SPE 25353 Society of Petroleum Engineers

Optimal Oilfield Development of Fields With a Small Gas Cap and Strong Aquifer Peter Behrenbruch and L.T. Mason, BHP Petroleum

SPE Members

Copyright 1993. Society of Petroleum Engineers. Inc.

This paper was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference & Exhibition held in Singapore. 8-10 February 1993.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper. as presented. have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The matenal. as presented. does not necessarily reflect any position of the Society of Petroleum Engineers. its officers. or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledg­ment of where and by whom the paper is presented. Write Librarian. SPE. P.O. Box 833836. Richardson. TX 75083-3836. U.S.A. Telex. 163245 SPEUT.

ABSTRACT

Production practices for oil fields with gas caps usually centre around conservation of the gas cap (energy) to maximise oil recovery. A less conventional but effective reservoir management approach involves an early gas cap blowdown phase in situations where the gas cap is small and a strong aquifer is present.

This paper describes the critical parameters and the benefits from a less orthodox depletion plan. After discussing this subject from a general point of view, the reservoir management plan for the Skua Field, located in the Timor Sea, is cited as a successful application.

INTRODUCTION

In developing oil fields the aim is usually to maximise ultimate (oil) recovery and at the same time minimise capital expenditure (Capex) and operating expenditure (Opex) , the optimum plan resulting in a maximum Net Present Value (NPV).

To achieve this goal, oil fields may be produced in a variety of ways, constraint by the physical situation, commercial considerations and government regulation.

In terms of reservoir considerations, the most important factors tend to be initial (reservoir) conditions, that is pressure, temperature and depth; and fluid and formation (and rock) properties.

Overall, of these the dominant reservoir drive mechanism(s) and its effect on pressure maintenance and sweep efficiency (effectiveness of pushing oil towards the producing wells) are often the chief criteria for implementing the chosen subsurface development plan -the number, type and location of wells and production policy.

Drive mechanisms may be natural - (gas in) solution drive, (primary) gas cap drive, aquifer drive and compaction drive; or the reservoir energy and sweep efficiency may be supplemented by injecting fluids -commonly water or gas, or more exotic substances, leading to enhanced oil recovery (EOR).

In this paper the above mentioned natural drive mechanisms are reviewed for the purpose of comparing the benefits from a primary gas cap and a natural aquifer. In other words, when is the size of a primary gas cap more important than a certain aquifer? More specifically it is shown by means of a field example, the Skua Field located in the Timor Sea, how the ultimate recovery is being maximised by "blowing down" the primary gas cap! Figure 1 compares the latter production strategy utilised for the Skua Field Development with a more conventional approach.

RESERVOIR ENERGY

One measure of the relative importance of the various drive mechanisms is the intrinsic energy of the different substances, more specifically the compressibility-volume product, which compensates for reservoir voidage (production) in maintaining reservoir pressure.

307

In order to appreciate the wide range of compressibilities, Figure 2 shows these for an "average" situation.

Assuming some typical reservoir volumes for a small oil field, the following compressibility-volume products, at initial conditions, may be considered:

2 Optimal Oil Field Development of Fields with a Small Gas Cap and a Strong Aquifer SPE 25353

OiILec GuCop

F.-.1ica W.r

Rock

AAPfor (W_r A Rock)

Onp..-lbllll)'

(1'" kPa·' , 1'" ,.r') 2.9 .31

43 .300

0.43.3

O.l8.4

1 .7

46.2000 1«1 • 6000

1 SlO • 'lIOOOO

a-wI. VaI_

(M"", MMrII)

16 .100

3.2.31

UI.,.I0000

In this case, a gas cap which is 20 percent the size of the oil leg (m=0.2) has approximately one tenth the instantaneous expansion capacity (potential pressure support energy) as an aquifer which is 100 times the size of the oil leg.

In reality, the gas cap would initially be more effective being in close proximity to the producing wells. The aquifer, on the othe hand, would be slow to respond due to the greater distance through which it has to act. A more rigorous analysis can be carried out in terms of drive indicators; this aspect is further treated in the Appendix.

In the end, the one critical question is - can the aquifer maintain reservoir pressure (sufficiently close to initial pressure)? This question cannot be answered unless one knows not only the size of the aquifer but also how well it is connected to the oil leg. In this respect the permeability thickness product (kh) is important as well as the encroachment angle.

FLUID DISPLACEMENT

The second major aspect to consider is fluid displacement. Assuming the presence of a primary gas cap, the following need to be considered:

aquifer strength primary gas cap size availability and value of (make-up) gas (and cost of reinjection) residual oil saturation to water and gas displacement oil resaturation losses reservoir management (including well completions and recompletions ) dynamic factors - coning and cusping reservoir geometry and heterogeneity

308

Aquifer strength has to be sufficient (size and connectivity) to sweep the oil at elevated pressure (ideally close to initial, bubble point pressure). It is the relative aquifer size, by comparison to the oil leg (and gas cap) that is of importance (see Appendix).

Unfortunately, aquifer strength is usually not proven before development takes place but the chance for a strong or sufficient aquifer is accessed based on regional geology. This aspect is particularly important in offshore situations where pre-investment into a water injection plant(l) has to be considered if the chance of a sufficient aquifer is relatively 1()lW'.

As already discussed above, the size of the gas cap is primarily important for its expansive energy (ability to keep up pressure) and possibly its commercial value.

The injection of gas may be stipUlated by regu1ation. If this is not the case, the value of gas, including possibly make-up gas, and the cost of injection will have to be balanced against possible benefits which may be realised from additional oil recovery in cases where the residual oil saturation after gas displacement is considerably less than that after water displacement. Laboratory experiments indicate that residual oil saturation is typically less (i.e. higher recovery) after gas displacement than displacement by water.

In terms of initial completion intervals, provided the aquifer is strong and the primary gas cap is small, the simplest strategy is to place producing wells near the crest of the structure, even into the initial gas zone. The use of horizontal wells can further aid the maximisation (and/or acceleration) of oil recovery.

The primary gas cap size is also important when considering the aspect of oil resaturation. As the aquifer pushes oil crestally into the primary gas cap, the gas cap pore space is being saturated with oil which may subsequently be reduced again by the following aquifer water. Nevertheless, part of the oil contained originally in the oil zone may be spread over part of the gas cap pore space and be lost as a residual oil saturation (after water displacement). These potential losses have to be balanced against other factors such as the cost of reservoir management and possibly a crestally smaller remaining oil rim at the end of the project when compared to the alternative situation in which the abandonment oil rim is closer to the center of the original oil column.

Balancing an oil rim by a combination of completion and production policies and possibly gas (re)injection can be very costly if drive mechanisms fall outside the predicted range and wells have to be recompleted to optimise

SPE 25353 P. BehrenbnJch and L. T. Mason 3

drainage from an ever decreasing oil rim or, alternatively, unplanned fluid injection has to be implemented. This situation is particularly true in case of subsea development wells where recompletion costs are high, typically several million dollars per well. In the placement of wells (perforated interval), dynamic factors - coning and cusping, are often important. Due to the greater mobility of gas when compared to water, gas coning and cusping can be a problem. Provided the gas cap is not excessive, (i.e. contains considerable energy), it may be futile to prevent gas coning as this will either limit oil rates unnecessarily or result in the placement of non-optimal perforations (too low), leading to recompletion (perforating higher in the interval) to capture the final oil.

Finally, reservoir shape can have a considerable impact on optimising the depletion of the diminishing oil rim. A reservoir of dominant apex shape and with a small gas cap is ideally suited for initial gas cap blowdown.

NUMERICAL MODEL AND EXAMPLES

General Fonnulation

There are an infinite number of combinations involving available reservoir energy, production policy, perforation depths and dynamic effects affecting the evaluation of the feasibility for a gas cap blowdown.

For a strong waterdrive reservoir (like the Skua Field), it is envisaged that during gas cap blowdown from the crestal wells, the active aquifer would push the oil column upward and resaturate most of the original gas cap volume. Part or all of this oil (So,J may not be recoverable as it remains as oil saturation. It is assumed that So,& is the average oil saturation at abandonment, including part of the (original) gas that may remain in the attic. Generally, (l-S..J S So,& S S"".

The volume of oil loss due to resaturation of the gas cap is given by (in stb):

5 V 0.1 =

."~ 5 0 "

(1-s ... ) GB" S"" =

(1-s ... ) s:-(1)

The possible benefit from gas cap blowdown can be accessed by comparing the above loss volume to that incurred by an alternative production policy, e.g. an abandonment oil column of 10m. (It is also assumed that S"" = S .... ). In a strong water drive, this 10m column is closer to the original GOC (gas-oil contact) whereas in a

309

weak water drive, the 10 m column is closer to the original owe (oil-water contact). In the case of a solution gas drive or weak aquifer, it would beadvisable to avoid blowing down the gascap in order to maintain reservoir energy. In these situations, the recovery from the field may be very dependent on the abandonment pressure.If V.1o is the pore volume of this 10 m abandonment column in reservoir barrels, then the amount of oil left (stb) at abandonment is:

Depending on reservoir geometry, this 10 m volume is typically significantly larger towards the base of the reservoir than the crest. In this case and in case of the weak aquifer/solution gas drive it may be advantageous to inject water down dip and blowdown the gascap.

For the gas cap blowdown case, V.1o would be swept by water and the remaining oil by comparison would be V.1o S....)Bo. The remainder of the original oil volume is assumed to be swept equally (S""=S ..... ) in both scenarios.

The total amount of oil left behind following a gas cap blowdown would be:

(2)

The advantage of gas cap blowdown in a reservoir under strong water drive can be evaluated by comparing the oil loss due to resaturation of the gascap to the remaining volume of the 10 m abandonment column without gascap blowdown.

For a gas cap blowdown to be favourable, the reservoir must be under active aquifer drive and

< _V..;...I_O;;,< 1_-5_ ... _) Bo(;Jbft)

Numerical Model

(3)

A numerical model was assembled from a volume versus depth table, PVT (Glaso correlation), aquifer model (Gajdica(2) et al), material balance (extended material balance) macros of Workbench(3). Additional output vectors were created to:

4 Optimal Oil Field Development of Fields with a Small Gas Cap and a Strong Aquifer SPE 25353

(1) Calculate the four drive indices (gas cap expansion, solution gas drive, water drive and formation water/rock) .

(2) Correct for the OWC (oil water contact) movement in the original gas cap zone, associated with a different residual oil saturation in the gas cap to water sweep.

(3) Generate instantaneous GOR from the following formulation

GOR = R. + KS lJ}3o ~

where

KS • (

1 - ( ri:)r [1

- ( ri.J] (ri:f

(4)

(5)

R" J.Lo, J.L" Bo' B, and So are function of pressure and production history.

The above formulation is by no means the only GOR predicting formular. The relative permeability component KS can have many other alternative forms. The above formulation was chosen as it provides calculation stability for time steps of between 30 to 90 days. At each time step the material balance marco provides all the parameters (pressure, saturation, PVT properties, aquifer influx, free gas volumes) required to generate the production data for the next time step.

(4) To allow blowdown of the gas cap by producing ~ of the remaining free gas volume at each time step.

Combining loop control statements with the above macro commands allows the output of one material balance calculation to be the input for the next calculation. The output contained all the necessary reservoir properties on which to generate the next input data. The material balance proceeds iteratively until an abandonment condition such as a 10 m (30 ft) abandonment column or abandonment pressure is reached.

Example

For the geometry given in Figure 3a, the iterative material balance suggests that for m < 0.1, gas cap blowdown would result in better recovery when compared to

310

abandoning a 30 ft oil column. This is illustrated in Figure 3b.

For the simple case, this conclusion can also be obtained algebraically, as follows:

Consider the follwoing gas blowdown situation (Figure 3a):

h = 30ft S_ = 0.2 S_ = 0.3 So" = 0.5 Bo-Bo(tbIJ

Considering equation (3), one has

hA So" + 30A S_ = 30A (1-S....) 0.5 h + (30) (0.3) = 30 (0.8)

or

and

h = 30

m= h = 0.1 ~

This is exactly the same as the numerical solution. For more complex geometries and varying gas cap blowdown rates, the numerical approach will be useful for production planning in optimising recovery.

The above example demonstrates, that in the case of a strong water drive, the most important criteria for a gas cap blowdown is the balance between resaturation losses and the volume left at abandonment by an alternative production policy.

THE SKUA FIELD

General Description

The Skua Field is located in the Timor Sea; the location map is shown in Figure 4.

The Field commenced production in December of 1991 from three wells (Skua-4, -8 and -9), connected to a Floating Production, Storage and Offloading Facility (FPSO), Figure 5. The catenary mooring-riser system can accommodate up to 6 wells.With a capital cost of A$180 million, the project is not only marginal, but is critically dependent on a strong aquifer which was inferred from the regional geology. Wells were perforated crestally for

SPE 25353 P. Behrenbruch and L. T. Mason 5

maximising ultimate oil recovery and to minimise future workover costs (the need to recomplete wells had the original perforations been more conventionally placed near the middle of the oil column).

The field consists of a tilted fault block of Jurassic age(3). The Plover formation consists of massive, high permeability sandstones. Figure 6 shows the areal field map and Figure 7 shows a schematic cross-section. Reservoir and fluid properties are given in Table 1.

The oil initially-in-place is estimated to be 5-8 Mm3 (30-50 MMstb), with a recovery factor of 30 to 45 percent. Considerable uncertainty in the ultimate oil recovery remains, particularly on the flank, as this region has to date not been fully appraised.

Cumulative production to date (end October) has been 1.1 Mm3 (6.8 MMstb) and historic production profiles for the total field are given in Figure 8. As evident, the gas cap blowdown phase lasted approximately 2 months.

To aid the production analysis, simulation models were utilised to predict the likely future reservoir behaviour and Figure 9 shows an early pressure prediction as a function of aquifer strength. To better understand the gas cap response, the predicted elevation of the GOC was also simulated, and Figure 10 clearly indicates that the predicted rising GOC for the strong aquifer scenario is the only one that matches the observed field response. Based on the gas rate history, the small (m - 0.1) initial gas cap, with a volume of 60 Mm3 (2 Bscf), was confirmed. Early field monitoring(5) was critical in confirming a strong aquifer and a small initial gas cap.

The Skua Field Gas Cap Blowdown

For the Skua field the volume loss due to resaturation of the gascap is (2,000,000 rb), or in surface volume (stb):

2,000,000 Bol So.r (6)

Bol in this case is 1.47, and So., - 0.25 (some attic gas remains).

Assuming a strong aquifer, the corresponding volume of the abandonment column of 10 m is 5,600,000 rb, or in surface volume (stb):

5,600,000 (l-S",,") B02

(7)

311

Consider now equation (3), the left hand side (LHS) is given by (in rb)

LHS = 5,600,~ S.,... + 2,000,000 So" = 1,620,000 (S .... = 0.20, So" = 0.25)

and the right hand side (RHS) is given by (in rb)

RHS = 5,600,000 (l-S-> = 4,592,000 (S_ = 0.18)

Assuming BOI - Bol, the abandonment oil volume for the oil rim scenario is approximately three times that for the gas cap blowdown case. Even with some differences in volume factor, for Skua the gas cap could have been at least two times as large (m = 0.2), and the oil recovery would have been greater with the blowdown policy than with a conventional oil rim scenario. Furthermore, fewer wells and savings in recompletion make the blowdown case clearly the more attractive of the alternative production scenarios.

CONCLUSIONS

1. Oil production and recovery may be maximised from a reservoir with a small primary gas cap by blowing down this gas cap during the initial production phase, provided a strong natural aquifer exists.

2. Reservoir management and operating costs (workovers) tend to be minimised for the situation described. This is particularly true for subsea well developments.

3. It is safe to say that for m < 0.1 (any geometry) and in the presence of a strong water drive, gas cap blowdown will result in better recovery compared to a 10 m abandonment column. In many cases the gas cap can be even larger (m - 0.2) and a gas cap blowdown scenario is still the preferred case.

NOMENCLATURE

Variables

A - cross sectional area of reservoir, ft2 B - volumetric factor, rb/stb c - compressibility, psi/psi E - expansion factor, rb/sef F - total voidage (production in reservoir volume) G - gas in-place (standard conditions), sef GOR - gas-oil ratio, sef/stb h - thickness of oil rim, ft KS - relative permeability function LHS - left hand side of equation

6 Optimal Oil Field Development of Fields with a Small Gas Cap and a Strong Aquifer SPE 25353

m - relative reservoir gas cap volume (compared to reservoir oil volume), ratio

N - oil in-place (standard conditions), sth P - reservoir pressure, psi R - gas in solution ratio, sef/stb S - reservoir saturation by a fluid (oil, gas or

water), fraction S - average saturation, fraction V - volume W - water (or aquifer) volume 4 - incremental change (del) p. - viscosity

Subscripts

g - gas gi - gas initial, sef h., - hydrocarbon j index o - oil 0i - oil, initial, stb Or - oil, residual, fraction 0" - oil, residual - after displacement by gas, fraction 0,., - oil, residual - after displacement by water,

fraction o,g - oil in gas cap OCilla) - oil at abandonment p - production s - solution Si - solution, initial w - water q, - pore q, - pore and water (formation) q,JO - pore space of 10 m oil rim

ACKNOWLEDGMENTS

The authors thank the Management of BHP Petroleum and the Skua Joint Venture Participants: Santos, Ampolex, Command Petroleum, Norcen International and Minora Resources for permission to publish this paper.

REFERENCES

1. Behrenbruch, P. "Offshore Oil Field Development Planning: Project Feasibility and Key Considerations", SPE 22957, Presented at the SPE Asia-Pacific Conference held in Perth, Australia 4-7 November, 1991.

2. R.J. Gajdica, R.A. Wattenberger and R.A. Startzman. A new method of matching Aquifer Performance and determining original gas-in-place. SPE 16935 presented at Dallas Texas September 27-30, 1987.

3. The Workbench computer package is a general purpose reservoir engineering calculation and problcm solving programme from Exploration and Production Consultants (Australia) Pty Ltd.

4. Osborne. M. "The Exploration and Appraisal History of the Skua Field. ACIP2 - Timor Sea". The 1990 APEA Journal 30: 1. 197-211.

5. Chapman. G.J. "Reservoir Managcment of Subsea Development Fields in the Timor Sea" . To be presented at the 1993 APEA Conference.

APPENDIX

MATERIAL BALANCE AND DRIVE INDICATORS

1. Compressibility

In producing any reservoir the voidage created win be taken up by expanding reservoir fluids and the shrinking pore space. both the consequence of a reduction in pore pressure. This compressive behaviour is given by the definition of compressibility (in reservoir terms), as follows:

(_) 1:. IlVJ ., (_) 1 IlBJ VJ AP S; AP (AI)

The negative sign implies expansion of fluids with decreasing pore pressure. Only the pore compressibility is positive.

2. Material Balance

312

In deriving the general material balance equation. one may simply consider volume changes (due to compressibility) with reduction in pore pressure. More specifically:

for oil

(A2)

solution gas

(A3)

free gas

SPE 25353 P. Behrenbruch and L. T. Mason 7

4V, .. G(B,-B,,)

mNB .. .. (B -B ) ~ , "

" where the relative gas cap size (m) is given by

GB" m '" 1nf: ..

pore space

hydrocarbon pore space

furthermore

or

also

v .. •

and therefore

(l+m)NB ..

( 1-s_)

4V/t& .. -(l+m)NB .. (ct_'S:·)Ap

(A4)

(A4a)

(AS)

(A6)

(A7)

(AS)

(ASa)

(A9)

(AIO)

(All)

Furthermore, production in terms of underground withdrawal (voidage) is given by

oil and solution gas N,Bo + N,(R,-R.)B,

water W,B.,

Summing all production (F)

and equating voidage with changes in volume due to expansion/contraction

F .. E 4VJ '"' N(Eo+mE,+E .... ) +W)3 .. J

(A13)

where the Ej = are defined by equations A2, A3, A4a, and All.

W = influx of water measured in surface volume. •

3. Drive Indicators

313

Dividing equation (AI3) by F results in

1 = N E + Nm E + N E + W. B 7 0 7' 7·· .. 7" (A13a)

where the drive indicators can now be defined as follows:

oil and solution gas

;Eo = ; (Bo-B .. ) + (Rn-R.)B,

free gas

~E, .. ;B .. ( B:~l) pore volume and connate water

aquifer (simplistically)

;B .. '" (c .... )W,Ap

(AI4)

(AIS)

(AI6)

(AI7)

The above expressions are fractions which sum to unity. For a very strong aquifer WJ!..,IF>O.9. For a depletion drive situation with a large gas cap, NmE IF will be the dominating term. In most cases , NE •. .,IF is small or negligible.

General (Initial Conditions) Datum Depth Pressure at Datum Temperature at Datum Average Formation Dip Oil-Water Contact Gas-Oil Contact Water Salinity (NaCl)

Fonnation and R.ock Properties (Averages) Area Gross Thickness - Gas

- Oil Net-to-Gross Porosity Hydrocarbon Saturation Residual Oil Saturation Residual Gas Saturation

Fluid Properties (Initial Conditions) Oil Relative Density Oil Formation Volume Factor Oil Viscosity Oil Compressibility Gas-Oil Ratio Gas Expansion Factor Gas Viscosity Water Viscosity

R.ecovery (Average, Expected) Main Drive Mechanism Size of Aquifer Microscopic Sweep Efficiency Volumetric Sweep Efficiency Formation Permeability Expected Abandonment Pressure Oil-in-Place (P + P) Recovery Factor

Table 1

2286.5 m ss 22.86 MPa (3315 psia) 96 °C (205 OP) 18S SE 2333 m ss 2286.5 m ss 110,000 mgll

0.5 km W, 4.8 km L 28m 46.5 m (TVD) 0.5 0.21 0.82 0.20 0.15

0.815 (420 API) 1.48 m3/m3 (rb/stb) 0.30 cP 2.87 x 1<r kPa-1

160 m3/m3 (900 scf/stb) 200 m3/m3

0.021 cP 0.35 cP

Edge water drive Large (moderate to strong) 0.80 0.40-0.60 360-1700 md High, aquifer drive expected 5-8 Mm3 (30-50 MMstb) 0.30-0.45

Skua Field - Reservoir and Fluid Properties (pb2441.joh)

314

SPt2535J

Nl1AL IESERYOIR SITUATION

CONVENTIONAL OIL RIll DEVELOPMENT

FINAL RESERVOIR SITUATION

-eope--.t _01 lint __ t

b)

c)

GAS CN' .LOWDOWN DEVELOPMENT

FINAL RESERVOIR SITUATION

__ .AEIIAII~ING GAS CAP

Olin ... RESATIlRATED ZONE

ZONE

10000

2000

1000

20

10

15

2 o

SPE25353

" TEMPERATURE 232" F

'" ~ FREE GAS 0=0.75, Air:1) "',

" , 4 ~~CRUDE

~ ATURATED)

FORMATlONW ~TER CONSOLIDATED ROCK ••

10j,. 2Oez.

1000 2000 3000 4000 5000

PRESSURE (pal.)

Flgur. 1 SkUll field Development. R ... rvolr Menllgement Concept. Flgur. 2 Typical Compr ... lbllltie. of R ... rvolr Fluid. and Rock

h 11 au Column

t.

&orw.O.3 awc.o.2

S1rang ,\qui ....

Flgur. 3a Reservoir Geometry and Paramet.r. for exampl.

315

f

0.65,.-----------------..,

0.60

.... ...... ' ...... . ...

...... ' ...... . ... ...... ..... ...... --.-.. -:--.-~~.-Economic CuD"'. ... ... ~ ........ ~.-.... ~'. ...

-055

I ----p ... '"-::::~ ': ' ~~~:..:

050

Hunterlclll atIona ••••••

'..r: •• --:- -" ". ..................................................... L......; .......

.... 0.25 1Gri_0..30 a.t.O.l "IMn.CaUm ....

3O.-.c.um ".-.c.um __ _ - . 0.45 L.. __ ....L ___ ...L.. ___ L-. __ ....L __ ---J

0.00 0.05 0.10 0.15 020 025

M FIICtOr (Fraction, Ga, c.p Size)

Flgur. 3b Ga. Cap Blowdown • Effect of Ga.cap Sia on Recov.ry

TIMOR () c;!I)

TIMOR SEA

ACIP6

/' ,/

NTIPB .,..., ~

4 \\ WA-36-P \

\

Figure 4 Skua Field Location

PROCESS SKIDS

FLARE TOWER -

\ \

\

HAWSER

TANDEM ANCHORS

SPE25353

I 0"" _L....-'-_km-'-...,j~2-'50

SHUTTlE TANKER

FLOATING CRUDE PRODUCT HOSE

-- SUBSEA WELLHEAD

MID-DEPTH BUOYS

Figure 5 Skua Field Development - Schematic of Disconnectable FPSO Facility

316

o ICC) 400 100 100 1000 ; ; Zf?hNls; ;

Figure 6 Skua Field -Intra Valanginian Unconformity Depth

A' ............. _______ .JL~..a. _

2286.5mSS

SKUA FIELD

Figure 7 Skua Field - Schematic Cross-Section

100 ,

SPE25353

• ... • a.- .01 .1

• I " ...... :., . .,. : i- Ia.-J. ur

t"· ;I

i .I". g 16 ~ 0'.

,. '. -......,., ,,_ _V. , ........ ,-.

Figure 8 SkUll Field Production PerforlMnce (Weekly Averegee)

l !.

J 1 f

.4r---------------------------------------------------------, Loweal CalaJlated Pr .. sure (Multirate Testing)

...... ..-i: ............... . Strq Aquller

..... .... .. i- ••• ~, .................... .

' ...... ,­'. -,

.... '---~ ~ •••••••• :~ •••••••••••••• ~~.~ .. -- •••••••••••••••••••• - ••• w •• .. ,- .....

~ ... 1-'. ... .... ~ - ...

1, _. __ •• __ ._ •••••• :~.::-••••••••• - ••••••• - •••••••••• 7.~~. __ ._ .. '.

Oo •••• ,. -..............•.......... ::~.~:::::::~:~ .......•..•.........

'4 ' . ........ -•.........• -.-...... -.---........ ~-~.-..... -....... .

•••••• VoIumetric ". ,.~ __________ ~I __________ -L __________ ~ ____________ ~ __ -'

.. '00 , .. PRODUCTlOH DAYS

Figure g Skue Field Meterlel aelenee Preeeure Prediction tor Dlft.rent Strength Aqul"re

~r---------.... ----.... ------.... ----.... ------.... --.... ----~ zno •••.•••••••••••.•••••••••••••••••••• ~~~2;~~~.~~~! ....

i : ~~:.~~;.;::::::-: ~==-::]l:::::==::: E ....a .a - - .1. Intermediate AquHer i ..... j Os 1= --- ...... Iii 2300 !-o .............. :h ........................ : ••••••••••••••••••• CI j ......... ~ .... ~

23'0 !-o ••••••••••••••••••••••••. J .... :::::::: ... ::::::::: ........ . No'Aquiler

~!-o •••••••••••••••••••••••••••••••••••••••••••••••••••••••• __ •• -

2~~ __________ L-__________ L-__________ ~ __________ '~ __ ~

50 '00 '50 200

PRODUCTlOH DAYS

SPE25353

Figure 10 Sku Field Meterlel Belenee GOC Movement Prediction for Different Strength Aqul"re

318