Petrophysical information (Verlo and Hatland, 2008)

Petrophysical information (Verlo and Hatland, 2008) The petrophysics of the Norne main field is based on data from the two exploration wells 6608/10 2 and 6608/10 3. In 1994 the exploration well 6608/10 4 was drilled in the G segment creating base for the petrophysical interpretation of this area. The base measurements for the evaluation are; wireline log data, conventional and special core analysis, formation pressure points and fluid samples [Statoil, 2001]. A total picture of the porosity of the Norne Field is obtained by relating the core porosity to the density log. As a consequence, the water saturation has to be calculated using Archie's formula. The net to gross ratio and permeability were also estimated in this study. For the G segment, separate values for net to gross ratio, porosity, water saturation and permeability were calculated. The Norne reservoir has good to very good reservoir properties with average porosities in the range 20% 30%, average net to gross value in the range of 0.7 1.0, water saturation from 12% to 43% in the hydrocarbon zones and permeability values ranging from approximately 20 to 2500 md [Statoil, 2001]. Since the first study, other wells have been cored on the Norne Field. They include wells 6608/10 D 1 H, 6608/10 C 4 H and 6608/10 F 1 H. Based on these new cores, revisions of porosity/permeability relations and the water saturation have been made [Statoil, 2001]. The petrophysical parameters have been modelled in the geological model using co located co kriging to acoustic impedance [Fawke, 2008]. Well Information: Well 6608/10 2. Spudded at: 28 th October 1991 Total depth (TD) of the well was at 3678 m below Rotary Kelly Bushing (RKB), and this depth was reached December 16 th the same year. In January 1992, four drill stem tests were carried out on this well, which tested gas in the Garn Formation, oil in the Tofte

Formation and water in the Tofte/Tilje Formation. The well discovered a hydrocarbon column of 135 m in the rocks of Lower and Middle Jurassic. 110 m was oil, and the rest was an overlying gas cap. Table 1: Detail description of well 6609/10 2 (NPD, 2010) NPDID wellbore: 1782 Well name: 6608/10 2 Drilling operator name: Den norske stats oljeselskap a.s Geodetic datum: ED50 Coordinates: 66 0` 49.35`` N 8 4` 26.48`` E UTM coordinates: 7321933.62 N 457994.68 E UTM zone: 32 Drilled in production licence: 128 Area: NORWEGIAN SEA Discovery: 6608/10 2 NORNE Field: NORNE Drill permit: 701 L Drilling facility: ROSS RIG Drilling days: 94 Wellbore entry date: 28.10.1991 Wellbore completion date: 29.01.1992 Original wellbore purpose: WILDCAT Wellbore purpose: WILDCAT Wellbore status: P&A Wellbore contents: OIL/GAS Discovery wellbore: YES Formation/age with hydrocarbons 1: FANGST GP / MIDDLE JURASSIC Formation/age with hydrocarbons 2: BÅT GP / EARLY JURASSIC Seismic location: NRGS 85 NRGS84 451& SP. 780 Kelly bushing elevation (KB) [m]: 23 Water depth [m]: 374 Total Depth (MD) [m]: 3678 Final vertical depth (TVD) [m]: 3677 Max inclination [ ]: 4.00 Bottom hole temperature [ C]: 133 Oldest penetrated age: LATE TRIASSIC Oldest penetrated formation ÅRE FM

Well 6608/10 3. Spudded in: January 1993 Total Depth (TD) was reached at 2991 m February 19 th 1993. One month later, one drill stem test was performed, which tested oil in the Ile Formation. The well confirmed the test results from well 6608/10 2, and proved the extension of the field to north. Table 2: Detail description of well 6609/10 3 (NPD, 2010) NPDID wellbore: 1732 Well name: 6608/10 3 Drilling operator name: Den norske stats oljeselskap a.s Geodetic datum: ED50 Coordinates: 66 2` 06.66`` N 8 4` 57.97`` E UTM coordinates: 7324321.37 N 458426.47 E UTM zone: 32 Drilled in production licence: 128 Area: NORWEGIAN SEA Discovery: 6608/10 2 NORNE Field: NORNE Drill permit: 753 L Drilling facility: ROSS RIG Drilling days: 64 Wellbore entry date: 07.01.1993 Wellbore completion date: 11.03.1993 Original wellbore purpose: APPRAISAL Wellbore purpose: APPRAISAL Wellbore status: SUSP.REENTERED LATER Wellbore contents: OIL/GAS Discovery wellbore: NO Formation/age with hydrocarbons 1: BÅT GP / EARLY JURASSIC Formation/age with hydrocarbons 2: FANGST GP / MIDDLE JURASSIC Seismic location: B 18 83& SP. 1345 Kelly bushing elevation (KB) [m]: 24 Water depth [m]: 382 Total Depth (MD) [m]: 2921 Final vertical depth (TVD) [m]: 2920 Max inclination [ ]: 5.50 Bottom hole temperature [ C]: 115 Oldest penetrated age: EARLY JURASSIC Oldest penetrated formation: ÅRE FM

Well 6608/10 4. Spudded in the end of 1993. This well was drilled in the northeast segment, which is located approximately 3 km east of the main structure. An oil column of 30.5 m was discovered in the same structures as the main field. Figure 1 illustrates the location of the exploration wells. Alternating red and green indicates that there exist both oil and gas. Green represents oil, while red represents gas. Table 3: Detail description of well 6609/10 4 (NPD, 2010) NPDID wellbore: 2256 Well name: 6608/10 4 Drilling operator name: Den norske stats oljeselskap a.s Geodetic datum: ED50 Coordinates: 66 2` 25.26`` N 8 9` 41.74`` E UTM coordinates: 7324847.23 N 462006.74 E UTM zone: 32 Drilled in production licence: 128 Area: NORWEGIAN SEA Discovery: 6608/10 4 Field: NORNE Drill permit: 776 L Drilling facility: ROSS ISLE Drilling days: 82 Wellbore entry date: 15.12.1993 Wellbore completion date: 06.03.1994 Original wellbore purpose: WILDCAT Wellbore purpose: WILDCAT Wellbore status: P&A Wellbore contents: OIL/GAS Discovery wellbore: YES Formation/age with hydrocarbons 1: INTRA MELKE FM SS / MIDDLE JURASSIC Formation/age with hydrocarbons 2: GARN FM / MIDDLE JURASSIC Seismic location: ST 9203 CROSSLINE 2051& INLINE 1230 Kelly bushing elevation (KB) [m]: 23 Water depth [m]: 382 Total Depth (MD) [m]: 2800 Final vertical depth (TVD) [m]: 2800 Max inclination [ ]: 3.30 Bottom hole temperature [ C]: 103 Oldest penetrated age: EARLY JURASSIC Oldest penetrated formation: ÅRE FM

Figure 1: Location of exploration wells [NPD, 2008] Log Data The wells 6608/10 2, 6608/10 3 and 6608/10 4 have been logged with generally good quality. Logs give important data for geophysical interpretation of the area. The different logs used for acquiring data in the field are mentioned below along with the

logging interval given in meter. Tables 4 6 shows the available logs in the observation wells. Table 4: Available logs in the well 6609/10 4 (NPD, 2010) Log type Intervals logged [m] MWD 465 3335 LWD CDR CDN 2100 2573 DIFL ACL GR 867 3661 ZDL GR 867 1525 ZDL CNL CAL GR 1520 2141 ZDL CNL CAL GR 2559 3644 DLL MLL SL 2559 2758 DIPLOG GR 1520 2140 DIPLOG GR 2559 3332 DIPLOG GR 3329 3661 FMT HP GR 2579 2800 FMT HP GR 2650 2650 CBL VDL GR 394 1520 ACBL GR 1563 2559 ACBL GR 2405 3319 VELOCITY 930 3640 Table 5: Available logs in the well 6609/10 3 (NPD, 2010) Log type Intervals logged [m] MWD 472 2920 DIFL ACL ZDL GR 863 1587 CDL CNL GR 1575 2914 DIFL DAC GR 1574 2555 DIPL MAC SL 2430 2915 DLL MLL GR 2539 2800 FMT HP GR 2498 2862 CBL VDL GR 646 2871 DIPLOG GR 1900 2555 HRDIP GR 2563 2905 SWC 894 2901 VSP 1240 2900 Table 6: Available logs in the well 6609/10 4 (NPD, 2010) Log type Intervals logged [m] MWD 477 2558 DIFL MAC SL 2175 2795 ZDL CNL GR 2465 2794 DLL MLL GR 2465 2650 HRDIP GR 1396 2555 FMT GR 2485 2662 CBL VDL GR 800 2746 VSP 500 2750 SWC GR 1430 2774 VELOCITY 930 3640

The layers Ile 2, Ile 1, Tilje 4, Tilje 3 and Tilje 2 are eroded in well 6608/10 4. This can be seen for instance from logs as demonstrated in figure 2, which illustrates correlation of wells in the Norne Area. Figure 2: Correlation of Wells in the Norne Area [Statoil, 1995] Core Data Core data has also been used as a basis for determination of the petrophysical properties of the Norne Field. From well 6608/10 2 there has been cut six cores, eleven cores are cut from well 6608/10 3 and 7 from well 6608/10 4. All this data has been depth shifted to match the ZDL CN GR. Photos of cores from the different formation are included in figures 3 8. Use of core measurements is introducing some uncertainties which should be mentioned. When drilling the cores, the transportation of the cores and the treatment of the core material are vital. When performing measurements on the cores, there can be systematic errors connected to equipment and methods. The plugs may not be of general reservoir quality and will because of that give incorrect results.

Figure 3: Cores from well 6608/10 2, interval 2600 2605 in the Garn Formation [NPD, 2010]. Sandstones deposited near shore with some tidal influence Figure 5: Cores from well 6608/10 2, interval 2627 2632 in the Ile Formation [NPD, 2010]. Sandstones deposited in shoreface environment Figure 4: Cores from well 6608/10 2, interval 2611 2616 in the Not Formation [NPD, 2010]. Grey to black claystone with siltstone lamina, deposited in quiet marine environment Figure 6: Cores from well 6608/10 2, interval 2661 2665 in the Ror Formation [NPD, 2010]. Very fine grained/shaly sand, deposited in lower shoreface environment with low sediment supply

Figure 7: Cores from well 6608/10 2, interval 2724 2729 in the Tilje Formation [NPD, 2010]. Sand, with some clay and conglomerates, deposited in a marginal marine, tidally affected environment Figure 8: Cores from well 6608/10 2, interval 2674 2679 in the Tofte Formation [NPD, 2010]. Channel sandstones

Test Data Well 6608/10 2: Test data from four drillstem tests (DST) has been reported for this well. One of the tests showed evidence of Joule Thomson effect as the temperature decreased when the gas flowed from the reservoir to the wellbore. As this test was performed close to the gas oil contact it is likely that the effect is a result of coning. All the other DST's produced fluids in accordance with the petrophysical evaluation made here [Statoil,1994]. DST 1 tested the interval 2715 2720 m in the lower Tofte Formation. Max bottom hole temperature here was 100 C. 310 Sm 3 water/day was produced through a 2" choke. DST 2 tested the interval 2673 2695 m in the upper Tofte Formation. The production rate measured was 1165 Sm 3 /d oil and 108667 Sm 3 /d gas through a 1.5" choke. Gas Oil Ratio was 93 Sm 3 /Sm 3, oil density was 0.856 g/cm 3, the gas gravity was 0.65 and the gas contained 1.8% CO2 and 4 ppm H2S. Max bottom hole temperature was 98.4 C. DST 3 tested the interval 2605 2610 m in the lower Garn Formation. The test produced 33 Sm 3 condensate and 582600 Sm 3 gas/day through a 19.05 mm choke. Measured GOR was 17654 Sm 3 /Sm 3, and max bottom hole temperature was 91.4 C. DST 3B tested the interval 2590 2603 m in the Garn Formation. Measured rates recorded were 100 Sm 3 /d condensate and 9645000 Sm 3 gas/day through a 38.1 mm choke. GOR were recorded to 9450 Sm 3 /Sm 3. The condensate density was 0.783 g/cm 3, the gas gravity was 0.645 and the gas contained 1.1% CO2 and 0.5 ppm H2S. Maximum bottom hole temperature measured was 95.5 C. [NPD, 2010]. Well 6608/10 3. One drill stem test was carried out in this well. The test was performed in the Ile Formation, in the perforated interval 2617 2648 m. The production was measured to 1250 Sm 3 /d oil with density of 860 kg/m 3 at standard conditions. 102500 Sm 3 /d gas was produced with relative density of 0.65. The choke was of the size 60/64".

Well 6608/10 4. In this well, three drill stem tests were performed. DST 1 tested the Tofte Formation in the interval 2635 2640 m. No formation fluid was produced to the surface. Minifrac tests were performed at the end of this test, and the fracture closing pressure was evaluated to 405 bar. DST 2 tested the Garn Formation in the interval 2566.2 2582.2 m. This test produced a maximum of 900 Sm3/d oil with a density of 858 kg/m3 at standard conditions. 75000 Sm3/d gas with a relative density of 0.648 was measured. The choke was of size 80/64" (31.75 mm). Minifrac tests were performed at the end of this test, and evaluated the fracture closing pressure to be 410 bar. DST 3A tested the Melke Formation. DST 3A in the intervals 2484.5 2599 m and 2505 2514 m. DST DST 3B tested the Melke Formation DST 3B in the intervals 2524 2531 m. No formation fluid was produced to the surface. This test proved that the Melke Formation was tight with oil in place. FMT data The final data type used for the petrophysical evaluation was the Formation Multi Tester (FMT) log. This tool enables confirmation of a water bearing reservoir using pore pressure gradient. It also allows sampling of the formation water. Evaluation of the FMT data gives a base case oil water contact at about 2688.5 m TVD/MSL for both well 6608/10 2 and well 6608/10 3. Well 6608/10 4 had a oil water contact at 2574.5 m. Different gas oil contacts were observed in wells 6608/10 2 and 6608/10 3, while well 6608/10 4 did not contain any gas [Statoil, 1995]. Well 6608/10 2 had a gas oil contact at 2580 m TVD/MSL and in well 6608/10 3 the gasoil contact was at 2575 m TVD/MSL. The FMT data also suggests that there is a small pressure barrier in the northern segment (Segment E), caused by the presence of the Not Formation. Figure 9 illustrates this feature. However, it is shown by fluid analysis that it is the same composition of oil above and below this barrier. The calculated gradients are given in Table 7. Reference depth used in the oil zone was 2639 m and the formation pressure was 273.2 bar. [Statoil, 1994].

Figure 9: Fluid model, from [Statoil, 1994] Table 7: Calculated gradients, with some uncertainty [Statoil, 1994] Fluid Gradient g/cm 3 Oil 0.72 Gas 0.19 Water 1.02 Interpretation parameters The lithology factor, a, the cementation factor, m, and the saturation exponent, n, have been estimated based on core analysis from wells 6608/10 2 and 6608/10 3. For the first two parameters the values were found from plug data with overburden measurements. Estimated values are; a = 1.0 and m = 1.84. The saturation exponents are found for three different zone groups, from Resistivity Index (RI) measurements. The groups and the n values are given in Table 8. Six plugs from group 1, 9 plugs from group 2 and 5 plugs from group 3 are used as a basis for the RI measurements [Statoil, 1994].

Table 8: n values for the zone groups [Statoil, 1994] Group number n value Formation names 1 1.84 Garn 2 & Garn1 Not Ile 3 2 2.02 Ror Tofte 3 2.20 Garn3 Ile 2 & Ile1 Tilje Grain density. The average grain density for the entire reservoir, based on all core data from both wells are ρ ma = 2.67 g/cm 3. Zones of different grain densities are Tofte 3 and 2, 2.65 g/cm 3 and Tofte 1, 2.71 g/cm 3 [Statoil, 1994]. Overburden corrections The overburden pressure was calculated to correct results accordingly. To calculate the overburden pressure, the density logs in wells 6608/10 2 and 6608/10 3 were integrated. A minimum horizontal stress at depth 2673 m of 389 bar was indicated in a minifrac test [Statoil, 1992]. At that depth, the pore pressure was 273 bar, hence the minimum horizontal stress is 116 bar and the difference between the horizontal and the vertical stress is 123.5 bar. Due to rock mechanics the confining pressure will be 123.5/3+116 bar. In [Statoil, 1994] the equations for porosity and permeability are given as: K ref ref 0.976 0.865K atmos 1.004 atmos (1) Water resistivity (Statoil, 1992). The resistivity of the formation water is found from the water sample from DST 1 in well 6608/10 2. It is temperature corrected using Arps formula. The resistivity is: R w 0.054 at 98.3 C (2)

Formation temperature. Both the formation temperature and the temperature gradient were determined from the DST which is 98.3 C at 2639 m TVD/MSL and ΔT=3.5 C per 100m. Porosity. Generation of total porosity is executed by use of the equation φ= a + b ρ b where ρ b is the bulk density, while a and b are constants. Crossplots of overburden corrected core porosity vs. density log are used to find these constants. The constants are found for the different zones, which are grouped together for improving correlations. Some uncertainties are related to the determination of the constants a and b from crossplots [Statoil, 1994]. Fluid contacts there is a common oil water contact at 2688.5 m TVD/MSL for wells 6608/10 2 and 6608/10 3, while well 6608/10 4 had a oil water contact at 2574.5 m and did not contain any gas. There were two different gas oil contacts for wells 6608/10 2 and 6608/10 3; 2580 m and 2575 m respectively. The gas systems seem to be common over the entire field. That is also the case for the oil systems, except the oil above the Not Formation in well 6608/10 3. These contacts were also determined by FMT and DST data. Formation resistivity. Calculations of the true formation resistivity in both the hydrocarbon zones and the water zones were performed. The logs used for the calculations were environmentally corrected. In the hydrocarbon zones the DLL MLL log was used along with [Western Atlas Logging Services, 1985], while the deep induction logs were used for the water zones. Water saturations. Two different models; Archie and Capillary pressure, were used to determine the water saturation. It was assumed that Archie's equation could be used to estimate water saturation in the two wells, and the constant a was treated without uncertainty.

Permeability Log estimations Log estimated permeability was established by use of the relationship between overburden corrected core porosity and overburden corrected core permeability. Log permeabilities in the horizontal and vertical directions were found to be unrelated. Hence, vertical permeability was defined in the same way as the horizontal permeability. It is found that both horizontal and vertical permeability were overestimated in Tilje 3, Tilje 4 and Tofte 3 zones. Core permeability was less than 2000 md in these zones, so the log derived permeability was cut on a maximum value of 2000 md here. In the other zones, the maximum value was 10000 md. Data from well 6608/10 4 were used for determining the permeability in the G segment [Statoil, 1995]. Log/core permeabilities compared to test permeabilities A comparison of the log and core permeabilities and the test permeabilities showed a generally good similarity between log and test data. The k*h product from tests and logs were compared. This was done to verify the quality of the log derived evaluated permeability. The overall impression was that there were a good agreement between k*h products from tests and logs. The arithmetic means of the log permeabilities were closest to the test permeabilities. Use of arithmetic mean in reservoir simulations is recommended. To assure accuracy in the whole field, geometric means may be used in more heterogeneous sections of the reservoir [Statoil, 1994]. Conclusions Permeability Some intervals of the formation have overestimated or underestimated log permeability when comparing with core permeability. Beyond that, there is a good accordance between core and log derived permeabilities. Table 9 gives recommended permeabilities. k*h products resulting from tests and logs have good agreement. The test gives a permeability which lies between arithmetic and geometric mean values determined from logs. However, the permeabilities are closest to the arithmetic mean in all cases. As consequence of that, it has been recommended to use arithmetic means in reservoir simulations [Statoil, 1994].

Table 9: Recommended field values of permeability [Statoil, 1994] Zone KLH arith (md) KLH geo (md) KLH harm (md) Garn 3 2500 1300 200 Garn 2 400 130 17 Garn 1 20 12 5 Not Ile 3 100 65 13 Ile 2 1000 800 75 Ile 1 800 450 150 Ø. Ror 150 100 20 Tofte 3a 1065 850 680 Tofte 3b 200 175 120 Tofte 2 40 25 7.5 Tofte 1 1200 350 19.5 Tilje 4 450 70 2.0 Tilje 3 875 250 12 Tilje 2 400 50 5.8 Tilje 1 2000 650 30 Porosity permeability relations (Statoil, 2001) To estimate the permeability based on the porosity, the linear log relation showed below was used. K = 10 (a1+b1φ) Tables 10 13 includes cut off values for wells 6608/10 2 and 6608/10 3 for both oil and gas. Figures 10 12 show logs from wells 6608/10 2, 6608/10 3 and 6608/10 4, respectively. Table 10: Cut off values, Oil Case, Well 6608/10 2 [Statoil, 1994] Zone Fluid Thickness TVD (m) φ F (fraction) S w (fraction) N/G (fraction) Garn 3 Gas 11.0 0.302 0.121 0.982 Garn 2 Gas 10.3 0.258 0.145 0.844 Garn 1 Gas Oil 5.0 7.2 0.205 0.231 0.249 0.298 0.742 0.305 Not 7.5 0 Ile 3 Oil 21.6 0.247 0.183 0.894 Ile 2 Oil 16.0 0.287 0.123 0.981 Ile 1 Oil 2.9 0.259 0.185 0.828 Ø. Ror Oil 8.6 0.254 0.221 0.907 Tofte 3 Oil 29.1 0.280 0.187 1.00 Tofte 2 Oil 6.6 0.228 0.430 0.985 Tofte 1 Gas Oil 9.0 6.5 0.256 0.248 0.339 0.767 1.00 0.644 Tilje 4 Water 11.3 0.214 0.845 0.796 Tilje 3 Water 22.5 0.250 0.984 0.929 Tilje 2 Water 37.7 0.187 0.922 0.587 Tilje 1 Water 28.2 0.277 0.987 0.847

Table 11: Cut off values, Gas Case, Well 6608/10 2 [Statoil, 1994] Zone Fluid Thickness TVD (m) φ F (fraction) S w (fraction) N/G (fraction) Garn 3 Gas 11.0 0.302 0.121 0.982 Garn 2 Gas 10.3 0.252 0.149 0.893 Garn 1 Gas Oil 5.0 7.2 0.192 0.203 0.270 0.331 0.980 0.791 Not 7.5 0 Ile 3 Oil 21.6 0.240 0.187 0.949 Ile 2 Oil 16.0 0.285 0.124 1.00 Ile 1 Oil 2.9 0.233 0.206 1.00 Ø. Ror Oil 8.6 0.251 0.222 0.930 Tofte 3 Oil 29.1 0.280 0.187 1.00 Tofte 2 Oil 6.6 0.227 0.431 1.00 Tofte 1 Gas Oil 9.0 6.5 0.256 0.212 0.339 0.813 1.00 0.907 Tilje 4 Water 11.3 0.206 0.867 0.867 Tilje 3 Water 22.5 0.245 0.993 0.960 Tilje 2 Water 37.7 0.162 0.971 0.889 Tilje 1 Water 28.2 0.265 0.997 0.911 Table 12: Cut off values, Oil Case, Well 6608/10 3 [Statoil, 1994] Zone Fluid Thickness TVD (m) φ F (fraction) S w (fraction) N/G (fraction) Garn 3 Gas 9.9 0.325 0.112 0.998 Garn 2 Gas 9.8 0.276 0.130 0.673 Garn 1 Gas Oil 7.6 9.0 0.252 0.241 0.204 0.259 0.960 0.486 Not 7.3 0 Ile 3 Oil 16.9 0.236 0.225 0.826 Ile 2 Oil 11.0 0.279 0.149 1.00 Ile 1 Oil 3.5 0.269 0.173 0.914 Ø. Ror Oil 8.4 0.234 0.258 0.819 Tofte 3 Oil 28.5 0.276 0.170 1.00 Tofte 2 Oil 6.1 0.231 0.359 1.00 Tofte 1 Gas & Oil 14.9 0.262 0.239 0.898 Tilje 4 Water 6.9 0.235 0.568 0.716 Tilje 3 Water 18.0 0.266 0.937 0.897 Tilje 2 Water 34.4 0.223 0.958 0.672 Tilje 1 Water 25.6 0.272 0.987 0.830

Table 13: Cut off values, Gas Case, Well 6608/10 3 [Statoil, 1994] Zone Fluid Thickness TVD (m) φ F (fraction) S w (fraction) N/G (fraction) Garn 3 Gas 9.9 0.325 0.112 0.998 Garn 2 Gas 9.8 0.266 0.144 0.751 Garn 1 Gas Oil 7.6 9.0 0.252 0.226 0.204 0.301 0.960 0.774 Not 7.3 0 Ile 3 Oil 16.9 0.229 0.231 0.943 Ile 2 Oil 11.0 0.279 0.149 1.00 Ile 1 Oil 3.5 0.254 0.183 1.00 Ø. Ror Oil 8.4 0.225 0.269 0.946 Tofte 3 Oil 28.5 0.276 0.170 1.00 Tofte 2 Oil 6.1 0.231 0.359 1.00 Tofte 1 Gas & Oil 14.9 0.250 0.248 0.990 Tilje 4 Water 6.9 0.215 0.605 0.934 Tilje 3 Water 18.0 0.258 0.957 0.949 Tilje 2 Water 34.4 0.203 1.00 0.858 Tilje 1 Water 25.6 0.260 1.00 0.901 Figure 10: CPI plot Well 6608/10 2 [Statoil, 1994]

Figure 11: Log from NPD Well 6608/10 3 [NPD, 2010]

Figure 12: Log from NPD Well 6608/10 4 [NPD, 2010] PVT properties: Some properties of the oil and gas in the Norne Field are: Initial pressure: 273 bar at 2639 m TVD Reservoir temperature: 98 C Oil density: 859.5 Kg/m3 API= 32.7 Gas density: 0.854 Kg/m3

Water density: 1033 Kg/m3 Oil formation volume factor: 1.32 Gas formation volume factor: 0.0047 Rock wettability: mixed Pore Compressibility: 4.84 10 5 1/bar at 277 bar Figure 13 and 14 represent some of the PVT properties, relative permeabilities and capillary pressures related to E Segment. Connate water saturation is varies from 0.05 to 0.38 among different relative permeability curves. Figure 13: PVT properties for the E segment in Norne Filed

Figure 14: Relative permeabilities (top) and capillary pressures (Bottom) for the E segment in Norne Filed References: This document is a part of Chapter 3 of a master thesis from Verlo and Hetlad 2008 which is done at NTNU. Statoil, 1992. Discovery Evaluation Report, Well 6608/10 2. Statoil, 1994. Plan for Development and Operation, Reservoir Geology, Support Documentation Statoil, 1995. Reservoir Geological Update After 6608/10 4. Statoil, 2001. PL128 Norne Field Reservoir Management Plan Verlo, S. B. and Hetland, M. 2008. Development of a field case with real production and 4D data from the Norne Field as a benchmark case for future reservoir simulation models testing. Masters Thesis, NTNU, Norway. Western Atlas Logging Services, 1985. Log Interpretation Charts.