johnson*, Thomas A. Mackayt, and David J. Stewart¢ Shell UK Exploration and Production, ShelI-Mex House, Strand, London WC2R ODX, UK Received 10 December 1985

The Fulmar Field is a large, late Jurassic dome-shaped structure with approximately 427 × 106 bbl (68 × 106 m 3) of recoverable oil (40° API) contained mainly within Upper Jurassic shallow marine sandstones (Fulmar Formation). The field is situated within the UK sector of the Central North Sea (170 miles/270 km south-east of Aberdeen) in water depths averaging 265 ft (81 m), and is !ocated mainly within Shell/Esso Block 30/16 and, to a lesser extent, Block 30/11b (Amoco/Mobil/Texas Eastern/Amerada/Enterprise). This paper describes the geology of the Fulmar Field in terms of its discovery, appraisal and development, with emphasis on its reservoir geology. The field was discovered in 1975 when Shell/Esso well 30/16-6 established an important new oil play within the Fulmar Formation in the South-West Central Graben. Field commerciality was established by one appraisal well (30/16-7) but pre-development drilling of four oil producers (through a six slot, subsea template) allowed further geological appraisal prior to platform installation and oil production. The four template wells indicated that the reservoir was more complex than originally anticipated. Extensive coring of the discovery, appraisal and pre-development wells (2200 ft/670 m) provided an essential basis for a thorough reservoir description and the construction of a reservoir geological model. The structural configuration of the field has been derived from a 3D seismic survey (undertaken in 1977 prior to development drilling) but seismic resolution of the prospective Jurassic interval, and the underlying Triassic, is poor. The main geological features of the field are described in the paper and summarized below. The Fulmar Sands are of Oxfordian-Volgian age. The reservoir mainly comprises shallow marine sandstones of the Fulmar Formation (Oxfordian-Kimmeridgian; Members II and III), and a subordinate deeper water sandstone body (Volgian; Member I) enclosed within the overlying Kimmeridge Clay Formation (= Kimmeridge Sand Member). The Fulmar Formation consists of 500 - 1100 ft (150-335 m) of variable shallow marine sandstones. The Member III sandstones provide the main reservoir (approx. 90% reserves) and consist of large-scale (ca. 200 - 600 ft, 60-180 m thick), coarsening upward sequences in which very fine grained argillaceous sands (non-reservoir) are replaced upwards by fine to medium grained, well sorted sands displaying excellent reservoir properties (e.g. porosities 20 - 30% and permeabilities 500 - 4000 roD). The Member II sandstones are fine grained and argillaceous, show coarsening upward sequences and are characterized by siliceous sponge remains, early silica (chalcedony) cement, and calcite concretions. These sandstones are of generally poorer reservoir quality (e.g. porosities 15- 25% and permeabilities 1 - 500 mD), they are resticted to the upper part of the formation on the northern and eastern flanks of the field, and interfinger westwards with some of the better quality Member III sandstones. These Fulmar sandstones are all extensively bioturbated, and were deposited slowly in an irregularly subsiding shallow marine basin (shelf or shoreface) which deepened eastwards into the Central Graben. The pod-shaped geometry of sand thickness distribution, which appears to be unrelated to those faults mapped within the field, is interpreted as a reflection of salt-related subsidence (eg. salt withdrawal) during sedimentation. The Member I sandstones form a wedge-shaped unit within the Kimmeridge Clay Formation, which sharply overlies the Fulmar Formation on the western flank of the field. They are interpreted as laterally restricted turbiditic sandstones which were emplaced across an active Auk Horst boundary fault. These sandstones are of very high quality (eg. porosities 2 5 - 35% and permeabilities 1000 - 10,000 mD) but they are volumetrically subordinate (approx. 10% reserves). The Fulmar Field reservoir sandstones display abundant evidence of syn- and early postdepositional, dewatering-related, soft sediment deformation (eg. fractures, autobrecciation, fluidisation pipes and some slumping) and have undergone environment-related diagenesis (mainly quartz and feldspar overgrowths, silica and calcite cementation) and early burial diagenesis (mainly dolomite cementation and minor clay mineral authigenesis). *Present address: Sarawak Shell Berhad, Lutong, Miri, State of Sarawak, Federation of Malaysia tPresent address: Shell UK Exploration & Production, P.O. Box 4, Lothing Depot, North Quay, Lowestoft, Suffolk NR32 2TH, UK ¢Present address: Koninklijke/Shell Exploratie en Produktie Laboratorium, Volmerlaan 6, Rijswijk, The Netherlands

0264-8172/86/02099-27 $03.00 ©1986 Butterworth & Co. (Publishers) Ltd

Marine and Petroleum Geology, 1986, Vol 3, May

99

Fulmar Oil Field: H.D. Johnson et al Reservoir quality distribution within the field mainly reflects depositional textural variations which have been variably enhanced, and only rarely overprinted, by diagenesis. T h e Fulmar structure is a relatively simple dome-shaped anticline with prominently dipping flanks (ca. 8-25°). There is one main OWC at 10840 ft subsea (3304 m) and a more localized, higher OWC on the northern flank at 10560 ft subsea (3219 m). The western flank of the field is conformably capped by the Kimmeridge Clay Formation, while the eastern flank is unconformably overlain by the Chalk (overlying the regionally extensive late Cimmerian unconformity). The field is cut by NW-SE trending normal faults which mainly hade eastwards, but subsidiary, westward hading antithetic faults are also present. The structural configuration is interpreted as reflecting late stage (late Jurassic) salt withdrawal from below an Upper Jurassic secondary rim syncline, which results in the characteristic pod-shaped geometry. The faulting is related to the Auk Horst/Central Graben boundary fault system and occurred prior to the formation of the late Cimmerian (early Cretaceous) unconformity surface. For reservoir management purposes the Fulmar reservoir has been subdivided into seven units. The western flank of the field contains six units which are named after British rivers using the word 'Fulmar' as a mnemonic: Forth, Usk, Lydell and Mersey units (= Member III), Avon and Ribble Units (= Member I). The eastern flank of the field contains an incomplete sequence capped by Member II sandstones, which is informally termed the Clyde Unit (named after the adjacent Clyde Field). The field is being developed from a 36-slot platform with adjoining 6 slot jacket and subsea template system. To date, 23 development wells have been drilled, ten for water injection, one or two (provisionally) for gas injection and the remainder for production. Approximately five additional wells may be drilled in the future. Depletion is supported by both water injection, around the periphery of the field, and gas injection (for temporary storage) in the crest. After the first four years of production the reservoir performance remains consistent with the geological model. The various units within the Fulmar Formation are in full pressure communication. The faults are non-sealing, despite the presence of the high OWC in a fault-bounded segment on the northern flank. The uppermost Member I sandstones (= Ribble Unit) have suffered some pressure depletion due to localized fault juxtaposition against the main Member III reservoir sands (i.e. Lydell and Mersey Units). The geology of this substantial oil-field is described in the context of the development of depositional and structural models, which led to its discovery, appraisal and development. A chronological framework has been adopted in order to outline the evolution and continuous refinement of geological concepts, ranging from a general regional model used for the generation of similar exploration prospects in the Central North Sea, to a more detailed reservoir model that has guided field development and reservoir management. Keywords: North Sea; Upper Jurassic; Fulmar Field; Shallow marine sandstones; Reservoir geology

Introduction The Fulmar Field is situated within the UK sector of the Central North Sea (CNS), some 170 miles (270 km) south-east of Aberdeen and 7 miles (11 km) north-east of the Auk Field (Figure 1), in water depths averaging 265 ft (81m). The field was discovered in 1975 when Shell/Esso well 30/16-6 first established the presence of a commercially important oil play within Upper Jurassic shallow marine sands in the South-West Central Graben. Field commerciality was subsequently established by one appraisal well. Four development wells were pre-driiled through a subsea template prior to platform production which commenced in February 1982. To date, a total of 23 development wells have been drilled and recoverable reserves are currently estimated at 427 × 106 bbl (68 × 106 m 3) of oil with a gravity of 40° API (STOIIP is estimated at 801 x 106 bbl/127 x 106 m3). The field straddles blocks 30/16 (Shell/Esso) and 30/llb (Amoco/Mobil/Texas Eastern/Amerada/Enterprise) and has been unitized. As a consequence of the 1981 equity redetermination, Shell/Esso currently hold approx. 94% of the field. The Fulmar Field is operated by Shell UK on behalf of the Shell/Esso North Sea Venture and the Fulmar Unit.

Geological setting The Fulmar Field is situated on a fault-bounded terrace

100

which forms the western margin to the South-West Central Graben, adjacent to the Auk Horst (Figure 1). The graben margin comprises a series of rotated, step faults, hading east and combining to give an overall throw of approximately 3000 ft (914 m) at top Devonian level (Figure 2). Only locally preserved Zechstein salt is present along the graben margin, in contrast to the large salt sequences and diapirs found in the graben centre (Figure 2). However, the Fulmar structure appears to show the influence of both halokinesis and graben tectonics. Hydrocarbons are principally trapped in fine to medium grained, shallow marine sandstones of Upper Jurassic age (Oxfordian-Kimmeridgian) with shales of the Kimmeridge Clay Formation and Upper Cretaceous Chalk providing the cap-rock/seal on the western and eastern flanks respectively. These sandstones have been referred to as the Fulmar Formation (Johnson and Stewart, 1985) and are one of several prospective Upper Jurassic intervals in the North Sea. The reservoir sandstones are comparable with those of the Piper, Ula and Clyde fields and interfinger basinwards with bioturbated shales of the Heather Formation

(Figure 3). An additional reservoir interval in the Fulmar Field is provided by mass emplaced sandstones (of Volgian age) within the Kimmeridge Clay Formation and referred to as the Kimmeridge Sand Member (Figure 3). This upper reservoir unit, together with the sands of the

Marine and Petroleum Geology, 1986, Vol 3, May

Fulmar Oil Field: i-I.D. Johnson et al 3°

"

,~'~i !i/~/:¸!ii ;

~J:,~

/- / \\

\ • \

/"

FULMAR~ l 1 1 1 1

~

,

se"

'

F I S H E R BANK

I

SOUTH HALIBUT

-~

BASIN

-~-

'

BASIN

~'"

.@:.;.~:iLONG~::.

"'o

-

~'

%

,,

,,

ii::i::i::!liiiiiiiiii:":'ii~ii~i i~i@~i!~ ~

~

I ......

~i~:

.

O

4'

iC!s:~s~s~:::".~:".i:~'s~: :. :::.":i!.~::!::i ; ::F:!i!i::ii ~:;i~!iii::~:~*:!:i

!@iii@ii!ii!liiiiiiiii!iiii!iii!iiif£~i;i;@li;iiiBi!!i!ii!iiii!iii@iiiii@

iiii@iiii~ii@iiii~;."

iiiiiiiiiii:~iiiii}iiii~

\

IBi J iiBii iJ!!iiiB ii!ili~iii!iiii!ii'!!!!i:~Io: , '~:'!!i~o~:,~,,~:~'~!',s:E~: ~:,~:!,:~:,~iiiii!iJiiiiiiiiiiiiiiii!iiiii'!iiii',','i~::~ii~Y' ~ ;41i:,~f/~ iiiiii!iiiiiiii iiiiiii~iiiiiilii i,iiii!~iiii~iiiiiFiiiiiiiilSiili!iliiiiiiii!iiiiiiiiiiiiiiiii~iiiiiiii!iiiiiiiii@!iiiiiiiiiii!i!iiiiiii!iii!i iiiiiiiiiiii@iiii@iii@@iiiill iiiiiiiii~iiiiiiiiii~iiiiiiiiit\ =~ !:~

!~i.'..:~:~:~ :~.~::~ ~:~.~:~:~:~.~;;!8~.;~ s:s::.::.::~s~s~::':!s:;~:::~:':~.,:;.~..~:::~:~!'.'..s~::!#:~:~::s~::'s:::.~:~:~s:~.~::::::: s~!:s~s~::'::..:~:!. ~~i~':'-~ie:~.s!:!:~:~::.s~::::

@ ~~ ~

Figure

.

~i"~:'i!iJ

'-,L>'iii4

\/%

i i!!iti~it! ii ;il~i;iiii~ii~ ;ii@iiil~i~ili~ii!:iiiiiiiiii;iiiii~4iiii:ii!iii:ii!iiiiiil :iiiiiiii~ii!ii!iiiiii@iiiiiiiii~@!iiiiiiii@iiiiiiiiiiiii::

iiiiiii!~iil ~

::~ii!iii:i:ii:i:ii::#j::i#/i!:y/::i:i:i:/h

- r~ ~

\'

!8 ~:::~:!::':::::¢:::s:s~:::::.

~i~i~i:iii i~iii:~l!i!iiliB iiiii!ili'i@iiiii@iiiii!ii!liiiiiii@! @iiiiiiiiii~W!i~@iiiiiiiiii i!@iiiiiiiiiii@i!iiiiiiilF .

.

.

~:;~!~iiiiiiiiiiiil@iii!i~i~i~!~ii;!itii.~!i/ili!!iiiiii@i@711!i iii;i@i!i@i!ii~..!:.]i~i~i~@.'~iJii!i!iiJ;iriiiiiiilliiiiio ii

~9

29

39kin

1 Megatectonic framework of the Central North Sea and location of the Fulmar Field

Marine and Petroleum Geology, 1986, Vol 3, M a y

101

Fulmar Oil Field: H.D. Johnson et al NE

SW AUK

FULMAR

EKOFISK

~

-------

~

-

iiiiiiiiii!ii!i!ii

• * . * * * * * * * * * . * , . * . % ' , * * * * * . 20000': •

.

+

:

+

+

.

,

+

+

+

+

+

+

. ::.:.:.:.:.:.:.:.:.:.:

+

+

÷

+

+

+

+

*

+

.:::::::

+

+

*

*

•

*

*

*

•

4

:

EOCENE - PLEISTOCENE

EARLY CRETACEOUS

ZECHSTEIN SALT

PALAEOCENE

JURASSIC

ROTLIEGEND & DEVONIAN

LATE CRETACEOUS

TRIASSIC

BASEMENT

0 I

+

:s .........

50km I

,

Figure

2 Regional geological cross-section across the Central North Sea (from Ziegler, 1982)

:f

OUTER MORAY FIRTH

STAGE

,,h;, 8

RYAZANIAN/ BERRIASIAN

VOLGIAN

CENTRAL GRABEN

SOUTH VIKING GRABEN

NORTHERN NORTH SEA

EAST CENTRAL GRABEN (NORWAY) --

o

KIMMERIDGE CLAY FM

i-- I ~

K|MMERIDGE

II-

~

KIMMERIDGE

~

~

KIMMERIDGE

• ~ ~ ;:::.:....

-~-

KIMMERIDGE

~

~

~

| -i:i:i:i:::::".'."• "

-m-

-m- ~ M E M B E ~

"~-

-m-

__

.--,oo,..

< i:!iiiiiiiiiiiiiiii

::::::::::::::::::::::::::::::::::::::::::::: ?

?

CALLOVIAN

Figure

3 Lithostratigraphic framework for the Upper Jurassic of the North Sea (from Johnson and Stewart, 1985)

102 Marine and Petroleum Geology, 1986, Vol 3, May

HALDAGER FM

Fulmar Oil Field: H.D. Johnson et al Contemporary (1970) seismic data indicated that, within Shell/Esso block 30/16, the Auk Horst was a large prominent closure while the Fulmar structure, which was located within the graben, was difficult to see and apparently much smaller (Figure 6). Hence the Auk structure was drilled first and well 30/16-1 discovered the Auk Field. The prominent dipclosure that could be mapped, in the north-eastern corner of Block 30/16, was thought to be at base Cretaceous level and the location of the Fulmar discovery well (30/16-6) was selected to penetrate slightly off-crest of the structure

Fulmar Formation, constitute the 'Fulmar Sands'. The Fulmar and Clyde fields form a west-north-west/ east-south-east trending string of structures that terminates updip with the Auk Field (Figure 4). The Fulmar and Clyde structures climb, and their reservoirs thicken and steepen towards the graben margin. All three structures are thought to be filled to spill-point. The Fulmar reservoir is overpressured by 1100 psi with respect to the normal hydrostatic pressure gradient. As a consequence, initial reservoir pressure at reservoir datum (10500 ft subsea/3200 m) is approx. 5700 psi.

(Figure 7). The domal nature of the Fulmar prospect and the 'pod-like' shape of the underlying sequence suggested that the structure was salt-related. Thus, a crestal well was expected to pass from the Upper Cretaceous Chalk, through a thin Lower Cretaceous sequence, into some 550 ft (168 m) of Upper Jurassic, before reaching the Permian Zechstein salt. A maximum of 300 ft (91 m) of sandstone was expected, based on the initial sand distribution model (Figure 6) and the main risk was considered to be reduced sandstone thickness due to salt uplift (Figure 8a). Well 30/16-6 was spudded on the 20th August, 1975. Upper Cretaceous Chalk was found to rest directly on the Upper Jurassic Kimmeridge Clay Formation with the prognosed Lower Cretaceous being absent (Figure 8b). The well subsequently penetrated a 668 ft (204 m) thick oil column in the upper part of a 990 ft (302 m) gross interval of Upper Jurassic sandstones. The sandstones were fine grained, well sorted, relatively homogeneous and of high reservoir quality (porosity 18-26%; average permeability ca. 1000 mD). A sharp oil-water-contact (OWC) was encountered at 10830 ft subsea (3301 m), coinciding with a horizontal event on contemporary seismic (Figure 7). The oil-bearing section had an average porosity of 24%, an oil saturation of 88% and contained 607 ft (185 m) net oil-bearing sand. Some 1600 ft (488 m) of Triassic red-brown shales and sandstones were subsequently penetrated and the

Exploration/discovery stage Early exploration activity in the CNS concentrated on testing prominent closures associated with two main hydrocarbon plays: (1) Zechstein carbonates and Permian Rotliegendes sandstones situated in horst blocks along the margins of the Mid North Sea High; such as the Auk (Brennand and van Veen, 1975) and Argyll (Pennington, 1975) fields, and (2) Tertiary sandstones overlying late Palaeozoic/early Mesozoic horst blocks within the Central Graben, such as the Montrose (Fowler, 1975) and Forties (Walmsley, 1975) fields, which represent two of the earliest oil discoveries in the UK sector of the North Sea (discovered in 1969 and 1970 respectively). During the early 1970's the pre-Tertiary sequence within the Central Graben was largely unknown and, where it had been penetrated, consisted predominantly of chalk and shale deposits. However, a limited number of wells in the Auk area had suggested the possible presence of an Upper Jurassic sandstone play; including Hamilton Bros' well 30/24-6 (Argyll appraisal) which tested oil at the rate of 1200 bbl (191 m 3) per day from a 24 ft (7 m) sand of Upper Jurassic age (Pennington, 1975). Consequently, a working hypothesis that marine sands were deposited on a coastal shelf in the Auk area supplied from a fluviatile source to the west, was envisaged (Figure 5).

WEST

EAST

0 ft subsea1

i Oft subsea

,72

FULMAR

CLYDE

soo° 1

PERMIAN

.100o0

-~

.

/

~

J

.

~

. _FCI~ALI~ _ I _ J. J. I

~

.

.

~

10OOO-

¸15000 AUK HORST _I_ -I 20000

SOUTHWEST CENTRAL GRABEN

_I_CENTRAL -I GRABEN |.J

2OO00

oI

I

I

I

I

5km J

Figure 4 Geological cross-section through the Auk-Fulmar-Clyde area

Marine and Petroleum Geology, 1986, Vol 3, May

183

Fulmar Oil Field: H.D. Johnson et al

j_ J _ .

FULMAR FIELD

• e-e-o . o e o o • oe • • • )e°o°oeo°eeo

U SAND SUPPLY

_

> 30Oft

AUK HORST

100-300ft O- 1 0 0 f t 0 I

J

20km I

Figure 5 Initial Upper Jurassic sand distribution model

SW

NE AUK

TWT

HORST

CENTRAL G R A B E N

CENTRAL

GRABEN

BOUNDARY FAULT ZONE

(Secs) 2.n TOP CHAL

TOP DEVONIAN LM!

3.

TOP CHALK BASE CHALK

4.

5.

UK-67 UNMIGRATED Figure 6 An early seismic line (UK-67, 1970) across the western margin of the South-West Central Graben indicating the relative size of the Auk and Fulmar structures

104

Marine and Petroleum Geology, 1986, Vol 3, May

Fulmar Oil Field: H.D. Johnson et al Jl

BLOCK 3 0 / 1 1 b AMOCO~ BLOCK 30/16 ~

SHELL/ESSO

I=

SEISMIC LINE U K 4 - 4 7 1 MIGRATED

30/16-6 Proposed Location

TWT 'SECS) 1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5 Figure 7 Pre-discovery seismic line (UK4-471, 1974) across the Fulmar structure. A horizontal event at approximately 3.1 seconds (arrowed) coincides with the OWC encountered by the discovery well 30/16-6

(a) PRE-DRILLING INTERPRETATION N

30/16-6

S

I l I

/

"AsE

(b)

Appraisal stage

.......

Initial appraisal

POST 3 0 / 1 6 - 6 INTERPRETATION 30/16-6 t I I

~

S

I

well was terminated within a Zechstein anhydrite and dolomite sequence. Initial interpretation of the structure was one of a relatively simple, homogeneous sandstone with a single OWC, which was sealed by a drape of Kimmeridge Clay (Figure 9a).

S

JUR SHALE SANDS

Figure 8 Two schematic geological cross-sections (based on seismic line in Figure 7) through the Fulmar Field; (a) pre-30/16-6 interpretation, (b) post-30/16-6 interpretation

An outstep appraisal well (30/16-7) was drilled in 1977, some 2300 ft (700 m) south-west of the discovery well on the apparently steeply dipping western flank. Simultaneously, a 3-D production seismic grid, consisting of 94 lines at 75 m spacing, was shot over the structure to facilitate later field development should the prospect prove to be commercially viable. The well results confirmed the commerciality of the field and encountered an oil-bearing 'Upper Reservoir' some 139 ft (42 m) thick, separated from a waterbearing 'Main Reservoir' by 94 ft (29 m) of shale belonging to the Kimmeridge Clay Formation. An oil-down-to (ODT) 10766 ft subsea (3281 m) coinciding with the base of the 'Upper Reservoir' and a water-upto (WUT) 10860 ft (3310 m) were recognized on electric logs and were consistent with the OWC found in 30/16-6 at 10830 ft subsea (3301 m). Dipmeter data confirmed the presence of steeply dipping beds on the western flank (ca. 25 ° to the south-west) and suggested

Marine and Petroleum Geology, 1986, Vol 3, May

105

Fulmar Oil Field: H.D. Johnson et al

INITIAL

DISCOVERY STAGE (1975)

SW

NE

30 / 16-6

sw

30/16-7

APPRAISAL STAGE

NE

30/16-6

CHALK

LATE CLMMERt~N uNCONFORMITY

J--"

A HUMBER UNCONFORMITY

KIMMERIDGE

~ ~ ~ 4 1 " ~

CLAY T

N,NMER,DGE CLAY

KtMMERtOGE

lOOOmD

GROSS SO?' NOS

~

~990'

TRiASSiC

(a)

..

%o

~."~,.

~

SSIC

TRIASSIC HOMOGENOUS "SAND DOME"

CORED ~INTERVAL

C

~4

4t~'OlO0~" C'~4,p

1ODOreD

CLAY

--

(1977)

?

~

TRIASSIC

--

TWO R E S E R V O I R S

--

? INTERNALLY HETEROGENEOUS

(b)

SECONDARY

SW

APPRAISAL

7

STAGE / FT-4

6

SECONDARY

(1978)

NE

FT-4

SW

7

APPRAISAL STAGE / FT-1

6

FT-1

(1979)

NE

FT-4

*CHALK

~ O

-------T

O w c at ~JOSBO'

lOAD'

tRIASSIc

FT-4 WELL R E S U L T S -----

1¢)

LOW DUALITY UPPER SANDS NON RESERVOIR BASAL SAND CHALK CAPROCK HIGH OWC

i

TRIASSIC

FT-1 WELL RESULTS " INTERCALATING SEQUENCE IN UPPER RESERVOIR - 8ROAD RESERVOIR SUBDIVISION - CONFIRMED DEEP OWC

COREDINTERVAL

P O S S I B L E SEALING FAULTS

DEVELOPMENT

~4"x,o

~"%&~AL

(d)

STAGE (1982-84)

LOCATION MAP

SW

NE

FA-35

FT-3

6

FT-1

FT-4

FA-07

Llr~.

-----.-1 - - ' - " -----

~

RESERVOIR S U B D I V I S I O N CORRELATION CONTROL OF TRUNCATION OF TOP R E S E R V O I R C H A R A C T E N I S A Y I O N OF RESERVOIR UNITS

i

TRIASSIC

i CORED INTERVAL

(e)

Figure 9 Schematic evolution of idealized geological models from discovery to development stage (final reservoir nomenclature given in Figure 26)

106

M a r i n e and P e t r o l e u m G e o l o g y , 1986, Vol 3, M a y

Fulmar Oil Field: H.D. Johnson et al an additional unconformity may be present within the Kimmeridge Clay Formation ('Intra-Humber'). 119 ft (36 m) of net oil-bearing sands were encountered in the 'Upper Reservoir' with an average porosity of 27% and a'n oil saturation of 86%. The well tested 40 ° API gravity oil at 8556 bbl (1360 m 3) per day through a 50/64 in. choke. The results of 30/16-7 added little to the reservoir geological model for the Fulmar Field. There was no evidence to suggest that the east and west flanks were different although the possibility of greater reservoir heterogeneity was evident with the discovery of the two reservoir sand bodies (Figure 9b). Nevertheless, the size of the accumulation was sufficient to allow full field development to proceed. An 'Annex B', outlining the Fulmar Field development plan, was submitted to the UK Department of Energy for approval in November 1977. Although there was no firm proof at this stage that the field extended across the boundary of Shell/Esso's block 30/16, there was adequate evidence from seismic to indicate an extension into block 30/11b to the north held by the Amoco Group. In view of the need for unitization in order to obtain the Secretary of State's approval for development, an interim arrangement was agreed whereby the owners of block 30/11b contributed 15% towards the cost of development. Government approval to the plan was obtained in June 1978.

template well, FT-6, was drilled in the same general area as FT-4, and confirmed both the high OWC and the poorer sand quality on the northern flank. As a result of this secondary appraisal phase, the relatively simple 'sand dome' model, as originally envisaged, required substantial revision in view of the additional stratigraphic, structural and fluid distribution complexities (Figures 9c and d). These would have an important impact on both field development strategy and the first equity redetermination. The fluid contact distribution was particularly difficult to explain since faults were not easy to recognise on seismic. The formation pressure versus depth plot suggests that the oil column is in communication between the 'main field' area and the 'northen block' (Figure 10). However, the water leg within the 'northern block' appears to lie on a separate gradient which is around 80 psi higher than that of the 'main field' (Figure 10); see section 'Field development stage - fluid contacts' for further discussion.

Reservoir geological model During the initial discovery and appraisal stage there was uncertainty concerning the depositional origin of the Fulmar Sands and its relationship with the tectonic

PRESSURE(PSIG) 5500

Secondary appraisal The first stage of the Fulmar development plan was to pre-drill four oil producers from a six slot, subsea template installed on the sea-bed in July 1978. This was to have two principal advantages: (1) early oil production and rapid build-up to plateau production rate, once the main platform was installed and operational, and (2) additional field appraisal prior to platform installation, thereby optimising the location for later platform development wells. Three of the planned template wells, FT-4, FT-2 and FT-1 were drilled and subsequently suspended in the period July 1978 - June 1979 using a semi-submersible rig. The first well, FI'-4, located on the northern flank of the field, encountered several unexpected features (Figure 9c): (1) the OWC was encountered 268 ft (72 m) high to prognosis at 10562 ft subsea (3219 m), (2) the Kimmeridge Clay Formation was absent and the reservoir sands were unconformably overlain by Cretaceous Chalk, and (3) two low quality reservoir intervals were found in the lower and upper parts of the sandstone sequence. FT-2 was drilled to the north-west of the template and confirmed both the extension of the field into block 30/11b and the deeper OWC (10845 ft subsea, 3306 m). A third well, FT-1, was drilled to appraise the south-east flank. This well penetrated a thin interval of Kimmeridge Clay between the Fulmar Formation and the Chalk, whilst the reservoir stratigraphy showed features intermediate between the western flank (30/ 16-6) and the northern flank (FT-4). A wellhead jacket was installed over the subsea template in Summer 1979 and, in the following year, a 'jack-up' rig was used to tie back and surface complete the suspended template wells. In addition, a fourth

]

6000 I

J

i

J

I

10000• 30/16-6

OIL GRAD.~ 0.278 psi/ft~

+ 30/16-7 xFT-1 ® FT-4

10500

owe 10562' X IN FT-4

ZIlL W a

~ =

RECOVEREDOIL

o w c Joe:to'- 48'

11000-

WATERGRAD. k 0.48 psi/ft. ~ (SALINITY-150,000ppm) ~ ~ ® TR

Figure 10 Pressurev e r s u s depth plot illustrating the shallow OWC encounteredby FT-4 and apparent communication within the hydrocarbon column

Marine and Petroleum Geology, 1986, Vol 3, May

107

Fulmar Oil Field: i-I.D. Johnson et al

75

25.

QUARTZ QUARTZARENITE ~

50

^

50 SUBARKOSE

25

IBLITHARENITE LITHIC SUBARKOSE

75

MEMBER I

25~. / M E M B E R II \

.~75 LITHIC ARKOSE

50

2 5 S

"'~A//

"'}~

FELDSPAR

50

FELDSPATHIC LITHARENITE

ROCK FRAGMENTS

75

M E M B E R III Figure 11 Sandstoneclassification(basedon McBride,1963)of the FulmarSands regime of the Central Graben region. Identifying the correct model was important in assisting exploration of the Upper Jurassic sand play in other parts of the CNS basin and in establishing a reservoir model for optimum field development. The exploration and appraisal wells were, therefore, extensively cored (ca. 2200 ft, 670 m recovered) and subjected to detailed sedimentological, diagenetic and palynological analysis.

Reservoir description The Fulmar Sands in the Fulmar Field consist of fine to medium grained, arkosic sands (17--43% feldspar; Figure 11), which are of moderate to good quality with porosity and permeability increasing upwards. In cores they are characterized by three distinctive properties which led to initial uncertainties in interpretation. Firstly, the sands are predominantly massive and primary sedimentary structures are relatively rare. Secondly, soft sediment deformation features (eg. waterescape structures, fluidization pipes and autobrecciated beds) are of wide occurrence and locally abundant. Finally, palaeontological and palynological data are sparse and, apart from demonstrating marine conditions, non-diagnostic. The appraisal stage subsurface facies analysis was, therefore, directed towards establishing: (1) depositional environment, (2) sand body types, (3) reservoir geological model, and (4) origin and controls of porosity-permeability distribution. On this basis the Fulmar reservoir can be subdivided into three main genetically-

108 Marine and Petroleum Geology, 1986, Vol 3, May

distinctive rock units, referred to (approx. from youngest to oldest) as Members I, II and III, which are summarized below.

Member III This member forms the bulk of the Fulmar Formation and comprises three main facies types which together form characteristic, large-scale, coarsening upward sequences up to 600 ft (180 m) thick (Figure 12). The basal part of the sequence (Member lllc) consists of very fine grained, argillaceous and glauconitic sandstones which are strongly bioturbated (including Zoophycus burrows) with a distinctive pelletoidal texture (faecal pellets and Chondrites burrows). Rare cross-lamination occurs in 1-3 cm thick layers but is usually in various stages of biogenic disruption. The very poor reservoir properties (porosity 12-15%; permeability < 1 mD) and low structural position renders this facies largely non-prospective. The sediment textures and biogenic features are indicative of slow deposition in a low-energy, distal offshore, shallow marine environment. The laminated sand layers are interpreted as distal storm deposits (cf. Aigner and Reineck, 1982). The middle part of the sequence (Member IIIb) consist of fine grained, moderately to well. sorted, g e n e r a l l y massive or m o t t l e d sandstones. Xradiographic studies confirm that this lack of structure largely reflects biogenic activity (Figure 13). Clay is mainly restricted to thin laminae and to the walls of

Fulmar Oil Field: H.D. Johnson et al ISOPACH THICKNESS __

(ft)

GENERALISED FACIES INTERPRETATION

0

PROXIMAL SANDS (INNER SHELF/SHOREFACE) ::::-L-.

~

~o ' ~ u ,

MODERATE WAVE ENERGY ENVIRONMENT WITH STORM DEPOSITED GRANULE LAYERS.

i!i!i!}!;!ii i '

1oo

SANDS MEGARIPPLED AND BIOGENICALLY UJ --

~ . - z

=

.

o

o

o

=

o

O Z uJ

e

:-~:?:'-:-:'- 'c, ,., o ~-rm-rr 200

. . . . . . . . . . . ,j ,j*,O . . . . . mZ~ZZZ:Z "

-] ;r;r;:;t;:~;'; - ~

O

O ILl (n U) m <[

(

(')

~

"u

I i::ii~i.."~i: ......: :-:---: ~/ , ~

,Q

REWORKED.

INTERMEDIATE SANDS BIOGENIC REWORKING > SEDIMENTATION RATE.

O. ..... ::-=-=:

300

=

q ,:;i;';i;'!';i;: ~'r,"~ ~ ° v ,,

O Z D Z

I 400

-'1

..

.

.

. . . . . . . . . . . . . .

_ --I

I

II:i@i:i:i:~i

U

I ;~.;1;:;:;:

J

LAMINATED

GRADED BEDS-PROXIMAL

SANDS AND

STORMS LAYERS,

UJ

i ...~,.:;:;.;.;. ~-~.:<.:°:. ,..°.%°,.,~-~

LOCAL PARALLEL

I

I:::~:::: v'~ "~~

,< O 0 ,,.,, LU

DISTAL SANDS (OFFSHORE/SHELF) BIOGENIC REWORKING>

SEDIMENTATION

RATE.

.J

G. :E

OCCASIONAL

CROSS-LAMINATED

DISTAL

<

STORM LAYERS. .

.

~m

'.%t.%,.%'.?.

6OO

Figure

12 I d e a l i z e d l i t h o l o g i c a l p r o f i l e o f M e m b e r

III ( a d a p t e d f r o m J o h n s o n

vertical burrows, and include Ophiomorpha. Physical sedimentary structures are relatively uncommon but include parailel to low-angle lamination, crosslamination and rare graded bedding. The bases of some of these beds contain quartz granules and disseminated shell debris, and are occasionally preferentially cemented (by calcite or dolomite). Reservoir quality is moderate to good (porosity 18-24%; permeability 1001000 mD). These sandstones are transitional between the surrounding deposits (IIIc and Ilia) and a moderate energy, offshore shallow marine environment is inferred in which biogenic reworking was a dominant feature. The nature of the preserved sandstone beds and the shallow water character of the surrounding facies suggest sand emplacement by storm processes. The upper part of the sequence (Member Ilia) is represented by well sorted, mainly fine to medium grained sandstones which are massive, horizontal to low-angle laminated and occasionally cross-bedded. Apart from localized zones of dolomite cementation, this interval contains good reservoir properties (porosity 20-30%; permeability 500--4000 mD). It represents the highest energy part of the sequence and the lack of emergent features suggests depostion in a shallow water, shelf or offshore environment (eg. proximal offshore to nearshore), which was subjected to periodic physical reworking probably by waves and stormgenerated currents (structures indicative of tidal currents are noticeably absent). Members Ilia, IIIb and IIIc together form major, genetically-related, shallow marine (or shelf) regressive

a n d S t e w a r t , 1985)

sequences (Figure 12). The large thicknesses (eg. 200-650 ft, 60-200 m) and amplified nature of these sequences reflects an important tectonic control on sedimentation, which in this case may have been partly salt-related (discussed later).

Member II This member comprises poorly sorted, fine grained, extensively bioturbated, argillaceous sandstones with early diagenetic calcite and silica (chalcedony) cementation derived from disseminated bivalve shells and siliceous sponge remains (Solenasters and acicular spicules) respectively (Figure14). Soft sediment deformation, mainly related to the dewatering of locally overpressured sandstone layers, is also common. Internally these sands display 50-200 ft (15-60 m) thick coarsening upward regressive sequences, followed by 10-50 ft (3-15 m) thick fining upward transgressive sequences. Reservoir quality is generally poor (porosity 1525%; permeability 1-500 mD) and oil saturation low (-50%). Environmentally, these deposits are somewhat analagous to Member IIIb, with bioturbation the dominant depositional process. Member II sandstones are restricted to the upper part of the Fulmar Formation on the northern and eastern flanks of the field, and are laterally equivalent to the Member Ilia sandstones on the western flank of the field.

Member I This interval represents a wedge-shaped sandstone

M a r i n e and P e t r o l e u m G e o l o g y , 1986, Vol 3, M a y

109

Fulmar Oil Field: H.D. Johnson et al 2,025,7 ft 12~025,7 ft

12,033.8 ft

)

Figure 13 Two examples of normal (left plate) and X-ray (right plate) photographs of the 'massive' sandstones of the Fulmar Formation

body on the west flank of the field, and includes the surrounding Kimmeridge Clay Formation. Hence, sandstones of Member I do not constitute a part of the Fulmar Formation (Figure 3). The sandstones are massive, non-bioturbated, graded and parallel laminated. They display excellent reservoir properties (porosity 25-35%; permeability 1-10 D) but contain a volumetrically minor part of the Fulmar reserves (ca. 10%). They are separated from the Fulmar Formation by a 30-40 ft (9-12 m) thick interval of finely laminated, non-bioturbated shales which are typical of the Kimmeridge Clay Formation. These shales are noticeably different from the burrowed shales of the Fulmar Formation and their lateral equivalent, the Heather Formation. This interval is interpreted as representing a sequence of mass-emplaced turbidite sands which were deposited in an anoxic, deeper marine and mainly mud-accumulating environment below storm wave base (part of the regional Kimmeridge Clay event). The textural and mineralogical similarity with the Fulmar Formation indicates continuity of sand supply, with the Auk Platform forming a shelf edge environment.

influenced by both graben tectonics, notably the close proximity of a major graben boundary fault (3-5 km to the west), and also by syn- and post-depositional late Jurassic salt withdrawal. In megatectonic terms, the South-West Central Graben represented a variably subsiding and relatively shallow water marine basin. This basin was flanked to the west by a stable and

Depositional model

Figure 14 Photomicrograph displaying siliceous and calcite biogenic debris typical of the Member II sandstones. Note the large echinoid plate and the circular Solenasters (siliceous sponges)

The Fulmar Sands accumulated in a tectonically active basin (the South-West Central Graben) which was

110

Marine and Petroleum Geology, 1986, Vol 3, May

Fulmar Oil Field: H.D. Johnson et al

AUK PLATFORM

SOUTH WEST CENTRAL GRABEN

CENTRAL GRABEN TROUGH

STABLE SHALLOW PLATFORM

VARIABLE SUBSIDING SHALLOW MARINE BASIN

DEEPER MARINE BASIN

PROGRADING SEQUENCES ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::~.~ ~ . ~ . ~ ! " ' : : : " ' i : : ' : . ' . : ~ : : : : ; ~ ? ~i:~:!':i:~!'~i;!;.!i'~ii """:':~:!::....

THIN (?) REWORKED[ SAND SEQUENCES ]

:

!:~,.......~::'::i::':"".""

.

.

.

.

.

i::iii~i~~ ..........

.-=

"-:'.'~':':::...i:i::::.':'.~'~-'.,. ,:~.'.'.:..".:....!:i::::~:i:!:~:':""'" -~.~,,.~-

.

.

_ _

"1-

o~-'-

::::::::::::::::::::::::::::

AMPLIFIED, REGRESSIVE, SHALLOW MARINE SAND SEQUENCES

[ ? DISTAL SHALLOW MARINE ] AND DEEPER MARINE SEDIMENTS V

HIGH ENERGY SANDS LOW ENERGY BIOTURBATED SANDS

COARSENING UPWARDS SEQUENCE BIOTURBATION

LOW ENERGY BIOTURBATED ARGILLACEOUS SANDS

I

CROSS BEDDING

SILTSTONE AND SHALE Figure 15 Schematic depositional cross-section through the Fulmar Formation in the South-West Central Graben area (from Johnson and Stewart, 1985)

largely non-subsiding area (the Auk Platform), and it deepened eastwards into the Central Graben trough, in which low-energy, deeper water argillaceous sands and muds accumulated (Figure 15). More specific aspects of the Fulmar Sands depositional model are discussed below in terms of (1) depositonal processes, (2) sand supply and environmental models, (3) tectonic influence, and (4) depositional history.

(1) Depositionalprocesses. A notable feature of the Fulmar Formation (sensu stricto) is that biogenic reworking exceeded sedimentation rates in all facies. The resulting poor preservation of primary sedimentary structures prevents precise reconstruction of physical sedimentation processes. However, available data argues against frequent physical reworking (eg. by tidal currents). Instead sand emplacement was apparently periodic and two processes may be envisaged: (1) storm-induced currents, and (2) gravity-driven/turbidity flows. The trace fossil assemblage most closely resembles Skolithus and Cruziana ichnofacies which supports an essentially shallow marine interpretation (eg. Frey and Pemberton, 1984). In such a shallow, shelf-like setting it is considered that storm-induced processes provide the most likely depositional mechanism (Allen, 1982; Johnson and Baldwin, 1985), although turbidity currents may not be totally excluded from such an environment (eg. Walker, 1984, p. 150-

153).

(2)

Sand supply and environmental models.

The most likely source of the texturally mature arkosic sands are nearby Permo-Triassic continental strata (eg.

on the Auk Platform) which contain sandstones with an average 10% more feldspar than the Fulmar Sands and exhibit a similar heavy mineral assemblage. Facies and sequence characteristics suggest that sand could have been supplied to the basin in two depositional models: (1) shoreface model, and (2) shelf model (Figure 16). The shoreface model (Figure 16a and b) implies updip (westward) connection with a contemporaneous, prograding shoreline system, which never fully regressed across the South-West Central Graben (Figure 16b). However, no Fulmar-related shoreline has been positively identified, which may be partly due to poor preservation. The model provides a ready mechanism for supplying the large volumes of Fulmar sand (eg. lateral supply from river mouths/deltas). The shelf model (Figure 16c) represents the lateral migration of a storm-dominated shelf sand sheet complex (cf. Spearing, 1976). Sand supply in this case could reflect the transgressive reworking of nearby preFulmar deposits (eg. by direct or in situ marine reworking of Permo-Triassic deposits) and/or lateral transport across a non-depositional shelf (eg. 10's - 100's km from a contemporary shoreline). The latter model would be partly analogous, although on a larger scale (in terms of sand volumes), to the Cretaceous shelf sand bodies of the Western Interior Basin of North America (eg. Cambell, 1973). The main attraction of the shelf model is that it provides the most satisfactory explanation for the lack of emergent features both within the Fulmar Field and in other occurrences of the Fulmar Formation. Furthermore, the model could account for the mineralogical immaturity of the sandstones since, in the case of a local sand source, transportation distances and reworking would have been restricted.

Marine and Petroleum Geology, 1986, Vol 3, May

111

Fulmar Off Field: ll.D. Johnson et al A. SHOREFACE MODEL (Complete Regression) TIME LINES ~ . : ~ . . . : . . . . .

Sedlmentat

30/11b Coastal plain deposits Shoraface / proximal offshore

-S6oSO'N

.o,,.l

Distal offshore

B. SHOREFACE MODEL (Incomplete Regression)

0

i ,,, Contm~ Inte~l • W d poet~ ToI~Fdmm'

2012'E

Coastal plain deposits Shoreface/proximal offshore Distal offshore

C. SHELF MODEL ( Erosional Transgression) _ F LMAR FIELD

I,...°

GRAABEN]SYNDEPOSITIONALLOW SYNDEPOSITIONAL] RGIN[(eg.llalt-lnduc~edhollow)l HIGH • ACT~AULT ZONE] 1 roximal offshore Distal offshore

Figure 16 Palaeodepositional models for the Fulmar Formation; (a) shoreface model showing complete regression (sedimentation > subsidence), (b) shoreface model showing incomplete regression (sedimentation - subsidence), and (c) shelf model showing erosional transgression (sedimentation = subsidence).

(3) Tectonic influence. The most important effect of tectonics influencing sedimentation is seen in the thick, amplified nature of the large-scale, coarsening upward sequences (ie. individual sequences approx. 200-600 ft, 60-180 m thick) and in the intense fracturing of the reservoir sandstones on the western flank of the field adjacent to the Auk Horst boundary fault. The coarsening upward sequences reflect prolonged periods in which subsidence and sedimentation rates were in balance. The overall tendency, however, was for sedimentation rates to gradually exceed subsidence rates resulting in the development of the coarsening/shallowing upward sequences. Fining upward, transgressive/ deepening sequences occur where the Fulmar Formation passes transitionally into the Kimmeridge Clay. However, the Fulmar/Kimmeridge contact is often very

112

Marine and Petroleum Geology, 1986, Vol 3, May

Figure 17 Fulmar Formation isochore map illustrating the sym-

metrical 'pod-like' nature of the deposit

abrupt in the Fulmar Field, notably on the western flank, which indicates a sudden change from shallow to deep water conditions at the end of Fulmar Formation times. The relative interplay of graben and salt tectonics on sedimentation is uncertain. Fulmar sand thickness and reservoir quality are best developed close to the Auk Horst boundary fault, while thinner and more distal facies increase to the east. However, the thickness of the Fulmar Sands within the Fulmar Field depicts a 'pod-shaped' geometry (Figure 17). Within the 'pod' the thickest and most complete facies sequences are located in the centre of the structure while increasingly thinner and more incomplete (amalgamated) facies sequences are found towards the western flank (eg. Figure 18). This 'pod-shaped' geometry is similar, although of a smaller size, to the widespread and larger 'pods' of Triassic sediment, which are believed to reflect the infill of salt-related primary rim synclines (or 'turtle-back' structures). Thickness changes within the Fulmar Field sand 'pod' are unrelated to any mapped faults, which is considered to preclude any growth fault-related mechanism (cf. Gibbs, 1984). An alternative to the latter model is that the Fulmar Field, and perhaps other occurences of Upper Jurassic 'podshaped' sand accumulations (eg. Clyde Field), reflect the syn-depositional infill of localised hollows resulting from late stage salt withdrawal (eg. a type of secondary rim syncline). Although the generating salt has subsequently migrated away from the Fulmar area (Taylor, 1980), major salt diapirs are found within the axial part of the Central Graben (Figure 2). The abundance of soft sediment deformation structures supports the earlier conclusion of syn- and early post-depositional tectonic activity on the Fulmar sand 'pod', whatever the precise mechanism. (4) Depositional history. Three main phases of deposition account for the vertical and lateral distribu-

Fulmar Oil Field: H.D. Johnson et al

PHASE 11]" SW

NE

30/16-7

ERO=O.

,,

TRIAS. /~ +

+

30/16-6

I

FT-1

I

~ O o O o O o ° o ° ~ ~ ~

" +/~

FT-4

I

FA-12

I

_,,-

..... -

I .

.

.

~ ~ ' : ' : ' : ' ;

:::::::::::::::::::::::::::::::::::::

.

.

.

.

= . . . . ' . = = = = ' = = : ; . ' = = = ' : " = = = =

.

.

.

.

. . ...........

.

.

.

.

4-

4-

'

..,iiiii

.

-J~-~- `~d..~.~...°.~.~.~.~.....~`~..~...~..~.~.:~...::::°~°:~:~:~:~:~;:':~:~:~;~;~:~:~:~:;:::::::::~:~;~:;~

0

500

1000m

I

I

I

I/

-

RAPID BASIN DEEPENING/DEPOSITION KIMMERIDGE CLAY

-

REACTIVATION OF AUK HORST BOUNDARY FAULT

-

EMPLACEMENT OF MASS FLOW SANDS

/

PHASE 1]" NE

SW

30/16-7

30/16-6

FT-1

FT-4

FA-12

EROSION !

TRIAS,

+

+

....

• ",',"

, •

,,,, ,,

,'.'.'.'-'-'.'*'.

." ". . . . . . . . .

:::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::~:~:~:~:~:~:!:!$i:i:i:i:~:~:~:~:~:~:~:~:~:!:i:i:~:~:~:~:~:~:~:~:~:~:i:i:i:i¢~:~:

, , , .,., =.- ~........................... ~..--;-. ; ,

.o°o.o...°.o.o.o.

...,

. . . . .

. . . . . .

. , , = , , ,

. . . .

~

. . . . . . .

~ ~ : ~: : : : : :,11,:, : , ' .: ., : .: : ,: ~: . :. ' ~. ' , ~ ~ :

-,-,-,.,.,.,-,-,.,.,,,.,,,,,,,,,,,,,, , ,,,,,,, ,,,,,,,, ,,,,.,,

.o_.-..o.---: •.

.

.

.

.

............................. .

.

.

.

.

o,,oooooooo,,oo,,ooo,

oo

o,o ,o

=~,-,,,-m============........ ========~,','~" ====== ===================================== ======================================= ................. .= ........~

0

500

I

~

1000 m I

- CONTINUED SHALLOW MARINE SAND DEPOSITION - RAPID EASTWARD DETERIORATION IN SAND QUALITY - INTERFINGERING OF HIGH AND LOW QUALITY SANDS

PHASE I SW

NE

30/16-7

30/16-6

FT-1

FT-4

FA-12

EROSION

+TRIAS.~. +

/

0

500

I

-

1000

m

I

SHALLOW MARINE DEPOSITION

- COARSENING -

I

/SHOALING

UPWARD,

AMPLIFIED

SEQUENCES

PROLONGED BALANCE BETWEEN SEDIMENTATION

& SUBSIDENCE

Figure 18 Depositional evolution of the Fulmar Sands in the Fulmar Field

Marine and Petroleum

Geology,

1986, V o l 3, M a y

113

Fulmar Oil Field: H.D. Johnson et al tion of the rock units within the Fulmar Field (Figure

18): Phase 1 (Members IIIc ~ IIIb --~ Ilia lower) reflects the initial progradation of a slowly deposited, stormdominated shallow marine sand complex. The thickest and most complete sequence is developed in the axial part of the field (Figure 18). The argillaceous, nonreservoir sands of Member IIIc are also restricted to the central part of the Fulmar Field, which supports the inference that this was also the deepest part of the depositional pod. This sequence looses its definition in the marginal part of the pod where it amalgamates into a composite unit. Phase I1 (Members Ilia upper ~ II) marks a substantial vertical and lateral change in sand type and reservoir quality (Figure 18). The main change is in the northern and eastern part of the field where the Phase I sequence is abruptly overlain by shale and argillaceous

and cemented sands (Member II). Cores demonstrate that these low quality reservoir sands interfinger in the centre of the field with typical Member IIIa sands, and are replaced entirely by Member III sands on the western flank. This sequence reflects a renewed period of rapid basin deepening, which was again located in the central part of the pod, and was probably tectonically-induced. It was also accompanied by the onset of deposition of siliceous sponge remains, which is interpreted as a semi-regional organic bloom. The onset of Phase II (notably the onset of Member II deposition) provides an important intra-reservoir marker, which can be correlated with well logs in the central and eastern parts of the field. Phase 111 (Member I) marks the widespread phase of basin deepening at the onset of Kimmeridge Clay deposition. This was an abrupt event in the Fulmar Field, probably enhanced by movement along the Auk

~j:::

t .....

!i:: ~!iiZ;: :!Z z::'~

~7

E'2

N N~

N

N gz

N

Figure 19 Deformed calcite (a) and silica (b, c) concretions from Member II of the Fulmar Formation

114

Marine and Petroleum Geology, 1986, Vol 3, May

Fulmar Oil Field: H.D. Johnson et al Horst boundary fault. Continued transport of sands from the shallow Auk Platform is suggested by the periodic emplacement of small turbidite sand bodies within the Kimmeridge Clay Formation. The restriction of these sands to the western flank of the field suggests that the main sand 'pod' was already exerting a structural influence on deposition (Figure 18).

Soft sediment deformation Soft sediment deformation structures are widespread in the Fulmar Field, and are attributed to syn- and early post-depositional dewatering and associated sediment re-consolidation. There are two main groups of structures reflecting two contrasting types of host lithology. The first group of soft sediment deformation structures are associated with relatively homogeneous, massive sands, and include (1) shear zones, (2) narrow (mm-cm scale), steeply inclined fractures (commonly dolomite cemented), (3) buckled foresets/lamination, (4) vertical fluidization pipes, (5) massive, dewatered intervals, and (6) loading structures (eg. Member I turbidites). These structures are largely restricted to the good quality reservoir sands of Members I and III. The steeply dipping fractures are abundant on the western flank of the field where the common occurrence of alutriated clay and dolomite cementation causes these fractures to form localized baffles to horizontal fluid flow (measured horizontal permeabilities < 1 mD). However, their effect on long term reservoir performance has not been established and none of the mappable faults are sealing. The second group of soft sediment deformation structures are associated with heterogeneous, argillaceous and early cemented sandstones and comprise (1) compacted and partly sheared clay laminae and clay-lined burrows (eg. Ophiomorpha - type, (2) fluidization pipes, (3) rotated and displaced calcite concretions (Figure 19a), (4) narrow, clay-lined fractures, (5) in situ brecciation of early silica (chalcedony) cemented beds (Figure 19b and c), and (6) cementfilled (eg. silica) veins. These features are restricted to the poor quality sands of Member II. The apparent lack of significant lateral movement (eg. silica brecciated beds can be reconstituted into their original beds) and the disturbance of cemented intervals indicates (1) that deformation was effectively in situ, and (2) that the silica and calcite cementation events were very early and prior to significant burial. Both groups of structures are probably related to the same mechanisms, the different responses reflecting the contrasting mechanical rock properties. The deformation is thought to have been due to dewatering as a result of the periodic application of external shocks, such as earthquakes, fault movement or salt withdrawal. The frequency of these deformation features is an indication of the tectonic instability of the Fulmar area during the late Jurassic. Furthermore, the decrease in deformation features in the Clyde area, and the increased frequency of fractures along the western flank of Fulmar, may indicate some tectonic influence of the nearby Auk Horst boundary fault, in additon to late stage salt withdrawal and partial collapse of the flanks of the sand dome. This deformation of the Fulmar Sands was probably occurring throughout the early burial history of the Fulmar

Field. As such it is more indicative of the tectonic setting of the basirl/'sand pod' rather than anything inherent in the depositional environment.

Diagenetic history The Fulmar Sands have mainly undergone environment-related and early burial diagenesis, and are currently at their maximum depth of burial (10000-11000 ft, 3050-3350 m). The dominant authigenic minerals (based on point counting of around 160 thin sections) are quartz overgrowths (mean = 0.75%, range 0.5-2% bulk volume), feldspar overgrowths (1.15%, 0.5-3%, bv), silica/chalcedony (4.3%, 0-25% bv), calcite (6.2%, 0-62% bv), dolomite (3.5%, 3-49% by), pyrite (1.3%, 0.7% bv), and authigenic illite and chlorite. Authigenic kaolinite is virtually absent from the Fulmar Field suggesting that acid meteoric waters never penetrated the reservoir. Environment-related diagenesis is represented by an important phase of authigenic mineral growth during the initial burial period, when pore waters of marine salinity and faunal remains exerted a strong environmental influence. Macroscopic structures demonstrate that both silica and calcite cementation occurred at very shallow burial depths and prior to dewatering-induced deformation. Textural relationships also indicate that the majority of the quartz and feldspar overgrowths occurred during the same period. The silica cement consists of fibrous chalcedony which is intimately associated with rich concentrations of siliceous sponge remains (mainly spherical Solenasters). The chalcedony cement is interpreted as representing the breakdown of the amorphous silica tests, development of over saturated silica-rich solutions, precipitation of a silica gel and subsequent transformation into chalcedony (Siever, 1962). The result is a cement with a high micro-porosity (micropores a few iam in diameter), but one which is largely ineffective. The localized nature of this process is confirmed by its patchy distibution and close association between cement and primary sponge remains. The second main phase of authigenesis was probably the precipitation of overgrowths, beginning with potassium feldspar and closely followed by quartz overgrowths. This was followed by concretionary calcite in which iron-rich sparitic crystals replace framework grains as well as quartz and feldspar overgrowths. The carbonate was probably derived from concentrations of calcareous shell debris. This environment-related diagenetic phase was accompanied by periods of rapid dewatering and reconsolidation of the sediment, including some disruption of all these early cements (as discussed earlier). Early burial diagenesis is mainly characterized by widespread dolomite cementation, which occurs as intergranular, isolated rhombs and in clusters of coalesced rhombs. The crystals are frequently zoned, with iron-free cores and iron-rich outer rims. Dolomite cement is most abundant in intervals rich in detrital clay and with strong bioturbation, and also along some fracture zones. The necessary supply of Mg 2÷ may have been derived from one or more of the following; (1) from the decomposition of illitic clays (Heald and Baker, 1979), (2) from the decomposition of organic matter (Gebelein and Hoffman, 1973), (3)

Marine and Petroleum Geology, 1986, Vol 3, May

115

Fulmar Oil Field: H.D. Johnson et al NE

SW

3 0 / 1I 6 - 7

30/16-6

FT- 1

I

FT-4

I

FA- 12

I

I

2~ "17" ::::.

~

..

..

....................

::~:~:i....

,............

.:::::.

--::;"

::::::."

.:::::."

.:

~r:

..... ..;:::;:.:.-

::!? ?::" ..:....."

.: iii::" .:.:..

.:ii!;r: :.:.:.:.;."

..::!~!~i::" ..;:;:;:;:."

. :~ ~::"

::::~::::."

:iii::"

..::::::::.-

.::~ ::" .::~:~:~::."

.:!~: .;.

•,, °.,.,.,.,., .;:::.. :~

.:::::r

.::::~:: ,,',,,~..::::.-

.:::::."

::: ::

.. ::~:: S~i~::~::i~::~ ~~ , ::~i;::~i:.:.;~:::~i~::".: ~i :.~;~~~::,:~i~i ::i~:.~::: ~~::"..::~:~:~:~:~ .................. :....:.... ......................... .+...:::::::::...::+:.:: .......

TRIASSIC

~

CLEAN SANDS(< 1.5% CLAY,'~O.5-2% QUARTZ ~ OVERGROWTH, 0.5-3% FELDSPAR OVERGROWTH)

-~ABUNDANT

DOLOMITE

SILICA (CHALCEDONY) CEMENT & ASSOCIATED SPONGE REMAINS (Av.4.3%,RANGE 0-25%) MODERATE INTERSTITIAL CLAY (= MEDIUM GRAINED,MODERATELY SORTEO SANDSTONES)

CEMENT

(Av.3.5-10%,RANGE-~3-49%) -

~

CALCITE

ABUNDANT INTERSTITIAL CLAY (=RNE GRAINED ARGILLACEOUS SANDSTONES)

CONCRETIONS

(Av.6.2%,RANGE 0-62%1

Figure 20 Schematic distribution of the main diagenetic cements and clay minerals

Textures suggestive of secondary porosity occur throughout the sandstones of the Fulmar Formation. Two phases of leaching are evident; (1) early leaching of shell and sponge debris, and (2) a late phase of dissolution of silicates and possibly early carbonates. A mean of 4% intra-granular secondary porosity has been measured. No estimate of inter-granular secondary porosity has been made. NE

from feldspar-forming brines, and (4) from saline solutions derived from the underlying Permian and Triassic evaporites. Other aspects of burial diagenesis include compaction, pyrite cementation and clay mineral authigenesis (eg. illitized feldspars and chloritized detrital iron-rich clay particles and pellets, such as chamosite and/or glauconite) (Figure 20). SW 30 / 1 6 - 7 I

-I.

30/16-6 J.

I

FT- 1 J-

FT-4

I T

"

I _

:°:.:,.°=~:,:-,..--~~!:.:.:.:.:........ • .-............. ~ ~ i : , : ~ . .........:.:.:.:.:.....

_

-

_

-

~

....

• ....

VERY GOOD 1 ~ 2 5 - 3 5 % K,~ 1100-10000 mD

POOR ~*'15-25% K ~- 1 - 500 mD

GOOD jll'~ 20-30% K'~, 500-4OOOmD

K ~
MODERATE 1~,18 - 24% K ~,100- 1000mD

Figure 21 Reservoir quality distribution through the Fulmar Field

Marine and Petroleum Geology, 1986, Vol 3, May

_

±

.. . ' " -

116

FA- 12

I

~ " 12-18%

Fulmar Oil Field: H.D. Johnson et al

Reservoir quafity distribution Reservoir quality distribution in the Fulmar Field is mainly controlled by primary depositional textures, with grain size, clay content and sorting most responsible for permeability distribution. Diagenetic minerals, particularly dolomite cement, all reduce porosity (except microporous silica cement). However, the main effect of diagenesis has been to effectively enhance primary depositional variations in porosity and permeability (Figure21).

Structure

Structural description of the Fulmar Field The Fulmar structure is a domal anticline with pronounced flanks dipping to the south-west at ca. 25 °, to the south at ca. 12° , and to the east at ca. 8° (Figures22 and 23). It is conformably overlain on the western flank by the Kimmeridge Clay Formation, although some truncation of the reservoir sandstones, associated with possible 'Intra-Humber unconformaties', may locally be present. The structural configuration of the northern and north-eastern flanks has been substantially modified by erosion and the dip of ca. 15° corresponds to the Late Cimmerian unconformity surface. Since the underlying Fulmar Formation has a dip of only ca. 7° to the north and north-east, progressive truncation of successive reservoir units consequently occurs in this area of the field (Figure 23). The unconformity is thought to have been submarine because authigenic kaolinite is virtually absent from the Fulmar Field

N

suggesting that acid meteoric waters have never penetrated the reservoir (the abundant feldspars are generally fresh and show little sign of alteration). The field is transected by a series of north-west/ south-east trending, eastward-dipping normal faults, which are probably .related to the Auk Horst/Central Graben boundary fault system. However, a number of similar trending, antithetic faults to the former are present and clearly define the western flank and the Kimmeridge Clay 'basin' to the west (Figure 23). The recognition of faults from seismic is difficult since faulting pre-dates the formation of the Late Cimmerian unconformity and, consequently, no fault throw can be observed at base Cretaceous level. Seismic resolution within the Jurassic - Triassic section is also poor and the fault pattern is essentially derived by extrapolating faults only recognisable at Zechstein level. More detailed fault control has now been obtained from well data but the recognition of faults from well-log correlation is also extremely difficult.

Structural evolution of the Fulmar Field The most obvious structural element that is potentially responsible for producing the Fulmar structure is halfgraben tectonism associated with the subsidence of the Central Graben, which occurred throughout the Mesozoic. Such a mechanism has been invoked for. the formation of the Brae Field structure on the western margin of the Viking Graben where sands of a similar Upper Jurassic age are believed to have accumulated in a deep water, marine environment (Stow et al, 1982). However, the characteristic thickening towards the

SANDS

ABSENT

A07 -~

30/1 lb Amoco

....

OWC.. 10560

30/12b Amoco

56030'N

30/17b Britoil

30/16 Shell/Esso A2i

LEGEND

Gas 011 []

Fulmar Alpha Platform

•

OII Producer Gas

"~Water

Injector Injector

- ~ Plugged & Abandoned

GOC ~ 1 / 1 / 6 5 ca.lO 100 ft.ss

A : Wells from P l a t f o r m T : Wells from Template 0 lkm

I I I Contour Interval = 500 f t

2o12'E

Figure 22 T o p F u l m a r F o r m a t i o n s t r u c t u r e m a p

Marine and Petroleum Geology, 1986, Vol 3, May

117

.<

CO (33 < O LO

O O t~ -<

3 c~ ¢D

¢-

-O

¢0

n~

-t. 0o

o

....

I

30/16-7 proj. 140m HW

FT-31

30/ 16-6

\

::::::.

FA-13u~3:

l

~ FA-13

P r o j . 3 5 0 m SSE

::::: ~

,

~

FA-26

FULMAR A L P H A P L A T F O R M

Figure 23 Structural cross-section apd log correlation panel through the Fulmar Field

i

SW

12OOO-

11000-

10000-

9000-

SW

~

;

FA-26 .

\

~

.

FA-10 proj. 14om HNE

.

.

.

*

.

FA-IO

TRIAS

==

i

L 1OOO'

500'

• }0'

~

=

,

FA-O9

No Horizontal Scale Implied

1

\

FA-O9

,

R Y

"1"

NE

12000

F0°°°

NE

n~

~'

Fulmar Oil Fie~d: H.D. Johnson et al STAGE

STAGE

1

SW

30/16-7

30/16-6

I

FT4

I

NE

I

~

2

SW

30/16-7

SEA

30116-6

FT4

I

I

I

LEVEL

NE

JURASSIC

\

\ --

UPPER JURASSIC REACTIVATION OF PRIMARY TRIASSIC RIM SYNCUNE

--

CONTINUING SALT WITHDRAWAL

--

DEPOSITION OF LENTICULAR, SHALLOW MARINE SANDSTONE COMPLEX

--

INITIAL GROUNDING OF PRIMARY RIM SYNCLINE ON ZECHSTEIN CARBONATE

(SECONDARY RIM SYNCLINE)

--

INITIAL INVERSION OF RIM SYNCLINES

STAGE

STAGE

3

SW

30116-7

I

30/16-6

I

FT4

4

SW

NE

30/16-7

I

I

30/16 -6

I

FT4

NE

I

JURASSIC

\ --

CONTINUEDGROUNDINGAND INVERSIONOF RIM SYNCLINES

--

--

REACTIVATION OF ONABEN MARGIN FAULT

--ONLAP

EROSIONAND DEVELOPMENTOF LATE CIMkF-.JRIANUNCONFORMITY

--

INTERNAL SLIDING/CREEPING AND SOFT SEDIMENT DEFORMATION

- - F U R T H E R SURIAL DURING TERTIARY

OF CRETACEOUS SEDIMENTS

Figure 24 Schematic structural evolution of the Fulmar Field

Graben Boundary fault which would be expected if half-graben tectonism exclusively controlled sedimentation is not seen within the main body of sediment in the Fulmar Field. Moreover, inspection of seismic lines shot over the field, perpendicular to the graben axis reveal a characteristic lensoid shape to the package of Triassic and Upper Jurassic Fulmar sediments, overlain in the south-western area of the field by a wedge of Kimmeridge Clay. This lensoid shape has also been reported from the adjacent Clyde Field (Gibbs, 1984). The lensoid shape has obviously been modified, to some extent, by erosion of the Fulmar Formation on the northern and north-eastern flanks. However, inspection of the Fulmar Formation gross isochore map, derived from 16 'non-eroded' wells (Figure 17), also reveals a broadly symmetrical 'pod' with a maximum thickness of over 1000 ft (300 m) in the depocentre thinning to less than 500 ft (150 m) at the margins. This leads to our proposal that the Fulmar structure is largely the product of salt withdrawal with some modification due to half-graben tectonism. The structural evolution consists of four main stages which are summarized below (Figure 24):

Stage I Triassic paralic sediments were initially deposited within halokinetically-controlled basins and unconformably overlie salts of Zechstein age. Such 'pods' of sediment increased in size as further salt withdrawal and solution continued, resulting in the production of a primary rim

syncline. Reactivation of the Triassic primary rim syncline during the late Jurassic resulted in the formation of a secondary rim syncline with deposition of lenticular, shallow marine sandstones.

Stage 2 Continued salt withdrawal led to grounding of the primary rim syncline on immoveable Zechstein carbonates and inversion of the rim synclines commenced.

Stage 3 Further salt withdrawal permitted continued grounding and rim syncline inversion, with the relatively unconsolidated mass of Upper Jurassic sands subjected to internal soft sediment deformation. Sands subjected to early diagenetic cementation (i.e. Member II) were susceptible to more brittle fracturing.

Stage 4 Reactivation of the Auk Horst Boundary Fault created a deep water basinal environment, adjacent to the Auk Platform, in which both shales and organic rich claystones of the Kimmeridge Clay Formation accumulated. Periodic tectonic activity caused mass influx of arenaceous sediment into the basin producing the sands of Member I (Kimmeridge Sand Member). Subsequent erosion, associated with the development of the Late Cimmerian Unconformity, modified the structure which remained a positive feature until late Cretaceous times. During the Maastrichtian, the Chalk Sea trans-

Marine and Petroleum Geology, 1986, Vol 3, May

119

Fulmar Oil Field: H.D. Johnson et al NE

SW ---- CLYDE

FIELD

LATE CRETACEOUS

TRIASSIC

EARLY CRETACEOUS

ZECHSTEIN SALT

KIMMERIDGE CLAY FM

ROTLIEGEND & DEVONIAN

FULMAR FM

BASEMENT

0 I

5km

,

I

Figure 25 'Shallow listric faulting/detachment sliding' model proposed for the Clyde Field (adapted from Gibbs, 1984)

gressed over the structure resulting in the onlapping of the Chalk against Upper Jurassic sediments. Continued burial, throughout the Tertiary, and differential compaction around the sand dome, enhanced the appearance of the structure. This interpretation contrasts with a structural model proposed for the nearby Clyde Field (with inferred application to the Fulmar Field), which invokes a combination of half-graben tectonism and shallow listric faulting with detachment and sliding (Gibbs, 1984; Figure 25). The latter interpretation is difficult to disprove since the recognition of any faults from seismic, either of a deep-seated or a shallow, listric nature, is particularly tenuous beneath the base Cretaceous seismic event in the Fulmar-Clyde area.

~z

u.

[

.ESERVO,.

•

CLATURE

]'

RIBBLE

--

AVON

i

0

CHALK I L~ ~

.:,:,:,:,:,:,:,:.:,~

z~

:,:,:,:,:,:,:,,,:,:,, i!~.~i:~i~F~!l..".:~ti~i~iit~::.'~

111a

In order to aid field development and discussions with unit participants and management, a standard reservoir unit nomenclature has been introduced based upon the lithofacies subdivision described earlier and using the word 'Fulmar' as a 6 letter mnemonic (Figure 26). The names of British rivers have been used. The west flank can be divided from core and log data into six broad reservoir units and the east flank into four units. The interfingering relationship between the upper Member IIIa sands and the poorer quality Member II sands has been honoured with the latter referred to as the Clyde Unit, because of its similarity with the uppermost reservoir sand in the Clyde Field. The thin shale

120 Marine and Petroleum Geology, 1986, Vol 3, May

"~-~

..SE, :::::::::::::::::::::

u

Field development stage Reservoir subdivision and correlation

i| 0

I

i:!ii::::::i:i::: = iii::iiiiiiiii!i! ii

< E I,-

TRIASSIC

< I,-

Figure 26 Reservoir unit nomenclature for the Fulmar Field (see Figure 21 for reservoir quality)

Fulmar Oil Field: H.D. Johnson et al 1.9 FDC 2;7 PERMEABILITYPROFILE 46 CNL 0 ,NO "--~K~ ..... " I

GRAIN ,SIZE ,0

GR

•

~?o

m., .nd

~

o =

I,,,,,,,

Feet

O

>

,_ , °oo

,vss

o .

' 9800

o

o A

.10000 •10200 ' 10400 ' 10600 -"

,10800

owc

//

i' 1

•1 1 0 0 0

g=

TRIASSIC

.11200

-t

,11.400

TYPE LOG - WEST

FLANK FDC

1.9 0

8= Oo= t~

GR

1

GRAIN SIZE m u d ~sand 0.2 I_ ,',,, ._ ,,',_ '

200 I

45

IND

PERMEABILITYPROFILE!

2.7

CNL

0

"~

2000 ,

>

o

in,- 0

.L 1

.I] I.__~

TVSS

z¢

o ,-

10600 .:.:.:.:.:.~: ,...............,

10700

i i !ilili i i!i!.

10800

~%iiii

0 i

>,

0wc

-

,,

10900 .1

i!i!i !~ilil

-11000

I'-

0

i i!!!ii i i i ,................, :.:.:.:.:.:.:.

! ~ i i i t 7

i

~

.111oo .112oo

~ii i i i i i i ~::::::::::::::

~iiiiiiii

i~

2

I¢1

-~--~

~

.~.~~

" 11300

:::::::::::::::

ii~iiiiiii .I,~

--

J-

-r"

11400

~

,~

_ "It"

iiiiiiiiiiiiii

I

iiiiiiiii!iii iii~i!!]i:

I-

iii!i!ii!ii

TYPE LOG - EAST FLANK Figure

!:]:!S[:~:~:i

iiiiiiii~

27 Reservoir 'type' logs for the Fulmar Field illustrating the contrasting sequences between the west and east flanks

Marine and Petroleum

Geology,

1986, Vol 3, M a y

121

Fulmar Oil Field: ll.D. Johnson et al development separating the Member I (Ribble) sands from the 'main reservoir' is referred to as the Avon Unit. The Ribble and Avon Units, however, belong to the Kimmeridge Clay Formation and only the units of the 'main reservoir' constitute the Fulmar Formation. The above reservoir subdivision has provided a basis for intra-field correlation although this is often problematical since reservoir unit boundaries are generally gradational and can be indistinct (Figure 23). Reservoir correlation, in the absence of core control, is based upon log response, and since the gamma ray log lacks character due to the high concentration of potassium feldspar within the sands, correlation is achieved by the use of the neutron porosity and density log responses. There is a distinct contrast in log character between wells drilled on the eastern and western flanks (see type logs, Figure 27). However, the broad coarseningupward character of the sequence is very evident, in both cases, from the density log response. The Forth Unit is absent through non-deposition on the western flank but is conspicuous by the 'negative' (i.e. neutron to left of density) neutron porosity/density log separation, where it is developed on the eastern flank (Figure

27). Development drilling The shape of the Fulmar Field lends itself to development from one centrally-located, 36-slot platform which was installed in 1980. Flowlines were installed from the wellhead jacket to the platform so that the pre-drilled template wells could be brought into production as soon as the processing facilities on the main platform were operational. Oil production from the Fulmar Field commenced in February 1982. Oil is evacuated from the platform to a nearby Floating Storage Unit (FSU), a converted tanker permanently attached to a Single Anchor Leg Mooring (SALM), from where the crude is transferred to 'shuttle' tankers. The problems of handling produced solution gas from the crude (GOR = 650 scf/stb) was recognised at an early stage. The UK Department of Energy imposes stringent flaring restrictions, in order to promote energy conservation, and since there was no gas exporting pipeline available, at the time, in this area of the North Sea, all gas surplus to platform requirements had to be re-injected into the reservoir. A Fulmar gas pipeline is currently under construction and is scheduled to become operational in 1986. To date, some 18 wells have been drilled and completed from the platform, in addition to the 4 oil producers drilled through the subsea template (Figure 22). A further oil producer (FT-3) was drilled from the template using a 'jack-up' rig in 1983. The first development well to be drilled from the platform was allocated as a gas injection well (FA-16), in order to minimize gas flaring and maximize oil production during the 'buildup' phase. The second development well, a stand-by gas injector (FA-25), was drilled as an insurance against gas flaring whenever the primary gas injector is unavailable due to operational reasons. FA-25 is used as an oil producer whenever possible. Regional data suggested that natural aquifer influx would be inadequate to maintain prolonged production and, consequently, seawater injection is used as a

122

Marine and Petroleum Geology, 1986, Vol 3, May

secondary recovery mechanism and for pressure maintenance. Recovery factors in the range of 45-55% are reasonably expected. A total of 10 water injectors and 17-20 oil producers are expected to adequately drain the field. Reservoir performance indicated at an early stage that natural aquifer support was minimal and a reservoir pressure versus voidage plot showed a classic, linear decline (Figure 28). In order to maintain reservoir pressure, drilling of water injection wells was given priority and reservoir pressure has risen from 4600 psi (July 1983) to 4900 psi (Sept. 1984). Water injection wells have been located peripherally around the field in positions where the well is expected to penetrate the intended injection zone just below the OWC. Oil wells have been positioned so that initial completion intervals are low enough to avoid gas breakthrough from the expanding gas-cap and high enough to delay, for as long as possible, water influx. They are also positioned so that they can be recompleted upwards to avoid the advancing OWC after the secondary gas-cap has been partially or totally removed. 10 water injectors and 12 oil producers have now been drilled and oil production is at plateau rate of 165,000 barrels per day (Figure 28). Moreover, no alteration to the reservoir geological model has been required and the well results, so far, have only provided additional refinement of the model (Figure 9e). Production, to date, has centred around the depletion of the Mersey, Lydell and Usk reservoir units (Figure 26). This has been achieved by 'up-structure' depletion and 'down-structure' injection into the objective zone. A crestal oil producer, FA-13 (Figure 22), drilled in mid 1984, encountered the secondary gas cap and will be used to monitor the downward encroachment of the gas-oil contact (GOC). In January 1985, the GOC was at ca. 10100 ft subsea (3078 m) (Figure 22). The well will be used as a gas producer when the Fulmar gas sales line becomes operational. The Ribble sands within the Kimmeridge Clay Formation, despite containing some 10% of the reserves in place, have not been developed and it is proposed to re-complete existing wells on this reservoir unit later in the field's life. Formation pressure tests within the Ribble sands have indicated limited pressure communication with the 'main reservoir' probably via fault juxtaposition. Perhaps, more significantly, pressure measurements indicate the field is being drained as one unit and that no isolated, fault-bounded blocks, appear to exist.

Fluid contacts The apparent lack of separate drainage compartments within the field poses intriguing questions regarding the origin and mechanism to account for the fluid contact distribution and a number of solutions have been proposed to account for the phenomenon, including capillary effects, stratigraphic trapping elements, sealing/partially sealing faults and perched water tables. T h e latter mechanism is, however, preferred and outlined below. During oil migration into the structure, 'pockets' of formation water are believed to have become entrapped within structural depressions (due to folding and/or

Fulmar Oil Fie/d: H.D. Johnson et al RES.PRESS. PSI

GROSS LIQUID

~

6000XX 5500-

X XXX X

5000-

X

X X

X X X

X

4500

X X

X

X

GAS INJ.

WATER INJ.

X

X

AV. MONTHLY MRB/DAY

OIL RATE BOPD

300~

250200150-

OIL PROD. _..

• 180800 .135600

R~~ ' L

-90400

100.45200

500

I I I I I I I I I I l ] l l l l 1982

t i t l t t i t i l l i l i l i l l ~ I 1983

0

1984

Figure 28 Reservoirperformance profile, Fulmar Field faulting) at the base of the reservoir, partially assisted by stratigraphic configurations (Figure 29a and b). Oil continued to migrate into and accumulate within the reservoir until formation water could no longer be laterally or vertically expelled. If the basal reservoir topography was such that depressions within impervious strata existed, oil would continue to migrate and accumulate within the crest of the structure until the OWC had encroached to the level of 'spill-point' for the water pool (Figure 29c). When this occurred, migration in that sector of the reservoir ceased but continued in other areas of the reservoir where formation water could continue to be displaced until the whole structure had been filled to structural spill-point (Figure 29d). In the context of the Fulmar Field, the general field-wide OWC, at 10840 ft subsea (3304 m), appears to coincide with the spill-point of the main structure. However, the shallow OWC at 10560 ft subsea (3219 m), appears to be restricted to a fault-bounded 'block' in the northern area of the field. Here, water expulsion appears to have been restricted by (1) pinch-out of the reservoir through truncation by the base Cretaceous unconformity and capping by impermeable Cretaceous Chalk, and (2) fault juxtaposition of reservoir quality sands in the 'northern block' against non-reservoir, basal Fulmar and Triassic sequences in the 'main field' area. This scenario accounts for the two main observations from the pressure versus depth plot (Figure 10), namely that (1) oil leg pressures throughout the field all fall on a single gradient, and (2) the 'northern block' contains higher aquifer pressures (by around 80 psi) than the 'main field'.

The results of a TDT (Thermal Neutron Decay Time) logging campaign may throw further light on this topic.

Future development In August 1984, the drilling rig was down-manned since production rates had reached plateau and there was little technical justification for the driling of any additional wells. The Fulmar gas pipeline is scheduled for completion in 1986 and, from this date, solution gas can be exported and preparations made for secondary gas-cap blow-down. development plan. Oil wells will be produced to a water-cut of 90% and platform design allows for a maximum water production of 80,000 barrels per day. Workovers, recompletions and drilling from unused slots will be carried out as necessary to produce the field to its fullest potential.

Conclusions This account of the Fulmar Field emphasizes the importance of developing and refining new geological models both to enhance exploration success and to optimise field development. The discovery of the Fulmar Field occurred after the initial exploration phase in the Central North Sea and established a significant new play. The pre-development drilling strategy of the Fulmar Field allowed, amongst other things, for additional geological appraisal. This was particularly valu-

Marine and Petroleum Geology, 1986, Vol 3, May

123

Fulmar Oil Field: H.D. Johnson et al

!

HYDROCARBON

HYDROCARBON MIGRATION

WATER

WATER

EXPULSION

Figure 29 Proposed mechanism to account for the variation in OWC for the Fulmar Field: (a) prior to hydrocarbon entrapment, (b) during 'early' hydrocarbon entrapment, (c) during 'late' hydrocarbon entrapment, and (d) post hydrocarbon entrapment (i.e. filled to

spill-point)

able in that it established a more complex reservoir than originally anticipated, and it resulted in a revision and update of the geological model(s) which provided a more accurate guide for development drilling strategy and reservoir management.

Acknowledgements The authors wish to thank the managements of Shell UK Exploration and Production, Esso Exploration and Production UK, Amoco (UK) Exploration Co., Enterprise Oil Ltd., Mobil North Sea Ltd., Amerada Hess (UK) Ltd. and Texas Eastern North Sea Inc. for permission to publish this paper.

124

M a r i n e and P e t r o l e u m G e o l o g y , 1986, Vol 3, M a y ,

This review of the Fulmar Field represents the crystallization of ideas and concepts derived, during the past ten years, from numerous contributions from both our colleagues and predecessors. In this respect, the following individuals deserve special note:- John Parker, Gordon Knox, Tony Buller and John Foster for the exploration effort; Niko Praagman, Frans Wonink and Marianne Goesten for reservoir studies; Dave Robertson for seismic studies; and Paul Lapeyre and Dave Wilkin (both of Esso) for their contributions during the more recent development phase. Special thanks are also due to Bob Groves for the preparation of both the figures (contained herein) and the slides used in the presentation of this paper to the

F u l m a r Oil F i e l d : H.D. J o h n s o n et al

Petroleum Exploration Society of Great Britain (May, 1984) and to the American Association of Petroleum Geologists' Annual Convention (March, 1985). Finally, the authors wish to stress that the views expressed within this publication are those of the operator and do not necessarily represent the views of the other Fulmar participants. References Aigner, T. and Reineck, H.E. (1982) Proximality trends in modern storm sands from the Helgoland Bight (North Sea) and their implications for basin analysis, Senckenbergiana manit. 14 183-215 Allen, J.R.L. (1982) Sedimentary structures, their character and physical basis, vol. 1, Elsevier, Amsterdam, 593 pp Brennand, T.P. and van Veen, F.R. (1975) The Auk Oil Field, in: Petroleum and the continental shelf of north-west Europe, L Geology (Ed. A.W. Woodland) London, Institute of Petroleum, 275-284 Campbell, C.V. (1973) Offshore equivalents of Upper Cretaceous Gallup beach sandstone, North Western New Mexico, in Cretaceous and Tertiary rocks of the southern Colorado Plateau: Four Corners Geol. Soc. Mem., (Ed. J.E. Fassett) p. 78-84 Fowler, C. (1975) The geology of the Montrose Field, in: Petroleum and the continental shelf of north-west Europe, L Geology (Ed. A.W. Woodland) London, Institute of Petroleum, p. 467-476 Frey, R.W. and Pemberton, S.G. 1984, Trace fossils facies models, in: Facies models, 2nd edn. (Ed. R.G. Walker) Geol. Assoc. Canada Reprint Ser. 1, p. 189-207 Gebelein, C.D. and Hoffman, P. (1973) Algal origin of dolomite laminations in stromatolitic limestones, Sed. Pet. 43, 603613 Gibbs, A.D. (1984) Clyde Field growth fault secondary detachment above basement faults in North Sea, AAPG Bull, 68, 1029-1039

Heald, M.T. and Baker, G.F. (1979) Diagenesis of Mt. Simon and Rose Run sandstone, in: Diagenesis of sandstone, cementporosity relationships, Compiled by E.F. McBride Johnson, H.D. and Baldwin, C.T. (1985) Shallow Siliciclastic Seas in: Sedimentary environments and facies, 2nd edn. (Ed. H.G. Reading) Blackwells Scientific Publications, Oxford, p.229--282. In press Johnson, H.D. and Stewart, D.J. (1985) The role of clastic sedimentology in the exploration and production of oil and gas in the North Sea, in: Sedimentology: Recent developments and applied aspects (Eds. P.J. Brenchley and B.P.J. Williams) Blackwells Scientific Publications, Oxford, p.249310 McBride, E.F. (1963) A classification of common sandstones, Sed. Pet. 33, 664-669 Pennington, J.J. (1975) The geology of the Argyll field, in: Petroleum and the continental shelf of north-west Europe, L Geology (Ed. A.W. Woodland) London, Institute of Petroleum, p. 285-294 Siever, R. (1962) Silica solubility 0°-200°C, and the diagenesis of siliceous sediments, GeoL 70, 127-149 Spearing, D.R. (1976) Upper Cretaceous Shannon Sandstone: an offshore shallow marine sand body, Wyoming GeoL Assoc. Guidebook, 28th Field Conference, p.65-72 Stow, D.A.V., Bishop, C.D. and Mills, S.I. (1982) Sedimentology of the Brae oilfield, North Sea: fan models and controls, J. Pet. GeoL 5, 129-148 Taylor, J.C.M. (1980) Zechstein facies and petroleum prospects in the central and northern North Sea, in: Petroleum geology of the continental shelf of north-west Europe (Eds. L.V. Illing and G.D. Hobson) Institute of Petroleum, Proceedings of Second Conference, London, p.176-185 Walker, R.G. (1984) Shelf and Shallow Marine Sands, in: Facies Models, 2nd edn., (Ed. R.G. Walker) Geol. Assoc. Canada Reprint Ser. 1, p.141-170 Walmsley, P.J. (1975) The Forties field, in: Petroleum and the continental shelf of north-west Europe, L Geology (Ed. A.W. Woodland) London, Institute of Petroleum, p.477-485 Ziegler, P. (1982) Geological Atlas of Western and Central Europe Shell Internationale Petroleum Maatschappij. B.V., 130 pp.

M a r i n e and P e t r o l e u m G e o l o g y , 1986, Vol 3, M a y

125