pp evaluation exploration2014 k
TRANSCRIPT
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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
9/19-6 Frigg, Balder 29 53
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
9/19-7 Frigg, Balder 20 56
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.