pp evaluation exploration2014 k

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EP201501208218

Petrophysical evaluation for the K exploration prospect

9/18a-B3, 9/19-2, 9/19-6, 9/19-7 and 9/19-7S1

Yu Ling Wu, SUKEP-UIO/W/D

January 2015

Document number: EP201501208218



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Introduction

The primary target reservoirs of the K prospect are Upper and Lower Beryl. The secondary reservoir

targets are Triassic, Upper Jurassic and Tertiary injectites. The five key regional wells are 9/18A-B3 and

9/19-2, 9/19-6, 9/19-7 and it’s sidetrack 9/19-7Z. The key uncertainties for this prospect are faulting and

the presence of upper Beryl/ onlap of Beryl unit onto Triassic high.

Figure 1: Map showing the key wells.

Data preparationThe tables below show which reservoir targets are penetrated. The logs that were acquired in the

relevant hole sections.

Table 1: Overview of the penetrated reservoir targets.

Tertiary Upper Jurassic Beryl formation Jurassic (other) Triassic

9/18A-B3 Only GR Yes (Heather) Yes - Not penetrated

9/19-2 Yes (Frigg, Balder,

Sele)

Not seen Yes (Lower

Beryl)

Linnhe, Dunlin,

Eiriksson

Yes (Lewis 3, 2, 1)

9/19-6 Yes (Frigg, Balder,

Sele)

Yes (Heather) Yes (Beryl,

Lower Beryl)

Linnhe Only few feet into

the Lewis formation

=> not evaluated

9/19-7 Only GR-RES-DT,

not evaluated

Not

penetrated

Not penetrated - Not penetrated

9/19-7Z In original hole Yes (Heather,

Katrine, J50-

J40-J30sands)

Yes (Beryl,

Lower Beryl)

Linnhe Not penetrated

9/18A-B39/19-7

9/19-6

Buckland

Skene

9/19-2

K prospect



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Table 2: Overview of acquired log data.

Operator Spud

date

Hole section

Interval

ftMD

Mud Logging

contractor

GR DEN NEU RES DT

9/18A-B3 Mobil 3 Nov

1998

8.5 9787-

12850

OBM Schlumberger GR LDL CNL ILD BHC

9/19-2 Conoco 30 Jan

1976

12.25 5035-

11045

WBM

(lignosulfate)

Schlumberger GR FDC CNL ISF BCSL

8.5 11045-

12846

WBM

(lignosulfate)

Schlumberger GR FDC CNL ISF,

DLL

BCSL

9/19-6 Conoco 15 Nov

1981

12.25 5140-

10890

WBM

(seawater/

polymer)

Schlumberger GR FDC CNL DIL BHC

8.5 10890-

13084

WBM

(lignosulfate)

Schlumberger GR FDC CNL DIL BHC

9/19-7 Conoco 20 June

1983

12.25 5040-

11780

Inverted oil

emulsion

Schlumberger GR DIL SLS

9/19-7Z Conoco 8.5 12256-

14080

Inverted oil

emulsion

Schlumberger GR FDC CNL DIL SLS

Well 9/19-7 was side-tracked because the drill string became irretrievably stuck in hole whilst drilling at

13224ftMD. The hole was plugged back and sidetracked from 12256ftMD.

The density data over the Sele formation in well 9/19-2 was of poor quality. Over the Jurassic the

borehole of 9/19-6 showed washouts which may have affected the density readings. The poor quality

intervals are flagged with a red flag in the miniplots.

Analysis and Results

Porosity

The porosity was derived from the density according to the equation:

= − −

, where = porosity and = density.

The density of sand=2.65 g/cc has been used as the matrix density. The fluid densities are calculated

from estimated fluid compositions. In all cases it was estimated that the fluid was made up of 20%

connate water, 20% mud filtrate and 60% of oil in the oil leg or water in the water leg. At a formation

salinity of 68 kppm and a temperature around 200oF, the water density is 1.0 g/cc. The mud filtrate of

OBM was estimated to be 0.85 g/cc, the mud filtrate of the WBM 1.0 g/cc. The oil density at reservoirtemperature was estimated to be 0.77 g/cc (the oil is estimated to have an API of 40). In case it was

inconclusive whether an interval contained oil or water it was assumed the fluid was oil, which leads to

slightly lower calculated porosities.



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Connate

water

= 1.0 g/cc

Oil

=0.77 g/cc

Water

=1.0 g/cc

OBM mud

filtrate

=0.85 g/cc

WBM mud

filtrate

= 1.0 g/cc

Total fluid

density

WBM Oil leg 0.2 x1.0 0.6 x0.77 0.2x1.0 0.86 g/cc

WBM Water leg 0.2 x1.0 0.6 x1.0 0.2x1.0 1.0 g/cc

OBM Oil leg 0.2 x1.0 0.6 x0.77 0.2 x0.85 0.83 g/ccOBM Water leg 0.2 x1.0 0.6 x1.0 0.2 x0.85 0.97 g/cc

Saturation

The water saturation was calculated with the Archie equation:

= ( ∙ )

/

, where: Sw= water saturation

a= tortuosity factor

Rw= formation water resistivity

Rt= true formation resistivity = here deepest reading resistivity

= porosity = density porosity as defined above

m= cementation factor

n= saturation exponent

a m n Rw

Frigg, Balder 1 1.8 1.8 0.1 ohm.m (from Pickett plot)

Sele 1 1.8 1.8 0.04 ohm.m (from Pickett plot)

Katrine, J, Heather,

Beryl, Lower Beryl

Dunlin, Eiriksson,

Linnhe

1 1.84 1.85 0.07 ohm.m (from Pickett plot)

Lewis 1 1.85 1.95 0.04 ohm.m at 200oF (68 kppm)

(from An integrated petrophysical field study of the

Beryl alpha area, Woods, 2001)



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Figure 2: Pickett-plot for the Frigg and Balder formation over the water bearing sands.

Figure 3: Pickett-plot over the Sele formation over the water bearing sands.

Rw=0.1 ohm.m

m=1.8

Rw=0.04 ohm.m

m=1.8



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Figure 4: Pickett-plot over the Jurassic over the water bearing sands.

Net-to-gross

The net-to-gross was based on a Gamma ray based Vshale. The Vshale was a linear function of the

gamma ray:

ℎ = − −

As the GR_sand and GR_shale the 5th

and 95th

percentile were taken. There were a couple of exceptions:

-

The Heather in 9/18A-B3 did not contain any sands, as can be seen from the density-neutroncurves and no sand was observed in the cuttings. As the GRsand the same value was taken as

the GRsand in the Beryl formation.

-

In 9/19-7S1 the Heather, Katrine and J-sands hardly encountered sand. The GRsand was

estimated by drawing a baseline through the sandy interval around 12370ftMD.

The table below summarises the GRsand and GRshale. The Vshale cut-off used was 0.5. In addition a

porosity cut-off of 0.20 v/v was used for the Linnhe formation to cut out coal streaks.

Well Formations GRsand GRshale

9/18A-B3 Heather 21 155

Beryl 21 74

9/19-2 Frigg, Balder 35 60

Sele 24 68

Lower Beryl 18 82

Linnhe, Dunlin, Eiriksson 23 92

Lewis 47 105


Sele 23 64

Rw=0.07 ohm.m

m=1.84



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Heather 52 118

Beryl, Lower Beryl 15 87

Linnhe 15 85


Sele 24 69

9/19-7S1 Heather, Katrine, J-sands 30 112Beryl, Lower Beryl 16 93

Linnhe 47 105

Overall interpretation well-by-well

The information below is a summary of the information on the composite well logs and the log

evaluation.

9/18A-B3

-

Beryl: The logs show an oil-down to (ODT)=11326ftTVDSS. Contrary to the logs, the cuttings did

not have any visual porosity. There were no shows on the cuttings.

9/19-2

-

Frigg: the resistivity log shows ODT=5672ftTVDSS, but because the hole conditions are poor no

reliable porosity and saturation calculation can be done. Down to this depth there are increased

gas readings and good shows. Below this depth the logs indicate water and there are no

increased gas readings but there are good shows and some oil staining.

-

Balder: The logs indicate the Balder is water-bearing. During drilling there were no increased gas

readings and no shows on the cuttings.

-

Sele: The density is of poor quality and therefore the log interpretation is not always reliable.

There are some intervals with increased gas readings and some poor to good shows. During anFIT (formation interval test) done at 6888ftMD a sample with no gas, 200cc oil (black, heavy,

viscous, dead oil) and 9800cc mud filtrate was obtained.

-

Lower Beryl: The logs show ODT 11474ftTVDSS. The presence of oil is supported by increased

gas readings and poor to good oil shows on the cuttings. DST #4C over the interval 11568-

11593ftMD below the ODT produced only water.

-

Jurassic below the Beryl: There are no hydrocarbons seen on the logs. On the cuttings there

were poor shows and no visible oil staining.

-

Triassic: The Lewis 3, 2 and 1 are hydrocarbon bearing based on log data. This interpretation is

supported by poor to moderate shows on the cuttings and increased gas readings while drilling.

There were two successful DST’s (#1A and #3B) done during which gas and condensate wereproduced.



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9/19-6

-

Frigg-Balder: The logs do not show any indications of hydrocarbons. The cuttings had fair shows,

scattered visible oil staining and faint-dull fluorescence. There were some but no large increases

in the gas readings. Currently, these formation are water bearing but at some point in time they

probably contained hydrocarbons.-

Sele: There are no indications of hydrocarbons on the logs. The cuttings had some poor shows

and visible oil: “no to rare intergranular bitumen, dark brown-black and very viscous”. Currently,

these formation are water bearing but at some point in time they probably contained

hydrocarbons.

-

Heather: The borehole is washed out and therefore the density log and the calculated porosity

and saturation are not reliable. There were no shows on the cuttings and no increased gas

readings.

-

Beryl: The logs indicate the Beryl formation is water-bearing. There were some increased gas

readings, but the cuttings had only poor shows and no visible oil staining.

-

Below the Beryl the logs indicate only water. There were no shows on the cuttings.

9/19-7 and 9/19-7S1

-

Tertiary: The logs indicate the Frigg, Balder and Sele are water bearing. There were also no

shows on the cuttings.

-

Upper Jurassic: The logs indicate the Upper Jurassic is water bearing. There were also no shows

on the cuttings.

-

Beryl: The calculated water saturation is not exactly 1. But probably the Beryl formation is water

bearing because there were only poor oil shows and no visible oil staining. That the calculated

water saturation is not exactly 1 could be because no corrections on the resistivity were done to

obtain the true formation resistivity. The deepest reading resistivity curve was taken. In this wellthe Beryl formation was drilled with oil based mud, whereas the 9/19-2 and 9/19-6 drilled it

with water based mud.



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Sums and averages

The sums and averages are given in TVDSS. The net-to-gross is the TV net interval (including net with

poor hole quality) divided by the TV gross interval (including gross with poor hole quality). The average

porosity is calculated over only the sands over which the log quality is good. The saturation is only given

for intervals above the OWC, including the transition zone.

The miniplots are at the back of this document. Some wells have several miniplots to focusing on the

various formations. In the miniplots the porosity and saturation are only shown over the intervals where

the log quality was good.

Well ZonesTop

ftMD

Bottom

ftMD

Top

ftTVDSS

Bottom

ftTVDSS

Gross

TV

Net

TV

Net to

Gross

Gross TV

(good hole

only)

Net TV

(good

hole

only)

Average

Porosity

Av_Hydrocarbon

Saturation above

the contact

9_19-2 Frigg 5741.0 6167.0 5661.0 6087.0 426.0 167.5 0.39 199.0 84.0 0.256 unknown

9_19-6 Frigg 5928.0 6173.0 5851.0 6096.0 245.0 59.0 0.24 245.0 59.0 0.276

9_19-2 Balder 6167.0 6600.0 6087.0 6520.0 433.0 169.0 0.39 248.5 35.0 0.2569_19-6 Balder 6173.0 6610.0 6096.0 6532.9 436.8 185.9 0.43 272.0 60.5 0.318

0.38 0.277

Well ZonesTop

ftMD

Bottom

ftMD

Top

ftTVDSS

Bottom

ftTVDSS

Gross

TV

Net

TV

Net to

Gross

Gross TV

(good hole

only)

Net TV

(good

hole

only)

Average

Porosity

Av_Hydrocarbon

Saturation above

the contact

9_18A-B3 Sele 6200.0 7180.0 6111.8 7069.1 957.2 477.9 0.50 957.2 477.9 0.380

9_19-2 Sel e 6600.0 10977.0 6520.0 10897.0 4377.0 1917.0 0.44 2460.0 1453.5 0.162

9_19-6 Sel e 6610.0 11077.0 6532.9 10932.2 4399.3 1648.6 0.38 3872.0 1542.8 0.163

0.42 0.192

Well ZonesTop

ftMD

Bottom

ftMD

Top

ftTVDSS

Bottom

ftTVDSS

Gross

TV

Net

TV

Net to

Gross

Gross TV

(good hole

only)

Net TV

(good

hole

only)

Average

Porosity

Av_Hydrocarbon

Saturation above

the contact

9_18A-B3 Heather 11600.0 12305.0 10724.6 11300.3 575.7 4.1 0.01 575.7 4.1 0.046

9_19-6 Heather 11242.0 11981.0 11094.7 11822.5 727.8 240.3 0.33 0.0 0.0

9_19-7S1 He athe r 12150.0 12373.0 12062.7 12284.8 222.0 48.8 0.22 193.7 33.9 0.046

9_19-7S1 J36 12825.6 12972.0 12732.3 12876.1 143.8 1.0 0.01 143.8 1.0 0.035

9_19-7S1 J42 12809.2 12825.6 12716.1 12732.3 16.1 0.0 0.00 16.1 0.0

9_19-7S1 J44 12772.2 12809.2 12679.7 12716.1 36.4 1.0 0.03 36.4 1.0 0.054

9_19-7S1 J46 12761.0 12772.2 12668.8 12679.7 11.0 0.0 0.00 11.0 0.0

9_19-7S1 J52 12711.5 12761.0 12619.9 12668.8 48.8 2.0 0.04 48.8 2.0 0.039

9_19-7S1 J54 A 12632.7 12711.5 12542.1 12619.9 77.8 1.0 0.01 77.8 1.0 0.055

9_19-7S1 J54 B 12599.7 12632.7 12509.5 12542.1 32.6 0.5 0.02 32.6 0.5 0.022

9_19-7S1 J54 C 12567.7 12599.7 12477.8 12509.5 31.7 2.0 0.06 31.7 2.0 0.036

9_19-7S1 Katrine 12373.0 12567.7 12284.8 12477.8 193.1 28.3 0.15 193.1 28.3 0.083

0.16 0.060



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Well ZonesTop

ftMD

Bottom

ftMD

Top

ftTVDSS

Bottom

ftTVDSS

Gross

TV

Net

TV

Net to

Gross

Gross TV

(good hole

only)

Net TV

(good

hole

only)

Average

Porosity

Av_Hydrocarbon

Saturation above

the contact

9_18A-B3 Beryl 12305.0 12907.5 11300.3 11791.1 490.8 328.2 0.67 490.8 328.2 0.162 0.33

9_19-6 Beryl 11981.0 12063.0 11822.5 11903.2 80.7 53.7 0.67 32.5 24.6 0.120

9_19-7S1 Be ryl 12972.0 13350.0 12876.1 13246.1 370.0 328.5 0.89 370.0 328.5 0.138

0.75 0.149

Well ZonesTop

ftMD

Bottom

ftMD

Top

ftTVDSS

Bottom

ftTVDSS

Gross

TV

Net

TV

Net to

Gross

Gross TV

(good hole

only)

Net TV

(good

hole

only)

Average

Porosity

Av_Hydrocarbon

Saturation above

the contact

9_19-2 Lower Beryl 11366.0 11694.0 11286.0 11614.0 328.0 231.5 0.71 328.0 231.5 0.128 0.47

9_19-6 Lowe r Be ryl 12063.0 12258.0 11903.2 12095.3 192.1 66.0 0.34 192.1 66.0 0.083

9_19- 7S1 Lower Beryl 13350.0 1 3990.0 1 3246. 1 13871.0 6 24. 9 426.7 0. 68 624. 9 426.7 0.117

0.63 0.117

Well ZonesTop

ftMD

Bottom

ftMD

Top

ftTVDSS

Bottom

ftTVDSS

Gross

TV

Net

TV

Net to

Gross

Gross TV

(good hole

only)

Net TV

(good

hole

only)

Average

Porosity

Av_Hydrocarbon

Saturation above

the contact

9_19-2 Linnhe 11694.0 11850.0 11614.0 11770.0 156.0 33.0 0.21 156.0 33.0 0.108

9_19-6 L innhe 12258.0 12561.0 12095.3 12393.7 298.4 96.0 0.32 70.9 40.4 0.089

9_19- 7S1 Li nnhe 13990.0 14101.0 13871. 0 13979.1 108. 2 10.2 0. 09 108. 2 10.2 0.050

0.25 0.092

Well ZonesTop

ftMD

Bottom

ftMD

Top

ftTVDSS

Bottom

ftTVDSS

Gross

TV

Net

TV

Net to

Gross

Gross TV

(good hole

only)

Net TV

(good

hole

only)

Average

Porosity

Av_Hydrocarbon

Saturation above

the contact

9_19-2 Dunlin 11850.0 11855.3 11770.0 11775.3 5.3 0.5 0.09 5.3 0.5 0.045

0.09 0.045

Well ZonesTop

ftMD

Bottom

ftMD

Top

ftTVDSS

Bottom

ftTVDSS

Gross

TV

Net

TV

Net to

Gross

Gross TV

(good hole

only)

Net TV

(good

hole

only)

Average

Porosity

Av_Hydrocarbon

Saturation above

the contact

9_19-2 Eiriksson 11855.3 12000.0 11775.3 11920.0 144.7 8.5 0.06 144.7 8.5 0.2160.06 0.216

Well ZonesTop

ftMD

Bottom

ftMD

Top

ftTVDSS

Bottom

ftTVDSS

Gross

TV

Net

TV

Net to

Gross

Gross TV

(good hole

only)

Net TV

(good

hole

only)

Average

Porosity

Av_Hydrocarbon

Saturation above

the contact

9_19-6 Lewis 12975.0 13103.0 12801.4 12927.5 126.0 0.0 0.00 126.0 0.0

9_19-2 L ewis 1 12318.2 12651.0 12238.2 12571.0 332.8 185.5 0.56 332.8 185.5 0.130 0.39

9_19-2 Lewis 2 12275.6 12318.2 12195.6 12238.2 42.6 8.9 0.21 42.6 8.9 0.098 0.25

9_19-2 L ewis 3 12000.4 12275.6 11920.4 12195.6 275.2 270.1 0.98 275.2 270.1 0.112 0.24

0.60 0.119



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Figure 5: Miniplot of 9/18A-B3 Heather and Beryl formation.

ODT

11326

ftTVDSS



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Figure 6: Miniplot of 9/19-2: Frigg and Balder formation. The Sele and Jurassic formations are shown in separate miniplots.

ODT

5672

ftTVDSS



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Figure 7: Miniplot of 9/19-2 Sele formation. The shallower and deeper formations are shown in separate miniplots.



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Figure 8: Miniplot of 9/19-2 Jurassic and Triassic formations. The shallower formations are shown in separate miniplots

11474

ftTVDSS D S T # 4 C

D S T # 1 A

D S T # 3 B



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Figure 9: Miniplot of 9/19-6 Frigg and Balder formation. The Sele and Jurassic formations are shown in separate miniplots.



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Figure 10: Miniplot of 9/19-6 Sele formation. Shallower and deeper formations are shown in separate miniplots.



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Figure 11: Miniplot of 9/19-6 Jurassic formations. Shallower formations are shown in separate miniplots.



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Figure 12: Miniplot of 9/19-7 Sele formation.



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Figure 13: Miniplot of 9/19-7S1 Jurassic formations.

pp evaluation exploration2014 k

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