Petrophysical information (Verlo and Hatland, 2008)

Transcription

1 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 , 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

2 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: N 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: Wellbore completion date: 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

3 Well 6608/10 3. Spudded in: January 1993 Total Depth (TD) was reached at 2991 m February 19 th 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: N 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: Wellbore completion date: 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 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

4 Well 6608/10 4. Spudded in the end of 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: N 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: Wellbore completion date: 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

5 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

6 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 LWD CDR CDN DIFL ACL GR ZDL GR ZDL CNL CAL GR ZDL CNL CAL GR DLL MLL SL DIPLOG GR DIPLOG GR DIPLOG GR FMT HP GR FMT HP GR CBL VDL GR ACBL GR ACBL GR VELOCITY Table 5: Available logs in the well 6609/10 3 (NPD, 2010) Log type Intervals logged [m] MWD DIFL ACL ZDL GR CDL CNL GR DIFL DAC GR DIPL MAC SL DLL MLL GR FMT HP GR CBL VDL GR DIPLOG GR HRDIP GR SWC VSP Table 6: Available logs in the well 6609/10 4 (NPD, 2010) Log type Intervals logged [m] MWD DIFL MAC SL ZDL CNL GR DLL MLL GR HRDIP GR FMT GR CBL VDL GR VSP SWC GR VELOCITY

7 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.

8 Figure 3: Cores from well 6608/10 2, interval in the Garn Formation [NPD, 2010]. Sandstones deposited near shore with some tidal influence Figure 5: Cores from well 6608/10 2, interval in the Ile Formation [NPD, 2010]. Sandstones deposited in shoreface environment Figure 4: Cores from well 6608/10 2, interval 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 in the Ror Formation [NPD, 2010]. Very fine grained/shaly sand, deposited in lower shoreface environment with low sediment supply

9 Figure 7: Cores from well 6608/10 2, interval 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 in the Tofte Formation [NPD, 2010]. Channel sandstones

10 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 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 m in the upper Tofte Formation. The production rate measured was 1165 Sm 3 /d oil and Sm 3 /d gas through a 1.5" choke. Gas Oil Ratio was 93 Sm 3 /Sm 3, oil density was 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 m in the lower Garn Formation. The test produced 33 Sm 3 condensate and Sm 3 gas/day through a mm choke. Measured GOR was Sm 3 /Sm 3, and max bottom hole temperature was 91.4 C. DST 3B tested the interval m in the Garn Formation. Measured rates recorded were 100 Sm 3 /d condensate and Sm 3 gas/day through a 38.1 mm choke. GOR were recorded to 9450 Sm 3 /Sm 3. The condensate density was g/cm 3, the gas gravity was 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 m. The production was measured to 1250 Sm 3 /d oil with density of 860 kg/m 3 at standard conditions Sm 3 /d gas was produced with relative density of The choke was of the size 60/64".

11 Well 6608/10 4. In this well, three drill stem tests were performed. DST 1 tested the Tofte Formation in the interval 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 m. This test produced a maximum of 900 Sm3/d oil with a density of 858 kg/m3 at standard conditions Sm3/d gas with a relative density of 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 m and m. DST DST 3B tested the Melke Formation DST 3B in the intervals 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 m TVD/MSL for both well 6608/10 2 and well 6608/10 3. Well 6608/10 4 had a oil water contact at 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 bar. [Statoil, 1994].

12 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 = 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].

13 Table 8: n values for the zone groups [Statoil, 1994] Group number n value Formation names Garn 2 & Garn1 Not Ile Ror Tofte 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 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 K atmos 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 at 98.3 C (2)

14 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 m TVD/MSL for wells 6608/10 2 and 6608/10 3, while well 6608/10 4 had a oil water contact at 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.

15 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 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].

16 Table 9: Recommended field values of permeability [Statoil, 1994] Zone KLH arith (md) KLH geo (md) KLH harm (md) Garn Garn Garn Not Ile Ile Ile Ø. Ror Tofte 3a Tofte 3b Tofte Tofte Tilje Tilje Tilje Tilje 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 includes cut off values for wells 6608/10 2 and 6608/10 3 for both oil and gas. Figures 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 Garn 2 Gas Garn 1 Gas Oil Not Ile 3 Oil Ile 2 Oil Ile 1 Oil Ø. Ror Oil Tofte 3 Oil Tofte 2 Oil Tofte 1 Gas Oil Tilje 4 Water Tilje 3 Water Tilje 2 Water Tilje 1 Water

17 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 Garn 2 Gas Garn 1 Gas Oil Not Ile 3 Oil Ile 2 Oil Ile 1 Oil Ø. Ror Oil Tofte 3 Oil Tofte 2 Oil Tofte 1 Gas Oil Tilje 4 Water Tilje 3 Water Tilje 2 Water Tilje 1 Water 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 Garn 2 Gas Garn 1 Gas Oil Not Ile 3 Oil Ile 2 Oil Ile 1 Oil Ø. Ror Oil Tofte 3 Oil Tofte 2 Oil Tofte 1 Gas & Oil Tilje 4 Water Tilje 3 Water Tilje 2 Water Tilje 1 Water

18 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 Garn 2 Gas Garn 1 Gas Oil Not Ile 3 Oil Ile 2 Oil Ile 1 Oil Ø. Ror Oil Tofte 3 Oil Tofte 2 Oil Tofte 1 Gas & Oil Tilje 4 Water Tilje 3 Water Tilje 2 Water Tilje 1 Water Figure 10: CPI plot Well 6608/10 2 [Statoil, 1994]

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

20 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: Kg/m3 API= 32.7 Gas density: Kg/m3

21 Water density: 1033 Kg/m3 Oil formation volume factor: 1.32 Gas formation volume factor: Rock wettability: mixed Pore Compressibility: /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

22 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, Discovery Evaluation Report, Well 6608/10 2. Statoil, Plan for Development and Operation, Reservoir Geology, Support Documentation Statoil, Reservoir Geological Update After 6608/10 4. Statoil, PL128 Norne Field Reservoir Management Plan Verlo, S. B. and Hetland, M 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, Log Interpretation Charts.