diff --git "a/knowledge_base/raw_text/Discovery_report.pdf.txt" "b/knowledge_base/raw_text/Discovery_report.pdf.txt" new file mode 100644--- /dev/null +++ "b/knowledge_base/raw_text/Discovery_report.pdf.txt" @@ -0,0 +1,5591 @@ +Denne rapport +6 STATOIL +tilhører +LTEK DOK.SENTER +DISCOVERY EVALUATION +RETURNERES ETTER BRUK +WELL 15/9-19 SR +Theta Vest Structure - PL046A +ICC +Esso +TOTAL +STATOIL +HYDRO +VOLUME l +(Text, tables and figures) +Duplikat Grad.: +STATOIL +DISCOVERY EVALUATION REPORT +WELL 15/9-19 SR +Theta Vest Structure - PL046A +X(C +Esso TOTAL +STATOIL +HYDRO +VOLUME l +(Text, tables and figures) +STATOIL +DISCOVERY EVALUATION REPORT +WELL 15/9-19 SR +Theta Vest Structure +PL 046 +STATOIL 1993 +Contributions bv: +Project leader: Malm, O.A. +Report compilation: Blekastad, T. +Reservoir geology: Blekastad, T. +Seismic interpretation: Idsø, D. & Skole, B. +Structural core description: Pallesen, S. & Ottesen, S. +Biostratigraphy: Milner, P. +Core sedimentology Allers, J.E. +Petrography: Nadeau, P. +Petrophysics: Logstein, J.l. +Drill stem testing: Gjessing, K. +Geochemistry: Patience, R. +Text contributions: Malm, O.A. +STATOIL +Title +DISCOVERY EVALUATION REPORT +WELL 15/9-19 SR +Theta Vest Structure +PL046 +Prepared by Date No. of pages No. of enclosures +SLEIPNER PETEK Dec. 1993 190 19 +Key words +PL 046, Sleipner, Exploration, Well 15/9-19 SR, Theta Vest +structure, Oil, Discovery, Jurassic, Hugin Formation, +ST8215R, Seismic interpretation, Structural geology, +Tectonic development, Biostratigraphy, Sedimentology, +Petrography, Geochemistry, Petrophysics, Drill stem testing, +Resources. +Abstract +Exploration well 15/9-19 SR, drilled to the Theta Vest +structure in the Sleipner area, encountered oil in the +Jurassic Hugin Formation. The drill stem test showed very +good production capacities through time, with low water cut +and low GOR. A comprehensive study of the structure and the +discovery has been performed and is reported. This includes +seismic and structural interpretations, biostratigraphy, +sedimentology, petrography, geochemistry, petrophysics, test +analysis and resource estimation. The resources are +calculated to 10.3 million Sm3 oil in place and 4.55 million +Sm3 oil recoverable. +Recommended by Date Approved by Date +Ove A. Malm 16.12.93 Sigve Haaland, 16.12.93 +G&G Supervisor r'etr. ?Tech. Manager +Sleipner Production Sleipner Production +O STATOIL +TABLE OF CONTENTS +Volume 1 +1 SUMMARY 10 +2 INTRODUCTION 12 +3 SEISMIC INTERPRETATION AND MAPPING 16 +3.1 Seismic database 16 +3.2 VSP 16 +3.3 Seismic interpretation 16 +3.3.1 Top Heimdal Formation 17 +3.3.2 Top Shetland Group 17 +3.3.3 Top Blodøks Formation 17 +3.3.4 Base Cretaceous Unconformity 17 +3.3.5 Top Mesozoic Sandstone 18 +3.3.6 Other horizons 18 +3.4 Depth conversion 19 +4 STRUCTURAL INTERPRETATION AND TECTONIC DEVELOPMENT 33 +4.1 Structural core description 33 +4.2 Estimate of tectonic thinning of the Hugin Fm. in the position of well +15/9-19 SR 35 +4.3 Structural and tectonic development 36 +4.3.1 Regional setting 36 +4.3.2 The main fault zone 36 +4.3.3 The Sleipner Terrace area 37 +4.3.4 The Gamma High 38 +4.3.5 Structural links between the Gamma High and the Sleipner +Terrace 38 +4.4 Tectonic history 39 +4.4.1 Paleozoicum 39 +4.4.2 Mesozoicum 40 +4.4.3 Cenozoicum 40 +4.4.4 Tectonic development of the Gamma High 41 +5 GEOLOGICAL INTERPRETATION 58 +5.1 Introduction 58 +5.2 Biostratigraphy 58 +5.2.1 Chronostratigraphy 59 +5.2.2 Palynological events 59 +5.2.3 Palaeo-environmental comments 59 +5.2.4 Comparison with 15/9-9, -11, -13, -15, -16 and -17 wells ... 60 +5.2.5 Biostratigraphy of the 15/9-9, 11, 13, 15, 16 and 17 wells ... 61 +5.3 Lithostratigraphy 64 +5.3.1 The Nordland Group (84.0 - 1034.3 mMSL) 66 +5.3.2 The Hordaland Group (1034.3 - 2206.8 mMSL) 66 +STATOIL +5.3.3 The Rogaland Group (2206.8 - 2527.6 mMSL) 66 +5.3.4 The Shetland Group (2527.6 - 2758.6 mMSL) 67 +5.3.5 The Gromer Knoll Group (2758.6 - 2854.4 mMSL) 67 +5.3.6 The Viking Group (2854.4 - 2864.0 mMSL) 68 +5.3.7 The Vestland Group (2864.0 - 2882.0 mMSL) 68 +5.3.8 The Triassic (2882.0 - 3110.3 mMSL) 68 +5.4 Core description and sedimentology 69 +5.4.1 The Triassic section, the Skagerrak Formation 69 +5.4.2 The Jurassic section, the Hugin Formation 70 +5.4.3 Conclusions 72 +5.5 Mineralogy and petrology 72 +5.5.1 The Heimdal Formation (Rogaland Gp., 3643.00-3645.50 m) . 72 +5.5.2 The Hugin Formation (Vestland Gp., 4328.85-4343.25 m) . . . 73 +5.5.3 The Skagerrak Formation (Hegre Gp., 4344.25-4354.00 m) . . 74 +5.6 Jurassic and Triassic sediment distribution on the Gamma High ... 77 +5.6.1 Deposition of Jurassic and Triassic sediments 77 +5.6.2 Jurassic and Triassic stratigraphy in the wells 78 +5.6.3 Lithostratigraphic correlation 82 +5.6.4 Fades relations, depositional environment and sediment +distribution 82 +6 PETROPHYSICAL EVALUATION 101 +6.1 Petrophysical analysis 101 +6.2 Formations parameters 101 +6.3 Formation temperature 102 +6.4 Results 102 +7 DRILL STEM TESTING 106 +7.1 DST #1 106 +7.1.1 Summary of analysis 106 +7.1.2 Objectives 107 +7.1.3 Test performance 107 +7.1.4 Analysis 108 +8 GEOCHEMISTRY 117 +8.1 Geochemical properties of gas from DST#1, well 15/9-19 SR 117 +8.2 Geochemical properties of oil from DST#1, well 15/9-19 SR 117 +8.2.1 Bulk composition 117 +8.2.2 Molecular composition 118 +8.3 Thermal maturity 118 +8.3.1 Gas 118 +8.3.2 Oil 119 +8.4 Source classification , 119 +8.4.1 Gas 119 +8.4.2 Oil 119 +8.5 Comparison of Theta Vest with Sleipner Øst, Loke and Sleipner +Vest 120 +8.5.1 Sleipner Øst and Loke 120 +STATOIL +8.5.2 Sleipner Vest 121 +8.5.3 Comparison with Theta Vest 121 +9 DEFINITION OF DISCOVERIES, PROSPECTS AND LEADS AS A BASIS FOR +RESOURCE ANALYSIS 150 +9.1 Definition of structures 150 +9.1.1 Faults and fault directions 150 +9.1.2 Lineaments 150 +9.1.3 Isochores 151 +9.1.4 Depth maps 151 +9.1.5 Structural areas 152 +9.2 Evaluation of hydrocarbon source, migration and spill routes 155 +9.2.1 Source rocks 155 +9.2.2 Source areas 156 +9.2.3 Migration paths 157 +9.2.4 Spill routes 158 +9.2.5 Pressure 159 +9.3 Definition of prospects and leads 160 +10 RESOURCE AND PROBABILITY ESTIMATION 168 +10.1 The Theta Vest discovery 168 +10.2 The western and eastern segments of the Theta Vest structure .... 171 +10.3 The Theta C prospect 171 +10.4 The Theta Sør prospect 173 +11 FUTURE STUDIES AND EXPLORATION 186 +11.1 Introduction 186 +11.2 Evaluations based on the present data 186 +11.3 Acquisition of new data 187 +11.3.1 New seismic data 187 +11.3.2 New well data 187 +11.4 Evaluations based on new data 187 +12 REFERENCES 188 +STATOIL +LIST OF FIGURES +Figure 2.1 Location of well 15/9-19 SR 13 +Figure 2.2 The Sleipner Øst area 14 +Figure 2.3 Structural cross-section along the 15/9-19 SR well path 15 +Figure 3.1 Composite plot of VSP and random line along wellpath 21 +Figure 3.2 Synthetic seismogram (seismic tie to well) 22 +Figure 3.3 V map, Top Heimdal Formation 23 +0 +Figure 3.4 Structural depth map, Top Heimdal Formation 24 +Figure 3.5 Structural depth map, Base Cretaceous Unconformity 25 +Figure 3.6 Seismic crossline 491 through the 15/9-19 SR well 26 +Figure 3.7 Amplitude map, Base Cretaceous Unconformity 27 +Figure 3.8 Time map, Top Mesozoic Sandstone 28 +Figure 3.9 Structural depth map, Top Mesozoic Sandstone 29 +Figure 3.10 Result from add-linvel analysis down to Top Heimdal Formation. ... 30 +Figure 3.11 Time/Depth and Velocity plot 15/9-19 SR 31 +Figure 3.12 Location map of the profiles and the seismic sections 32 +Figure 4.1 Fracture frequencies along 1 meter intervals of cores 2 and 3 43 +Figure 4.2 Core photograph from the Hugin Formation, at 4336.59-4336.80 m MD +RKB 44 +Figure 4.3 Thin-section photograph 100X magnification from the Hugin Formation +at 4336.84 m MD RKB 45 +Figure 4.4 Fault with clay smear and striations in the Triassic at 4345 m MD +RKB 46 +Figure 4.5 Small faults in the Hugin Fm. at 4334 m MD RKB 47 +Figure 4.6 The present day structural framework map 48 +Figure 4.7 Structural setting of the Sleipner Complex 49 +Figure 4.8 Simplified map of the main faults and lineaments in the Sleipner +area 50 +Figure 4.9 Structural depth map, Top Rotliegendes 51 +Figure 4.10 Isochore, Top Rotliegendes - Base Cretaceous Unconformity 52 +Figure 4.11 Seismic inline 510 through Theta Vest and Sleipner Øst 53 +Figure 4.12 Seismic crossline 445 through well 15/9-17 54 +Figure 4.13 Structural cross section through well path 15/9-19 SR 55 +Figure 4.14 Seismic inline 703 in the Sleipner Øst area 56 +Figure 4.15 Seismic inline through wells 15/9-19 SR (Theta Vest) and 15/9-11 +(Sleipner Øst) 57 +Figure 5.1 Middle to late Jurassic chronostratigraphy in the Sleipner area. .... 86 +Figure 5.2 Drilling prognosis versus drilling results 87 +Figure 5.3 Legend of core description 88 +Figure 5.4 Core description of the Hugin and the Skagerrak Formation, well 15/9- +19 SR, scale 1:50 89 +Figure 5.5 Optical micrograph from the Heimdal Formation, well 15/9-19 SR, from +3644.50 m, plug no. 7 91 +Figure 5.6 Scanning Electron Micrographs, Heimdal Formation, well 15/9-19 SR, +from 3644.50 m, plug No. 7 92 +STATOIL +Figure 5.7 Geologic controls on reservoir quality of the Hugin Formation, well +15/9-19 SR 93 +Figure 5.8 Optical micrograph from the Hugin Formation, well 15/9-19 SR, from +4330.25 m, plug no. 20 94 +Figure 5.9 Optical micrograph from the Hugin Formation, well 15/9-19 SR, from +4331.25 m, plug no. 24 95 +Figure 5.10 Optical micrograph from the Hugin Formation, well 15/9-19 SR, from +4333.25 m, plug no. 32 96 +Figure 5.11 Hydrocarbon columns of the Jurassic and Triassic reservoirs in the +Sleipner Øst area 97 +Figure 5.12 Paleogeography of the Late Callovian regressive systems tract (max +progradation) 98 +Figure 5.13 Paleogeography of the Mid Oxfordian regressive systems tract (max. +progradation) 99 +Figure 5.14 Isochore map, Base Cretaceous Unconformity - Top Mesozoic +Sandstone 100 +Figure 6.1 Log and core presentation of the Hugin and the Skagerrak +Formations, well 15/9-19 SR 104 +Figure 6.2 CPI plott through the Hugin Formation, well 15/9-19 SR 105 +Figure 7.1 The performance of bottomhole pressure and temperature for the +whole test period 113 +Figure 7.2 The Semi Log Analysis 114 +Figure 7.3 The pressure data with the Type Curve match 115 +Figure 7.4 The Semi Log Analysis matched with synthetic generated data 116 +Figure 8.1 Chemical composition of gas from DST#1, well 15/9-19 SR 134 +Figure 8.2 Isotopic composition of gas from DST#1, well 15/9-19 SR 135 +Figure 8.3 Carbon isotopic composition of oil and fractions from well 15/9-19 +SR 136 +Figure 8.4 Gas chromatogram of the saturated hydrocarbon fraction from DST#1 +oil, well 15/9-19 SR 137 +Figure 8.5 Gas chromatogram of the aromatic hydrocarbon fraction from DST#1 +oil, well 15/9-19 SR 138 +Figure 8.6A Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - long plots 139 +Figure 8.6B Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - short plots 140 +Figure 8.6C Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - short plots 141 +Figure 8.6D Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - short plots 142 +Figure 8.6E Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - short plots 143 +Figure 8.7A Mass fragmentograms from GCMS analysis of aromatic hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR 144 +Figure 8.7B Mass fragmentograms from GCMS analysis of aromatic hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR 145 +Figure 8.7C Mass fragmentograms from GCMS analysis of aromatic hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR 146 +STATOIL +Figure 8.7D Mass fragmentograms from GCMS analysis of aromatic hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR 147 +Figure 8.8 Classification of fluid types on Sleipner Øst, Vest, Loke and Theta +Vest according to source rock type and thermal maturity 148 +Figure 8.9 Plot of CO concentrations vs carbon isotope composition for all +2 +samples from Sleipner Øst, Vest, Loke and Theta Vest 149 +Figure 9.1 Isochore map, Top Shetland - Base Cretaceous Unconformity 162 +Figure 9.2 Isochore map, Top Shetland - Top Blodøks 163 +Figure 9.3 Isochore map, Top Blodøks - Base Cretaceous Unconformity 164 +Figure 9.4 Structural depth map of the Top Mesozoic Sandstone with the defined +polygons 165 +Figure 9.5 Suggested migration paths and spill routes in the Sleipner area. ... 166 +Figure 9.6 Fluid gradients of the Jurassic/Triassic reservoirs in the Sleipner Øst +wells 167 +Figure 10.1 Prospect map, Theta Vest 180 +Figure 10.2 Frequency plot of plug and log derived porosity values from the Hugin +Formation, well 15/9-19 SR 181 +Figure 10.3 Histogram plot of log derived water saturation values from the Hugin +Formation, well 15/9-19 SR 182 +Figure 10.4 Segment map, Theta Vest 183 +Figure 10.5 Frequency plot of plug and log derived porosity values from the Hugin +Formation in the Sleipner Vest wells 184 +Figure 10.6 Histogram plot of log derived water saturation values from the Hugin +Formation in the Sleipner Vest wells 185 +IL +^^^^^^^^^^^^^^^^^^1 STATO +LIST OF TABLES +Table 5.1 15/9-19 SR, biostratigraphy, Statoil 1993 59 +Table 5.2 15/9-9, biostratigraphy, RRI (1981) 61 +Table 5.3 15/9-11, biostratigraphy, RRI (1982a) 62 +Table 5.4 15/9-13, biostratigraphy, RRI (1982b) 63 +Table 5.5 15/9-15, biostratigraphy, RRI (1982c) 63 +Table 5.6 15/9-16, biostratigraphy, RRI (1983a) 64 +Table 5.7 15/9-17, biostratigraphy, RRI (1983b) and Statoil 1993 64 +Table 5.8 Table of lithostratigraphy, well 15/9-19 SR 65 +Table 5.9 Core record, well 15/9-19 SR 69 +Table 5.10 Whole rock x-ray diffraction analyses data in semiquantitative weight +percent 75 +Table 5.11 Petrographic point count data (300 count) in volume percent 76 +Table 5.12 Thicknesses of the Draupne, Heather and Hugin Formations observed +in the 15/9 exploration wells in the Sleipner Øst area 81 +Table 6.1 Arithmetic mean 102 +Table 6.2 Mean of petrophysical results for the Hugin Fm. of 15/9-19 SR. . . . 103 +Table 7.1 Results from the testing phase and analysis 106 +Table 7.2 The rates, pressures and flow periods 108 +Table 7.3 Input parameters used for the analysis 108 +Table 7.4 Composition of reservoir fluid (from recombined separator +samples) 110 +Table 7.5 Results bottomhole samples 111 +Table 7.6 Results bottomhole samples 112 +Table 8.1 Available gas and oil samples from well 15/9-19 SR 123 +Table 8.2 Chemical and isotopic composition of gases from DST#1, well 15/9- +19 SR1 124 +Table 8.3 Bulk composition data for oil sample from well 15/9-19 SR 125 +Table 8.4 Isotopic composition data for oil sample and fractions from well 15/9- +19 SR1 125 +Table 8.5 Thompson's indices1 from light hydrocarbons analysis of oil sample +from well 15/9-19 SR 126 +Table 8.6 Data from GC analysis of whole oil and saturates fraction, well 1 5/9- +19 SR 127 +Table 8.7 Data from GC analysis of aromatics fraction from oil, well 15/9-19 +SR 127 +Table 8.8 Biomarker parameters from GCMS analysis of saturated hydrocarbon +fraction of oil from well 15/9-19 SR 128 +Table 8.9 Biomarker parameters from GCMS analysis of aromatic hydrocarbon +fraction of oil from well 15/9-19 SR 132 +Table 9.1 Pressure in adjacent wells 160 +Table 10.1 Estimation of resources for the Theta Vest prospect 175 +Table 10.2 Estimation of resources for the western segment of the Theta Vest +structure 176 +Table 10.3 Estimation of resources for the eastern segment of the Theta Vest +structure 177 +STATOIL +Table 10.4 Estimation of resources for the Theta C prospect 178 +Table 10.5 Estimation of resources for the Theta Sør prospect 179 +CJ STATOIL +Volume 2 +ENCLOSURES +1 V map, Top Heimdal Formation. Scale 1:25000. +0 +2 Structural depth map, Top Heimdal Formation. Scale 125000. +3 Structural depth map, Base Cretaceous Unconformity. Scale 1:50000. +4 Time map, Top Mesozoic Sandstone. Scale 1:25000. +5 Structural depth map, Top Mesozoic Sandstone. Scale 125000. +6 Amplitude map, Top Mesozoic Sandstone. Scale 1:25000. +7 Dip map, Top Mesozoic Sandstone. Scale 1:25000. +8 Azimuth map, Top Mesozoic Sandstone. Scale 1:25000. +9 Amplitude map, Base Cretaceous Unconformity. Scale 1:25000. +10 Dip map, Base Cretaceous Unconformity. Scale 1:25000. +11 Azimuth map, Base Cretaceous Unconformity. Scale 1:25000. +12 Structural depth map, Top Rotliegende. Scale 1:25000. +13 Composite plott, well 15/9-19 SR. Scale 1200. +14 Lithostratigraphic correlation. Scale 1:2000. +15 Lineament map. Scale 1:25000. +16 Isochore map, Top Shetland Gr. - Base Cretaceous Unconformity. Scale 1:25000. +17 Isochore map, Top Shetland Gr. - Top Blodøks Fm.. Scale 125000. +18 Isochore map, Top Blodøks Fm. - Base Cretaceous Unconformity. Scale 125000. +19 Isochore map, Base Cretaceous Unconformity - Top Mesozoic Sandstone. Scale +125000. +STATOIL +1 SUMMARY +The hydrocarbon discovery of exploration well 15/9-19 SR has been evaluated. A +comprehensive analysis has been performed including seismic and structural interpretation, +biostratigraphy, sedimentology, petrography, petrophysics, DST-test analysis and +geochemistry. Finally, a resource analysis of the discovery and associated prospects has +been performed. +The exploration well 15/9-19 SR is located on the Theta Vest structure in the Sleipner Øst +area. The well proved oil in Jurassic sandstones of the Hugin Formation. The 18 meter +thick Hugin Formation was found to be completely filled with hydrocarbons to its base at +2882.0 m MSL TD was reached in Triassic sediments at 3110.3 m MSL. +The primary objective of the well was to test the hydrocarbon potential in the Heimdal +Formation of Paleocene age, which is the main reservoir for gas and condensate in the +Sleipner Øst area. The formation was found deeper than prognosed and was water wet. +The secondary objective of the well was to test the hydrocarbon potential of the +Jurassic/Triassic. +Well planning on the Theta Vest structure was based on interpretation of reprocessed +ST8215R 3D survey data from 1991. The Top Hugin Formation horizon has been mapped +after the well was drilled. Because of limited resolution of the seismic data and a weak +reflector, the horizon has been difficult to interpret consistently. +The Theta Vest structure and the oil trap is a dome-shaped structure. The structure has +a well defined spill point to the east and is as a base case believed to be filled down to +this point. However, several faults cutting the crest of the structure could be sealing the +hydrocarbon accumulation off from spilling eastwards. +The core logging, covering the lower part of the Middle Jurassic Hugin Formation and the +uppermost part of the Triassic Skagerrak Formation, shows a high frequence of fractures +in the cores. This indicates penetration of a zone of intense and complex faulting. The +unfaulted thickness of the Hugin Formation has been estimated. The application of a pure +or simple shear model, gives an unfaulted thickness in the range of 24 to 27 meters. +The Hugin Formation in the 15/9-19 SR well is Callovian in age, probably of Late +Callovian. The sandstones are interpreted to be deposited in a high energy marine +environment, possibly a mouthbar setting. +The reservoir interval consists of highly variable fine to coarse grained, well to poorly +sorted, subarkosic arenite sandstones with good to excellent reservoir properties. The +underlying Skagerrak Formation is completely tight due to extensive kaolinite and dolomite +cementation. +Within the Sleipner Øst area, the Jurassic and Triassic reservoir distribution is complicated +10 +STATOIL +due to syndepositional tectonics and later erosion. The Hugin Formation sandstones are +only identified in three of the wells in the area. The scattered well data and poor seismic +resolution of the Jurassic and Triassic levels, make the mapping of sedimentary facies and +thickness distribution of the Hugin Formation very uncertain. +The Hugin Formation of the area consists of shallow marine shoreface, coastal +plain/lagoonal, channel and possibly mouth bar deposits. It is suggested that a mouth bar +system can have been developed in the Theta Vest area during the early stages of sea +transgression onto the Gamma High area. The Theta Vest area may represent a site for +increased sand thickness compared to what is observed elsewhere on the Gamma High. +The petrophysical analysis of the Hugin Formation in the 15/9-19 SR well, results in a +mean net/gross of 0.924, a porosity of 22.6%, a permeability of 2913.2 mD and a water +saturation of 11.0%. +One drill stem test has been carried out in the interval 2863.6 - 2880.5 m TVD MSL The +maximum rate recorded is 1358 Sm3/d. The permeabilities estimated from the build-up +analyses are approximately 914 mD. The extrapolated reservoir pressure is calculated to +327.7 bar. +The oil and gas from Theta Vest have geochemical characteristics which are unlike those +for any other fluids found elsewhere in the Sleipner area. The oil properties are consistent +in indicating that this sample was generated from a non-clastic marine source rock or +Jurassic shales (Draupne Fm.) of an unusual facies composition. +The Theta Vest area has been evaluated with respect to potentially prospects and leads. +Resource estimates have been calculated for each prospect. The calculated resource +estimates are Monte Carlo simulated results. The most probable resource estimate for the +Hugin reservoir in the Theta Vest structure is 10.33x1O'Sm3 oil In place and 1.65x10'Sm3 +associated gas phase in place. A recovery factor of 45% gives 4.55x10'Sm3 recoverable +oil and 0.72x10'Sm3 recoverable associated gas phase. The estimates are based on the +assumption that the oil-water contact is governed by the spill point of the Theta Vest +structure. If the faults cutting the structure are sealing, several of the fault segments north, +west and south of the Theta Vest structure can be hydrocarbon bearing. This would +increase the resource potential of the area by several orders of magnitude. +The evaluation of the Jurassic and Triassic reservoirs in the Sleipner Øst area will be +continued on the present data. When new seismic and well data become available in 1994- +96, the area and the Theta Vest structure will be reevaluated. +11 +STATOIL +2 INTRODUCTION +This report provides an evaluation of the 15/9-19 SR hydrocarbon discovery. +The exploration well 15/9-19 SR is situated on the Theta Vest structure, which is located +between the Loke structure and the north-westerly extension of the Sleipner Øst structure. +Figure 2.1 shows the location of well 15/9-19 SR together with other drilled exploration +wells in the neighbouring area. +Block 15/9 was awarded in 1976, together with block 15/8, as Production License 046. The +Theta Vest structure is located outside the area declared commercial (see Figure 2.2), with +the following ownerships: +Statoil (operator) 52.6% +Esso 28.0% +Norsk Hydro 9.4% +Elf 9.0% +Total 1.0% +The drilling of the 15/9-19 SR well was performed by the rig "Treasure Prospect" at a +water depth of 84 m. The well was drilled through the Loke Template situated +approximately 3 km east of the well target. The maximum deviation during drilling was 61.4 +degrees from vertical. +The primary objective of the well was to test the hydrocarbon potential in the Heimdal +Formation of Paleocene age, which is the main reservoir in the Sleipner Øst area. In case +of discovery, the purpose was to complete the well as a producer and take it into +production with the subsea well 15/9-C2H on the Loke structure. However, the Heimdal +Formation was found deeper than prognosed and did not contain hydrocarbons. +The secondary objective of the well was to test the hydrocarbon potential in sandstones +of Jurassic/Triassic age. Oil was encountered in sandstones of the Middle Jurassic Hugin +Formation. A structural cross-section along the well path given in Figure 2.3, illustrates the +geology of the Theta Vest structure. +The well was spudded on 18th Sept. 1992 and temporarily abandoned on 24th Sept. 1992. +A re-entry was done on 18th Nov. 1992. The well was drilled to a total depth of 3110.3 +m below sea level and was terminated in sediments of Triassic age. The testing and +completion started 26nd March 1993. The well showed very good production properties. It +was plugged and abandoned on 29th April 1993. +In the following chapters, an evaluation of the Theta Vest discovery and neighbouring areas +based on seismic interpretation, structural geology, biostratigraphy, sedimentology, +mineralogy, petrophysics, DST-test analysis and geochemistry is presented. This leads to +an anlysis and conclusion on the probable resources of the discovery. Planned future +studies and exploration in the Sleipner Øst area are also reviewed. +12 +PL046 AREA +STATOIL +Location of well 15/9-19 SR +Possible extension +of Sleipner Vest Field +15/9-11 +SLEIPNER +* +0STi 5/9-1 +Exploration well +gas/ condensate and oil +Exploration well +gas/condensate +Oil exploration well +Dry exploration well +Figure 2.1 +SLEIPNER ØST AREA +STATOIL +XLOKE •:•:•: +D-TernDi: +% +SLEIPNER ØST +Gas / Condensate +Heimdal Formation +Gas / Condensate +Jurassic / Triassic Sandstone +Oil +Jurassic Sandstone +Prospects +Heimdal Formation +Prospects +Jurassic / Triassic Sandstone +Area declared commercial +(PL 046C) +Figure 2.2 +Vertical Cross Section through Well Path 15/9-19 SR +Vertical exaggeration 2:1 +East +B +15/9-19 SR +2300 +Heimdal Fm +2500- +2700 +Lower Cretaceous +2900 - +Upper Permian and Tnassic +3100 +3300 +RoUiege neies <3p. +(Q 3500 +I +GS-FV/85718IRI +ro +co Structural cross-section along the 15/9-19 SR well path. See Figure 3.12 for location. +O STATOIL +3 SEISMIC INTERPRETATION AND MAPPING +A complete documentation of the operators seismic interpretation on the Gamma High is +beyond the scope of this report. Only the most relevant data for interpretation of the Theta +Vest area is included. Some of the presented maps are preliminary. +3.1 Seismic database. +The ST8215R 3D survey was shot in 1982 and reprocessed in 1991. Well planning on the +Theta Vest structure was based on interpretation of these data. The quality of the data is +varying. The lower Tertiary section, including Top Heimdal Fm. is of poor quality in this +area, whereas the Cretaceous section is better. The section below the Base Cretaceous +Unconformity is of poor quality. The deep section suffers from some overmigration. +The seismic data are processed with zero phase conversion using check-shot calibrated +well logs. Log-calibration analyses, using "Integrate" modelling, have confirmed that the +data are fairly close to zero phase. +3.2 VSP +A vertical incidence VSP was shot in the well after TD was reached and casing set. The +VSP covers the depth range 4580 to 846 m (MD RKB), of which the interval 4580 - 1480 +m (MD RKB) had a level spacing of 20 m MD. The VSP data has contributed to correction +of the velocities, well ties as well as the seismic mapping of major horizons on the Theta +Vest structure. +Figure 3.1 shows a composite plot of VSP spliced with a random line along the wellbore. +The Base Cretaceous Unconformity is notably better defined on this VSP section than on +the 3D seismic data, especially in the crestal area. The Top Mesozoic Sandstone however, +fails to be properly resolved, as the rest of the deep section. The Heimdal Formation is +resolved with more internal reflectors than on the 3D data. From visual inspection on +Figure 3.1, a negative shift of 5 to 10 ms seems to be necessary for the VSP to match +the seismic data. However, when checking the log times on several horizons and +comparing them with the 3D seismic data, a general shift is not required (Figure 3.2). +3.3 Seismic interpretation +Tie between the major horizons and the stratigraphy in the well is shown on Figure 3.2. +Top Heimdal Formation and Base Cretaceous Unconformity were adjusted, based on the +16 +STATOIL +well results and the VSP data. The Top Mesozoic Sandstone was interpreted after the well +was drilled. +3.3.1 Top Heimdal Formation +The Top Heimdal Formation reflector, representing top of the Heimdal sandstone, is +interpreted regionally in the Sleipner Øst area. It is generally picked in a minimum reflection +(white trough), since there is a marked increase in acoustic impedance from the overlying +shales to the well consolidated sandstone reservoir. +The Heimdal Formation was the primary target for this well. This reservoir came 50 m TVD +deep according to prognosis and was water wet. The VSP data indicated that the Heimdal +Formation reflector was picked approximaly 15 ms too high initially. The other reason for +the depth-discrepancy is relatively high velocities in the overlying sediments compared to +adjacent wells. Therefore the velocity map was adjusted accordingly (Figure 3.3 and +Enclosure 1). The corrected Top Heimdal Fm. depth map is shown on Figure 3.4 and +Enclosure 2. +The quality of the Top Heimdal horizon is varying. On the Theta Vest structure this horizon +is generally weak and hard to define. In the 15/9-19 SR well, the Top Heimdal Formation +tie is on the onset of a black peak accordingly to VSP, but is interpreted on the seismic +data 1/4 cycle higher, in the white trough. +3.3.2 Top Shetland Group +This is generally the best defined reflector in the Sleipner Øst area, representing the top +of the Cretaceous. It is picked in a strong white trough, as there is a marked increase of +acoustic impedance from Tertiary sandstones and shales to Cretaceous chalk. +3.3.3 Top Blodøks Formation +The Blodøks Formation is a marly formation near the base of the Shetland Group. In most +wells, the top of this formation ties to the onset of a black peak. +3.3.4 Base Cretaceous Unconformity +The Base Cretaceous Unconformity represents a fall in acoustic impedance on top of the +Jurassic Draupne Formation in the Viking Group. The horizon is therefore picked on the +maximum of a generally strong black peak. The horizon is of importance as it reveals the +17 +C) STATOIL +Jurassic structuring, both regarding fault block delineation and dips. The Base Cretaceous +Unconformity map is given in Enclosure 3 and Figure 3.5. +In the 15/9-19 SR well, the seismic tie should be on two-way time 2.547 sec. according +to the velocity log, which is on the maximum of a black peak according to the synthetic +seismogram. Originally the B.C.U. was picked at 2.512 sec, one cycle higher. The new +interpretation placed the Jurassic section in a down-faulted position (see Figure 3.6). The +new seismic tie will not affect the Jurassic/Triassic interpretation in areas outside the down- +faulted block. +The B.C.U. reflector is seen to have less amplitude levels near the crest of the structures +(see Enclosure 9 and Figure 3.7). A probable reason for this is thinning of the Draupne +Formation, probably also thinning of the Heather Formation. +3.3.5 Top Mesozoic Sandstone +The first occurence of sandstone below the Viking Group is denoted Top Mesozoic +Sandstone regardless of stratigraphic position. In well 15/9-19 SR it equals the top Hugin +Formation. +As the Top Mesozoic Sandstone reflector is the top of a sandstone with generally higher +acoustic impedance than the overlying shales, this should be picked at a minimum white +trough. Due to the fact that the Viking Group in most Sleipner Øst wells is relatively thin, +beyond the resolution of the seismic data, the horizon is hard to tie and interpret +consistently. To this should be added that there is a great variation in sand quality and +sand thickness throughout the Sleipner Øst area. The interpretation is consistent with and +tied to the Top Hugin Fm." interpreted on Sleipner Vest (Statoil, 1993c). +In the 15/9-19 SR well the Viking Group is only 9.5 m thick. The top of the Hugin +Formation is picked 7 ms below the BCU reflector. Top Mesozoic Sandstone time- and +depth maps are shown on Enclosures 4 and 5 and also given in Figure 3.8 and 3.9. +3.3.6 Other horizons +In the deepest parts of the seismic dataset, the following two horizons were picked (deeper +than TD in 15/9-19 SR): +- Top Smith Bank Formation (interpreted on selected lines). +- Top Rotliegendes Gp. +18 +STATOIL +In the shallow section, the following events are picked: +- Top Pliocene. +- Top Utsira Formation. +- Near Top Oligocen. +- Base Utsira Formation. +- Top Balder Formation. +- Top Lista Formation. +Internally in the Shetland Gp., Top Hod Fm. is interpreted. Based on the tie from the VSP, +also the Grid Formation was picked. This appears to have an "eye" - shape, consistent +with the sedimentological interpretation of this being a channel deposit. The areal extension +of the Grid sands have not yet been mapped. Figure 3.6 illustrates the seismic picks in the +Theta Vest area. Time and depth data for the various horizons are listed in Table 5.8. +3.4 Depth conversion +Shallow horizons (above the Top Heimdal reflector) were depth converted using interval +velocities derived from wells in the area. The Top Heimdal Formation was depth converted +using the linear formula: +Vz = V + kZ +0 +in which Vz = veolocity at depth z +V = initial velocity +0 +k = compaction factor +Z = depth (subsea). +The ADLINVEL program estimates the linear velocity function which minimizes the depth +difference between the observed and the estimated time/depth data. Based on analyses +from 11 wells in the 15/9 block (including 15/9-19 SR), the minimum point for depth +residuals occured at k= 0.346, whereas the minimum for standard deviation of V occured +0 +at k= 0.71 (see Figure 3.10). A similar analysis using the 5 vertical wells on the Gamma +High only (15/9-9, -11, -13, -15, -16 and -17), resulted in minimum for depth residuals at +k= 0.456. Bearing in mind that the well 15/9-19 SR is highly deviated, less weight is given +to that well than to the vertical wells on the Gamma High. Also a larger k-value gives less +standard deviation on the V values. Therefore k= 0.456 is chosen for the Theta Vest area +0 +as for the rest of the Gamma High. +The time/depth relationship as well as velocities from 15/9-19 SR are shown in Figure 3.11. +The abnormally high average velocities at Theta Vest, are probably contributed by the Grid +sands which are much poorer developed in other wells on the Gamma High. The +distribution of the Grid sands is likely to be restricted. +19 +STATOIL +Horizons below Top Heimdal Formation were depth converted using interval velocity grids +based on vertical velocities in the wells. Velocity grids were made for the following +intervals: +Top Heimdal Fm. Top Shetland Gp. +Top Shetland Gp. Top Blodøks Fm. +Top Shetland Gp. Base Cretaceous Unconformity +Base Cret. Unc. Top Rotliegendes Gp. +The composite map of the Base Cretaceous Unconformity shown on Figure 3.5, was depth +converted using Linvel function to Top Shetland Group (k=0.728) and velocity grid for the +interval Top Shetland - Base Cretaceous Unconformity. +The maps were adjusted in the wells using "AGR"(in I RAP). These residual corrections +have been minor. The grid size is 100 x 100 m. +20 +WELL 15/9-19 SR +STATOIL +Composite plot of VSP and random line along well path +Sec./m(MSL) +15/9-19 SR +GridFm. +2.1 +!P*T. Balder Fm. +2.3 -2400 +T. Heimdal Fm. +-2500 +2.4 - +'. Shet. Gp. j-2600 +-27W +2.5 +2800 +T. Blodøks Fm. +B.C.U. +12900 +T. Hugin +Fm./TM.SST2.6 +-3000 +2.7 -_ +2.8 +T. Rotliegendes +2.9 ~ +3.0 - s +LL +Loke Tempi, loc. +O +Figure 3.1 +wffi +15/9-19 SR +Synthetic seismogram +Random line along wellpath +Ac. Imp Synth. Seis +Sec. O-phase Sec. +~ — T. Heimdal Fm. +2.7 2.7 +2.8- 2.8 +m +2.9 - 2.9 m +to +3 +(Q +W +O +OJ Synt. Seismogram 15/9 -19 SR +ro +SLEIPNER ØST AREA +STATOIL +,V map +0 +Top Heimdal Fm. +432000 436000 440000 +6480000 6480000 +15/9-1 9 BH +•fy J / M 5/9:C-2 +"C-Temp +6476000 - 6476000 +6472000 +6468000 +1534-1540 +1540-1550 +1550-1560 +1560-1570 +1570-1580 +1580-1590 +1590-1598 +6464000 +Figure 3.3 +SLEIPNER ØST AREA +STATOIL +tructural depth map +Top Heimdal Fm. +432000 438000 +6480000 -6480001 +6474000 -6474000 +4 +6468000 -6468000 +zcoo--zzr +Cato-!:; +1: +160-2) +s?«°-?3 +10-? BU +80-r 9D +: +432000 438000 +1000 icoo +METER +l m25469 6-Dec-93 l +Figure 3.4 +SLEIPNER VEST AND ØST AREA +STATOIL +^Structural depthmap, preliminary +Base Cretaceous Unconformity +420000 424000 428000 432000 436000 440000 +6492000 i- ' HC/C o ' r1 - . ...J... -^6492000 +6488000 -6488000 +6484000 6484000 +1 +6480000 6480000 +6476000 6476000 +6472000 6472000 +6468000 6468000 +6464000 6464000 +6460000 5460000 +6456000 6456000 +\ —r" 1 T +420000 424000 428000 432000 436000 440000 +KILOMETER +0 1 2 3 45 +Figure 3.5 +THCTA VEST AREA +STATOIL +ST8215R Crossline491 +T.Heimdal Fm +T.Shetland Gr +'f- BCU pick before drillin +•'«•?>•" tm 'iff:. :•"- ••.maf:-: '-"UHf . «l +2S001 T.Blodøks Fm +T.Hugin Fm +T.RoOiegende +l XmSS&Jr " • " •• »: iP?f •••: «•* '•' %• • »^S «iS» •:% • ;!*^ :,W:S:- "f «SS '- •¥*" -•'* SV::-V S^W & * +Seismic crossline 491 through the 15/9-19 SR well. Note the B.C.U. pick before and after drilling and reversal of fault +CO at approx. 680. See Figure 3.12 for location. +b> +THETA VEST AREA +Amplitude map STATOIL +ecu +397 500 600 inlines 700 800 859 +73 +127 +crosslines +600 +0 +800 +(Q -128 +913 +I +to +THETA VEST AREA +STATOIL +Time map +Top Mesozoic Sandstone +431000 432000 433000 434000 435000 436000 437000 438000 439000 440000 441000 442000 +431000 432000 433000 434000 435000 436000 437000 438000 439000 440000 441000 442000 S +I +Meter +0 500 1000 1500 2000 2500 +m•":lt: § +Figure 3.8 +THETA VEST AREA +STATOIL +Structural depthmap +Top Mesozoic Sandstone +431000 432000 433000 434000 435000 436000 437000 438000 439000 440000 441000 442000 +431000 432000 433000 434000 435000 436000 437000 438000 439000 440000 441000 442000 S +Meter +0 500 1000 1500 2000 2500 +Figure 3.9 +Result from add-linvel analysis +STATOIL +Down to top Heimdal Formation +Std.Dev. of Vo and Sum of Depth Residual +vs. K-Values +0 +0.00 2.00 +K - factor +The velocity evaluation is based on +wells 15/9-4, 8,9, 10, 11, 13, 15, 16, 17, 18 and 19 SR. +Note: 15/9-19 SR gives k=.361 and Vo =1679.13 m/s +Figure 3.10 +WELL 15/9-19 SR +STATOIL +Time/Depth and Velocity plot +Time scale [sec] one way travel time +0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 O.B 0.9 1.0 1.1 1-2 1.3 +Velocity scale fro/sec] +2500 3000 3500 4000 +. Tint* vs. depth +Average velocity +From Read Well Services: VSP report +. RMS velocity +Interval velocity +Figure 3.11 +SLEIPNER ØST AREA +STATOIL +Profiles and seismic sections +432000 434000 436000 438000 440000 442000 +i i __1 I +6482000 - 6482000 +6480000 - 6480000 +Seis.crossl.No491 (Fig.3.6) +6478000 - 6478000 +6476000 - 6476000 +5474000 - 6474000 +6472000 - -6472000 +SLEIPNER A +6470000 - -6470000 +, 15/9-9 +6468000 H - 6468000 +6466000 -| -6466000 +6464000 Kilometer -6464000 +1 2 3 +432000 434000 436000 440000 442000 +Figure 3.12 +STATOIL +4 STRUCTURAL INTERPRETATION AND TECTONIC DEVELOPMENT +4.1 Structural core description +Structural core logging was carried out for cores no. 2 and 3, covering the lower part of +the Middle Jurassic Hugin Formation, and the uppermost part of the Triassic Skagerrak +Formation. +A core logging scheme for describing and mapping structures at a scale 1:5 was used, +including drawings. 15 thin-sections were studied. +The study showed that the rocks contain a high number of natural fractures. Frequency +distribution is shown in Figure 4.1. +The fractures are mostly small faults or deformation bands with displacements from a few +mm to a few cm (Figure 4.2), and the fracture infill is highly variable in colour. +When studied in thin section, it is observed that most deformation bands have grain +crushing/grain size reduction (Figure 4.3). Porosity reduction is often one order of +magnitude. Preferred orientation of quartz grain long axes is frequent, and some preferred +growth of clay minerals seems possibly to have taken place in many of the deformation +bands. +According to researchers at Stanford University, deformation bands may be classified +according to the change in porosity (unchanged, compaction, dilatation) and after presence +of grain crushing (Antonelli et al., 1993). All these types were found in the core, but the +grain crushing/porosity reduction was the most common. +A deformation band with grain crushing and porosity reduction may be viewed as a result +of strain hardening, whereas larger faults with localized slip surfaces represent strain +softening products. Mechanically, these are different processes. +A few larger faults were recognized by clay smear and striations. It seems that they form +zones of weakness where the core easily parts under bending stress. +A partial orientation of the core was made possible by the well deviation (about 40 degrees +towards the west). In the west, there is a west-dipping, N-S striking large master fault, and +faults were termed synthetic and antithetic relative to this. +All clear cross-cutting relationships in the two cores were analyzed, and it was found that +"synthetic before antithetic" was of similar frequency as "antithetic before synthetic". +From this, it may be concluded that the faults observed were formed in a zone of intense +and complex deformation. Antithetic and synthetic faults probably formed at roughly the +33 +CJ STATOIL +same time. +General dip of the bedding relative to a plane perpendicular to the core axis was measured +in an attempt to record possible fault drag zones (dipmeter was not run due to technical +problems). This method contains some uncertainties due to core orientation and +observational difficulties due to massive rock etc. The oil stain and often massive character +of the Hugin Formation made observations of general bedding dip difficult, especially in the +Jurassic. Rotation of bedding was pronounced in two zones: +(i) 4345-4348 m MD RKB (Triassic). This coincides with major (m-size?) faults +with day smear and striations at 4345 (Figure 4.4) and 4347 m MD RKB. +Fracture frequency is high in the upper part, and low in the lower part of the +interval. +(ii) 4355-4362 m MD RKB (Triassic). No major fault has been recorded in this +interval. Fracture frequency is low in the upper part (Figure 4.1), and medium +in the lower part of the interval. Rotation may have been caused by +slumping. +Since grain crushing require some minimum value of the mean stress, it may be concluded +that some overburden (Upper Jurassic shales) were present at the time of faulting. +It is assumed that the Upper Jurassic tectonic phase is responsible for most of the +fractures. Where displacements can be seen, they dominantly indicate normal faulting. In +addition, syn-sedimentary faulting can be seen in the Triassic, especially in the lower part +of core no. 3. These are characterized by small associated folding and a combination of +normal and reverse faulting. A few post-consolidation reverse faults may be of Cretaceous +age. +The Jurassic is oil-filled troughout, but still contains a large number of deformation bands +with a possible sealing potential. Sometimes these bands are light and in some cases very +thick (up to 10 mm), indicating a "seal". Other bands are dark. See Figure 4.5 and 4.2. +Both light and dark bands show grain crushing and significant porosity reduction under the +microscope. A possible explanation is that tight light bands do seal, but the sealing +property has a limited lateral extent, and that a significant oil coloumn has broken the seal +of the more narrow, dark bands. This may possibly be due to differences in capillary +displacement pressure. +Altogether some 400 induced fractures were present in the two cores. They were easily +recognized by not containing clay smear/striations or a deformation band of mm-thickness. +They fall into two groups, one perpendicular to the core axis with "clean" joint surface +(probably caused by bending), and one with joint "swarms" mainly parallel to the core axis +and sometimes covered by drilling mud (possibly caused by torsion). +The structural core description is presented in detail in a separate report (Statoil, 1993f). +34 +STATOIL +4.2 Estimate of tectonic thinning of the Hugin Fm. in the position +of well 15/9-19 SR +Single-well hydrocarbon discoveries with poor seismic resolution give a drilled reservoir +thickness that may not be representative for the reservoir within closure. A high degree of +faulting by faults of varying size (most of them small) may have thinned the reservoir +anomaleously at and near the well trace. +A rough estimate of a representative reservoir thickness may be obtained using a pure- +shear or simple-shear analysis based on data from structural core logging. All natural +fractures found in the core were assumed to be shear fractures, and a mean displacement +is applied to all fractures from (a limited number of) measurable displacements in the core. +An initial fault dip of 60 degrees was assumed. +The core part of 52 meter contained 829 fractures (assumed to be faults), with mean +displacement of 31 mm based on 42 measurements. The ratio of antithetic faulting (roughly +east-dipping) realtive to synthetic faulting was found to be 2:1. +The following procedure was used to estimate tectonic thinning: +1. Structural core logging was carried out (see separate report; Statoil, 1993f). +Displacements and numbers of fractures per meter were noted, and drawing +of fractures were made. +2. The number of faults encountered in a well is dependent on deviation +direction relative to fault plane orientations. The number of fractures +(intensity) encountered was corrected for well deviation, recalculated from a +40 degree deviation to zero deviation, assuming horizontal bedding. Both +pure-shear and simple-shear models for recalculation were used. +3. For a pure-shear model, tectonic thinning equals sum of throws on faults. +4. For a simple-shear model, a rotated fault block model (rotation is relative to +disturbed bedding surface), including the shear angle, is expressing the +thinning. The shear angle was found using a numerical procedure. +The results for the Hugin Fm., well 15/9-19 SR (18 m vertical thickness in well position) +is as follows: +unfaulted thickness using pure-shear model is 27.0 m +unfaulted thickness using simple-shear model is 24.7 m +interpolated pure-shear/simple-shear model using observed ratio between +antithetic and synthetic fractures gives an unfaulted thickness of 25.5 m. +35 +STATOIL +Instead of reducing fault intensity to zero to obtain representative thickness, it may be +reduced to a suitable background level, using comparable wells. The calculation of tectonic +thinning of reservoir is described in a separate report (Statoil, 1993e). +The method is of limited accuracy due to a limited data set, and lack of control on +displacements larger than core dimensions. +4.3 Structural and tectonic development +4.3.1 Regional setting +The Sleipner area is located in the south-eastern part of the Viking Graben. The area is +situated close to the intersection point between some of the major structural elements of +the North Sea. Major structural elements of the Sleipner region are given in Figure 4.6 and +Figure 4.7. +At this intersection, the N(NE)-S(SW) striking Viking Graben intersects with the NW-SE +striking Central Graben and also the NW-SE striking Norwegian-Danish basin. These strike +directions (N-S, NE-SW and NW-SE) are also the dominant strike directions for faults and +lineaments in the Sleipner area and have played an important role in the structuring and +shaping of the area. +The seismic attribute maps (Enclosure 6-11) reveal the lineaments in the Theta Vest - +Loke area. The Triassic/Jurassic faults in the Sleipner area are plotted on the Top +Mesozoic Sandstone depth map (Enclosure 5) and on the seismic interpretation of the +Sleipner Vest Field by Statoil (1993c). A simplified map showing the main faults and +lineaments in the Sleipner area is shown in Figure 4.8. Based on this map, some of the +main structural features of the Sleipner area are reviewed. +4.3.2 The main fault zone +The Sleipner area is divided into two major structural subareas, the Sleipner Terrace and +the Gamma High, by a major fault zone of approximately 1000 m throw in the northern +part of the 15/9-block (on Top RotJiegendes level). The fault zone is reaching a maximum +1500 m throw west of the 15/9-11 well and is down to approx. 1000 m west of well no. +15/9-9. +The Sleipner Terrace is located to the west of the main fault zone on the downthrown side. +To the west the Sleipner Terrace is bounded by the Viking Graben. The Sleipner Vest +Field is located on this terrace. +36 +STATOIL +The Gamma High is located on the eastern upthrown side of the main fault. The Gamma +High constitutes the southern extension of the Utsira High. The Sleipner Øst, Loke and +Theta Vest are located on the Gamma High. +The main fault zone follows two main directions (see Figure 4.8). In the south, between the +Sleipner Øst Field and the southern part of the Sleipner Vest Field, the main fault strike +dominantly N-S with a weak deviation towards a NW-SE direction. This direction is steady +over a distance of more than 10 kilometer along the Sleipner Øst Field. An extension of +the main fault can be followed for more than 10 kilometer south of the field out of the +mapped area, as a distinct depression on the Base Cretaceuos map (see Figure 3.5). At +the extreme north-western part of the Sleipner Øst Field, right south-west of the Theta Vest +structure, the main fault direction changes sharply to a NE-SW direction. This direction can +be followed for more than 10 kilometers towards north-east out of the mapped area. +4.3.3 The Sleipner Terrace area +The Sleipner Vest Field is located in the west part of the Sleipner Terrace. Between the +Sleipner Vest Field and the main fault to the east, there is a downfaulted basinal area. +The Sleipner Vest Field consists of several major fault blocks. The shape and orientation +of these fault blocks is governed by the three main fault and lineament directions N-S, NE- +SW and NW-SE (see Figure 4.8). The overall general shape of the Sleipner Vest Field is +an anticline. +The southern fault blocks have an overall N-S orientation, while the fault blocks central on +the field have an overall NE-SW orientation. This change in orientation coincides with the +change in the orientation of the- main fault zone from N-S in the south to NE-SW in the +north. It is found that the deepest and most well defined basin area between Sleipner Vest +and the main fault zone is located in this northern area, and that this basin also have an +NE-SW orientation. +The main fault blocks of the Sleipner Vest Field are separated from each other by well +defined NW-SE orientated faults and lineaments. This simplified picture is complicated by +the fact that faults with the three main directions (N-S, NE-SW and NW-SE) actually are +present over the whole field area, but to different degrees. Many of the faults around and +within the main fault blocks are composite faults where all the three main directions are +playing a part. +As a simplification it can be said that N-S and NW-SE directions dominate in the southern +part of the Sleipner Vest Field, NE-SW directions dominate in the central part and N-S +NW-SE directions dominate in the northern part. In addition to these three main directions, +also faults with E-W directions are found in the central and northern area of the field. This +adds to the complicated structural picture of the Sleipner Vest Field. +37 +STATOIL +4.3.4 The Gamma High +There is an apparent difference in the complexity of faulting between the Sleipner Terrace +and the Gamma High area. On the Gamma High, including Sleipner Øst, Loke and Theta +Vest, the number of mapped faults are few compared to what is observed on the Sleipner +Terrace. Also the extension and continuity of the faults are significantly different. The faults +on the Gamma High are generally scattered with a limited continuity. This is at least valid +in the Post Triassic section. +This difference implicates that the Gamma High is less influenced by faulting activity than +the Sleipner Terrace. This can be explained by the fact that it has a more distant position +to the Viking Graben area and the tectonics related to its formation. +The observed difference between the two areas can also partly be explained by different +influence from the Cretaceous and the Tertiary compressional phases: The Gamma High +area and its structures are strongly influenced by doming during these phases. This may +have resulted in reverse movements on faults, and thereby masked many of them from +seismic resolution and mapping. On the Top Rotliegendes level however, the faults are +large in extension and throw (see Enclosure 12 and Figure 4.9). +4.3.5 Structural links between the Gamma High and the Sleipner Terrace +Despite the structural difference between the Gamma High area and the Sleipner Terrace, +the two areas do have a common history. The fault and lineament directions on the +Gamma High are similar to those on the Sleipner Terrace with the dominating directions +N-S, NE-SW and NW-SE. Especially the NW-SE directed faults and lineaments connect the +two areas. Although only scattered faults with this direction is observed on the Gamma +High, it is found from the seismic attribute maps (Enclosure 6-11) that several distinct and +continous lineaments with this direction cut across the Gamma High. The westward +extension of these lineaments line up directly with many of the major NW-SE faults +mapped over the Sleipner Vest Field and obviously are connected to these. Those +lineaments also have significant influence on the shaping of the structures on the Gamma +High. Many of the highs and lows on the Gamma High thus have an elongate shape +orientated NW-SE. +On the Sleipner Vest Field many of the NW-SE faults and lineaments are expected to be +sealing due to changes in fluid contacts across them. +On the Gamma High the main NW-SE lineament cutting across the Sleipner Øst Field, also +must be sealing. This may explain the waterbearing Jurrasic/Triassic reservoirs to the +south (wells 15/9-9 and 15/9-16) and hydrocarbon bearing Hugin Formation to the north +(wells 15/9-11 and 15/9-13). +38 +STATOIL +4.4 Tectonic history +The current interpretation seems to confirm the importance of regional lineaments as +described in the litterature for this area (Pegrum 1984, Pegrum & Ljones 1984). The NW- +SE direction could be an extension of the Tomquist Zone. The main bounding faults to the +west and northwest of the Gamma High have directions that conform to the Viking Graben +and to the Central Graben. The Tomquist Zone belongs to a set of northwesterly tectonic +zones extending into the Fennoscandian - East European Precambrian basement platform. +This can be traced from onshore Poland through Southern Sweden, Denmark, the +Fjerritslev Fault, the Farsund Basin, the Stavanger Platform and the Sele High. Movements +along this zone have occured during several periods and are interpreted to be the +response of major plate-tectonic adjustments. +An other fundamental lineament is the Highland Boundary Fault-Ling Graben Alignment. +This extends in northeastern direction from the Highlands past southeastern part of the +Utsira High, into the Ling Graben (Gage and Dore, 1987), see Figure 4.6. +4.4.1 Paleozoicum +During the Caledonian and Variscan orogenic cycles, the general stress along the Tomquist +Zone was compressional with right-lateral movements between the Fennoscandian-East +European platform and the rest of Europe. In the Late Devonian, sedimentary basins with +a north-northeast trend were formed in the central North Sea areas as an effect of wrench +faulting. These basins were subject to widespread deposition of Old Red Sandstone and +later also by Early Carboniferous sedimentation. During late Carboniferous, the Variscan +compression gave an east-west dominating direction, especially in the southern North Sea. +During Permian time, the North Sea area was subject to east-west extension with +development of Oslo Graben, Bamle Through and Horn Graben. The Tomquist zone +generally acted as a northeastern limit of the Zechstein Salt basin. +In Permian time, the Gamma High in block 15/9, was probably a basin-margin area, based +on results in wells 15/9-9 and 15/9-16. These wells proved 20 m and 56 m respectively +of anhydritic Zechstein Gp. overlying the Rotliegendes Gp. shaley sandstone and breccia. +In contrast, well 15/12-3 to the south had a Zechstein Gp. of 1154 m. Differences in the +development of the Rotliegendes also indicates a more basin-margin environment in the +Gamma High area. (Pegrum & Ljones 1984). In the Sleipner Terrace area, halokinetic +movements probably have been of importance for the formation of the Sleipner Vest +structuring, but it is uncertain how thick this salt has been. +39 +STATOIL +4.4.2 Mesozoicum +In the northwestern Europe the Triassic was dominated by regional extension and rifting. +During the early rifting phase the dominant lineament directions were north and northeast. +The Viking Graben, Central Graben, the Egersund Basin and Moray Firth Basin were +formed. The Gamma High, although being an extension of the Utsira High, still received +sediments. The present thickness of Triassic sediments is in the order of 300-600m. The +isochore map of Top Rotliegendes - Base Cretaceous Unconformity is given in Figure 4.10. +Relatively thin Triassic sections in the wells 15/9-11, 15/9-13 and 15/9-16 suggest that +parts of the Gamma High had relief during Triassic, resulting in non-deposition and/or +erosion at this time (Pegrum & Ljones, 1984). +The Mesozoic extension lead to a reversal of the movements along the Tomquist Zone, +from right-lateral/compressional to left-lateral/extensional. There was a regional uplift during +Early - Mid Jurassic in the central North Sea with erosion of high areas, also on the +Gamma High. Earlier deposited sediments on the Gamma High were largely removed by +erosion. There are abundant sandy deposits on the Sleipner Terrace of Bathonian - +Callovian age and much thinner development on the Gamma High (of Callovian Hugin +Formation). +The Mesozoic extension culminated in Late Jurassic time. The western margin of the +Gamma High consists of major normal faults with periodic movements associated with the +development of the Viking Graben and Central Graben. There has apparently been a +"footwall uplift" yielding a general dip down to the east and with most extensive erosion +along the fault margin. During Late Jurassic the vertical movement of the western- and +northwestern margin was 400-600m. On the Gamma High there are differences in +amplitude between highs and lows for the BCU reflector. This is interpreted to be an effect +of local thinning of the Viking Group on these high areas and consequently the structures +were in development at least during Upper Jurassic time. This is also supported by +observations of structures in the cores (see Chapter 4.1). During the Lower Cretaceous +time, the area has been subject to compression with the result that faults were steepened +and partly overturned. See Figure 4.11. This has also been observed during the latest +seismic interpretation on Sleipner Vest (Statoil 1993c), During Upper Cretaceous there was +subsidence and deposition of the marls and chalk of the Shetland Gp. +4.4.3 Cenozoicum +Laramide tectonism and associated drop in sea level caused large paleogeographic +changes in the North Sea Area (Ziegler, 1981). The Shetland Platform was subjected to +uplift and erosion, giving rise to eastward directed output of clastic sedimentation. This +eventually also reached the Sleipner area, providing Heimdal Formation reservoir sands. +Some flexuring and faulting of the Top Shetland Gp indicates that faults bounding The +Gamma High could have had a minor reactivation in the Paleocene. +40 +STATOIL +The last tectonic event of importance for the Gamma area occured in the Mid Tertiary in +connection with Alpine folding. This event resulted in a regional compression and probably +also reactivation of the Tomquist lineament, causing doming and creating the hydrocarbon +trap in the Paleocene. A possible late phase of the Mid-Tertiary compressional event can +be observed in the north-easterly extremes of the 15/9 block, causing local uplift. +4.4.4 Tectonic development of the Gamma High +Based on the known stressfields, the observed lineaments and the stratigraphy encountered +in the wells in the Sleipner area, the Gamma High is considered to consist of rotated fault +blocks with a complex genetic history. +From the seismic sections on Figure 4.11 and 4.12, it can be seen that there have been +reversed movements of some deep faults. The major faults on the T. Rotliegendes level +(Enclosure 12, Figure 4.9) can in some cases be traced up to the Base Cretaceous level, +but then often with reversed displacement In some cases, the Jurassic - Lower Cretaceous +is flexured over the deep seated block boundaries, and often this section thickens in local +graben areas. The Top Rotliegendes, however, will locally be uplifted in some of these low +areas, thus forming a pattern of repeated local inversions. See the vertical cross-section +through Theta Vest and Theta Sør in Figure 4.13. This pattern can not be explained as +result of a single dominating stressfield. +Two models will be briefly discussed here: +1. Halokinetic model +The structures on the Gamma High have some resemblance to "turtleback structures", +being the result of differential loading, salt doming and subsequent salt-with-drawel: the +clastic Post-Permian sedimentation would first be concentrated in local basins separated +by salt doming. Upon salt drainage from the area, the former clastic depocenters would +become local high areas and supply sediments for deposition in the former salt-dome +regions. +This model fails to explain the frequent reversals of major faults penetrating the +Rotliegendes. Also this model requires initial salt deposition up to a thickness at which the +salt becomes mobile, which is uncertain at the Gamma High (see Chapter 4.3.1), but it can +not be excluded that this could have been a mechanism in eastern part of the 15/9 area. +2. Shear fault model +Shear faulting will juxtapose fault blocks with different sediment thickness. From the known +tectonic history, especially with respect to the shear movements along the Tornquist Zone, +shearing could have has some impact on the tectonic development of the Sleipner area +Restoration of the fault blocks is not possible with this model either, and the extension of +the Tomquist Zone (at least the magnitude of shear movements) is uncertain. Several +41 +CJ STATOIL +observed features, at least in the Post - Rotliegende section are consistent with the known +movements along that lineament. First of all, the above mentioned thickening and +flexuration of the Jurassic and Lower Cretaceous sediments, is in agreement with the +known extensional stress-field along the Tomquist Zone during that period. Furthermore the +abundant NW-SE lineaments cut across to the Sleipner Terrace as well and seems to +seperate distinctive fault compartments (see Chapter 4.2.6). The net movements along the +lineaments seems to be left-lateral, observed for example on the Sleipner Terrace as +cutting local Jurassic basin axes. +Paleocene horizons, like the Top Heimdal Formation seems to have an "dome"-axis running +south of well 15/9-11 in the NW-SE direction. Faulting and folding along this axis confirm +Post-Paleocene compressional phase. Very locally there are indications of thrusting (on +T.Shetland Gp.), along the same lineament. See Figure 3.4, 4.8 and 4.14. +Both Jurassic extension and Early Cretaceous and Tertiary compression appear to have +been of importance for the development of the Theta Vest structure, as illustrated on the +seismic section in Figure 4.15. +Conclusion +The "Shear fault model" seems to agree better with the observed data than a purely +halokinetic model. The latter model seems insufficient in order to explain typical +observations in the area. On the other hand, salt could have secondary importance locally, +especially in eastern parts of the Gamma High. In areas surrounding the Gamma High, +salt movements are thought to have accompanied movements of major faults and +deposition of Triassic clastic sediments (Pegrum and Ljones, 1984). +It is probable that the two NW-SE trending lineaments, bounding Theta Vest, have had +major influence on the development of that structure. The fault blocks seem to be +irrestorable in cross-section view (Figure 4.13), but shearing along the lineaments could +explain this. +42 +WELL 15/9-19 SR +STATOIL +Fracture frequency +Measured 1 meter intervals +Fracture frequency, fractures per meter +4328 +4330 +4332 +4334 +DQ 4336 +V 4338 +rj= 4340 +* 4342 +Q 4344 +§ 4346 +•* 4348 +p 4350 +fc 4352 +-C 4354 +"ri 4356 +S-4358 +ft 4360 +tJ 4362 +4364 +4366 +4368 +4370 +4372 +4374 +4376 +4378 +4380 +4382 +Extrapolated in the case of missing core +Figure 4.1 Fracture frequencies along 1 meter intervals of cores 2 and 3. The +Jurassic-Triassic boundary (unconformity) Is at 4343.60 m MD RKB; +fracture frequencies are generally higher In the Jurassic than in the +Triassic. Recorded frequencies Include synsedlmentary features, which +seem to be more pronounced In the Triassic. +WELL 15/9-19 SR +Core photograph +Hugin Formation +Figure 4.2 Core photograph from the Hugin Formation, at 4336.59-4336.80 m MD +RKB. The dark rock Is oil-stained sandstone, the light zones are +deformation bands. +WELL 15/9-19 SR +STATOIL +Thin section photograph +'Hugin Formation +|=—1.0 mm +Figure 4.3 Thin-section photograph 100X magnification from the Hugin Formation at +4336.84 m MD RKB. The continuation of the light deformation band at the +right part of Figure 4.2. The photograph shows quartz grain crushing and +strong porosity reduction. +WELL 15/9-19 SR +STATOIL +Core photograph +Hugin Formation +B ronn. 15/9-19S +Dybde: +I +Figure 4.4 Fault with clay smear and strlations In the Trlasslc at 4345 m MD RKB. +WELL 15/9-19 SR +STATOIL +re photograph +Hugin Formation +Bronn 15.9-19S +Dybde: +Figure 4.5 Small faults In the Hugln Fm. at 4334 m MD RKB. Dark colour of deformed +zone (band) Indicate Invasion of oil. +The Sleipner Area +STATOIL +Structural framework map +SO°N 80°N +70°N +70°N +60° N +50°N +Figure 4.6 The present day structural framework map (from Gage & Dore, 1987). +TQA = Tornqulst Alignment, CG = Central Graben, HBFA = Highland +Boundary Fault Alignment, VG = Viking Graben. +The Sleipner Area +STATOIL +Structural setting +FLADEN +GROUND +SPUR +IPNER f +RACE-GAMftiA +HIG +AN|||W +I/VLT +ÉilGE +EXTENSIVE +SALT DOMING +Figure 4.7 +THE SLEIPNER FIELD +STATOIL +Main faults and lineaments +N +A +SLEIPNER +TERRACE +15/9-1 7 +GAMMA +HIGH +HYDROCARBONS +DRY WELL +\ +THE MAIN FAULT +Figure 4.8 +SLEIPNER ØST AREA +STATOIL +Structural depthmap +Top Rotliegende +432000 434000 436000 +6482000 6482000 +6480000 - 6480000 +6478000 - - 6478000 +8476000 - - 6476000 +6474000 -i - 6474000 +6472000 - - 6472000 +6470000 - -6470000 +6468000 - - 6468000 +6466000 -i - 6466000 +6464000 - - 6464000 +432000 434000 436000 438000 440000 442000 +Figure 4.9 +SLEIPNER ØST AREA +STATOIL +Isochore, depth +Top Rotliegendes-Base Cretaceous Unc. +SLEIPNER ØST +STATOIL +Inline 510 +ST8215R +Theta vest +Sleipner Øst +N +385 450 500 550 600 650 750 800 850 900 950 +2292 +Top Heimdal Fm. +2400 +Top Shetland Gr. +2500 , +Top Blodøks Fm. +BCU +2600 +Top Mesoz. Sst. +2700 +Top Rotliegende +2800 +2900 +I +3 +207 +See Figure 3.12 for location. +THETA VEST AREA +STATOIL +ST8215R +500 550 600 650 700 750 800 r: +2044» OH* -•••:?** C. +- •'•j«tSi«lfe-: +Top Balder Fm. +P: ::;;tf -•«•fe.* +||lf||| Top Heimdal Fm. +gj^:: w^m^jn^Mjjjjg +S^ J Top Shetland Gr. +*y^.3^5| +k. Top Blodoks Fm. +^•OTM *-» v^- w +•^ •;,.^,:;::-*?-"-«i +Top Mesoz. Sst +*sf "Is +Wlik/^m Top Smith bank +Vv«8ra!Wa»*((É +Top Rotliegende +3000 +i +•„ +*. 3144 ' Seismic «Iri^Ril^i^nro level. See +10 Figure 3.12 for location. +Ve3mmccal Cross Section throughiW Weell Path 15/9-19 SR +STATOIL +Vertical exaggeration 2:1 +North West +Theta Vest +m(MSL) Q +15/9-19 SR +2200 +2600 - +3000 +Upper Permian and Triassic +3400 — +3800 +Upper +Permian-Triass +4200 +5km 10km +1km +US-FV/8571BIR2 +3 +(Q +I +Structural cross section through the well path 15/9-19 SR. Note the uplifting at the Top Rotllegendes In local "graben +areas" relative to the Jurassic - Lower Cretaceous. See Figure 3.12 for location. +SLEIPNER ØST STATOIL +ST8215R Inline 703 +N 765 1000 1100 1200 1300 1400 1461 +2092 +Top Balder Fm. +2250S +Top Heimdal Fm|*| +i +Top Shetland Gr. ± +Top Blodøks Fm. +2500 +^ .^ +Top Mesoz.Sstpr^ ^ +Top Rotliegende +TI +e +i 3250 +33 +'éelsmlc Inline 703 In the Sleipner Øst area. Note the thrusted faults. See Figure 3.12 for location. +THETA VEST AREA +STATOIL +ST8215R Inline 579 +409 700 800 889 +Top Balder Fm. +T"- •***ijr: +15/9-ilpj +2250^ +Top Heimdal Fm. +Top Shetland Gr. +Top Blodøks Fm. +ecu +2500 +Top Mesoz. Sst. +#fe Top Smith Bank +Top Rotliegende +•n +is Data in Semi-Quantitlive Weight% +He Por. Klh Plug No. DEPTH Quartz K-Feldspar Plagioclase Calcite Dolomite Siderite Pyrite Kaolinite Mica-lllite Chl.-Ber. Smectite TOTAL +» * * Heimdal Firmation * * * +27,3 21,8 1 3643,00 84,2 6,2 6J 0 L 0 0,3 0,0 0,0 0,0 0,0 3,3 0,0 100,0 +22,9 40,0 3 3643,50 80,0 6,3 7,0 0,0 0,3 0,0 0,0 0,0 1,5 4,9 0,0 100,0 +27,3 68,4 5 3644,00 84,0 5,7 5,9 0,0 0,3 0,0 0,0 0,0 0,9 3,2 0,0 100,0 +26,6 27,5 7 3644,50 82,5 6,1 6,1 0,0 0,3 0,0 0,0 0,0 1.5 3,5 0,0 100,0 +26,4 54,1 9 3645,00 82,7 5,9 5,8 0,0 0,3 0,0 0,0 0,0 1,0 4,3 0,0 100,0 +25,6 11,6 11 3645,50 82,7 6,2 6,1 0,0 0,3 0,0 0,0 0,0 0,7 4,0 0,0 100,0 +* » * Hugin Fort1nation * * * +24,5 5350,0 14 4328,85 88,8 4,5 0,0 0,0 0,3 0.0 1,0 4,6 0,8 0,0 0,0 100 L 0 +25,5 11600,0 16 4329,25 93,9 2,2 0,0 0,0 0,2 0,0 0,8 2,9 0,0 0,0 0,0 100,0 +25,2 15300,0 20 4330,25 92,9 2,8 0,0 0,0 0,2 0,0 0,7 3,4 0,0 0,0 0,0 100,0 +24,7 115,0 24 4331 ,25 59,0 8,6 0,0 0,4 2,0 0,2 0,6 23,5 5,6 0,0 0,0 100,0 +21,8 111,0 28 4332,25 67,5 5,6 0,0 0,3 5,4 0,1 0,5 19,3 1,3 0,0 0,0 100,0 +22,7 312,0 32 4333,25 84,2 5,5 0,0 0,2 0,5 0,0 0,6 9,0 0,0 0,0 0,0 100,0 +26,1 298,0 34 4334,25 72,7 7,0 0,0 0,3 1,6 0,0 0,8 16,0 1,5 0,0 0,0 100,0 +23,1 82,6 38 4335,35 65,5 8,2 0,0 0,3 2,3 0,0 0,7 20,8 2,1 0,0 0,0 100,0 +21,5 3820,0 42 4336,25 89,1 5,0 0,0 0,2 0,9 0,0 0,0 4,7 0,0 0,0 0,0 100,0 +18,9 2630,0 46 4337,25 86,7 5,8 0,0 0,2 1,1 0,0 0,2 6,0 0,0 0,0 0,0 100,0 +20,5 591,0 50 4338,25 82,2 8,5 0.0 0,3 1,4 0,0 0,7 6,9 0,0 0,0 0.0 100,0 +27,4 98,0 53 4339,25 59,7 6,7 0,0 0,0 0,4 0,0 0,3 28,0 4,9 0,0 0,0 100,0 +28,0 514,0 57 4340,25 67,4 5,5 0,0 0,3 0,4 0,0 0,0 24,0 2,5 0,0 0,0 100,0 +24,8 208,0 61 4341,25 68,3 5,5 0,0 0,2 0,4 0,0 0,6 22,6 2,3 0,0 0,0 100,0 +14,7 9,5 65 4342,25 57,0 5,8 0,0 0,0 13,5 0,0 0,0 20,9 2,8 0,0 0,0 100,0 +9,9 16,4 69 4343,25 54,6 5,5 3,2 0,3 16,1 0,0 0,7 16,3 3,3 0,0 0,0 100,0 +* * * SkagerrakFormation * * * +17,9 1,3 73 4344,25 37,5 4,7 4,0 0,0 0,8 0,0 3,1 45,9 3,4 0,6 0,0 100,0 +15,0 - 76 4345,25 43,6 6,9 6,0 0,0 3,6 0,6 0,0 27,9 8,8 0,0 2,6 100,0 +14,4 0,3 80 4346,25 42,6 4,9 4,0 0,0 8,4 0,0 0,0 33,8 4,5 0,0 1.9 100,0 +16,7 0,6 84 4347,25 39,5 5,9 4,7 0,0 1,2 Pj3 0,9 44,0 3,5 0,0 0,0 100,0 +13,4 - 88 4348,25 36,0 6,6 5,3 0,0 2,7 0,3 2,1 42,4 4,5 0,0 0,0 100,0 +11,3 - 92 4349,25 41,1 6,9 5,8 0,0 8,7 1,1 1.3 31,8 3,5 0.0 0,0 100,0 +12,8 0,2 96 4350,25 41,6 6,0 5,3 0,0 10,9 0,7 0,7 29,0 5,7 0,0 0,0 100,0 +14,2 - 99 4351 ,00 46,1 5,7 4,5 0,0 3,9 0,7 0,6 32,5 6,0 0,0 0,0 100,0 +11,4 0,1 104 4352,25 44,7 5,5 6,7 0,0 8,2 1,4 0,0 29,4 3,5 0,0 0,7 100,0 +15,1 - 108 4353,25 43,1 6,0 5,8 0,0 0,6 0,3 0,3 34,4 9,4 0,0 0,0 100,0 +17,2 - 111 4354,00 49,5 6.5 7,6 0,0 0,8 0,5 0,4 32,9 1.9 0,0 0,0 100,0 +Table 5.11 Petrographlc point count data (300 count) In volume percent. From the Heimdal (3643.00 - 3645.50 m) and Hugln +(4328.85 - 4342.25 m) Formations, well 15/9-19 SR. +3etrographiclase Mica RX Pellets HM FG Other QtzCmt FeHCmt Kaolinite Disp. Cl Slay Matrix Carbonate Py-Otxi Org +4 . . Heimdal Firmation * • • +0,25 1,6 1 3643,00 5,0 0,7 57,7 5,0 1,7 1,0 1.0 0,7 0,3 0,0 2,3 0,0 0,0 18,3 4,3 1,0 1.0 0,0 +0,25 1,6 S 3643,50 11,3 1,0 53,3 7,7 1,0 0,7 2,0 1,0 0,0 0,0 4,0 0,0 0,0 16,0 0,7 0,7 0,7 0,0 +0,25 1,6 s 3644,00 • ' ' Poor his SectionQuality - Pont Count Data Not Acqured ' ' ' +0,25 lia 9 3644,50 7,0 1,3 59,7 3,3 ',0 0,7 3,0 0,7 0,7 0,0 1,7 0,0 0,0 19,3 1,3 0,0 0.3 0,0 +0,25 1,6 12 3645,00 10,0 0,0 59,7 2,3 1,0 0,7 1,7 2,0 0,0 0.0 2,3 0,0 0.0 10,7 8,3 0,3 1.0 0,0 +0,25 1,6 14 3645,00 11,3 2.0 54.3 6,3 1,0 1,7 1.7 1,3 0,0 0.0 2,0 0,0 0.0 12,7 4,3 0,0 1.3 0,0 +• • • HuginForrnation ' Total Fefcspar Grn. Cl. +0,30 1,3 14 4328.85 22,3 2,0 63,7 3,0 - 0 0 0 0 0 3,3 0 1 0 0 1 2.7 1 +0,35 1,3 16 4329,25 25,0 0,7 65,7 2,3 - 0,3 0 0 0 0 3 0 1 0 0,3 0,3 1 0,3 +0,40 1,3 20 4330,25 24,3 1,3 64^ 2,7 - 0 0 0 0 0 2.3 0 1,3 0 1,7 0 1.3 0,7 +0,13 1,4 24 4331,25 17,3 2,0 54,0 2.0 4,7 0 0 0 0 5,7 0 5,3 0 4 2,7 1.7 0,7 +0,10 1,6 28 4332,25 19,7 0,7 51,7 2,0 - 1,7 0 0 0,3 0 4,7 0 4,3 0 3 9,7 1.3 1 +0,40 3,0 32 4333,25 12,3 1,7 68,3 5,0 - 1,3 0 0 0 0 3,7 0 2,3 0 2,3 0,3 2 0,7 +0,15 1,5 34 4334,25 17,7 0,7 54,0 5,7 - 1,3 0 0 0 0 7,7 0 3 0 3 2,7 3 1,3 +0,10 1,6 38 4335,35 16,3 1,7 51,0 8,0 - 1,3 0 0 0,3 0 5,3 0 5 0 4,3 2,3 3.3 1 +0,50 2,0 42 4336,25 15,0 0,3 68,7 5,7 - 0 0,3 0 0 0 4 0 0,3 0 2,3 0,3 1,3 1,7 +0,40 2,0 46 4337,25 18,0 1,3 60,0 5,3 1 0 0 0 0 5 0 3,7 0 3 1 1,3 0,3 +0,40 2,0 50 4338,25 15,0 0,3 59,7 5,3 0,7 0 0 0,3 0 6,3 0 3.7 0 5 1,3 1.7 0,7 +0,15 1,4 53 4339,25 16,1 1,0 52,3 3,7 - 3,3 0,3 0 0,7 0 6,7 0 9 0 3,3 0 2 1 +0,15 1,5 57 4340,25 19,0 0,3 55,0 2,3 1,3 0,3 0 0,3 0 10,7 0 5,7 0 2,3 0,3 2 0,3 +0L15 1,4 61 4341,25 19,7 LP. 55,0 4,3 - 0,3 0 0 0 0 9 0 JL7 0 1,3 1,7 1.3 0,7 +0,15 1,3 65 4342,25 7,7 0,0 53.0 3,0 0.7 0 0 0 0 8 0 6,3 0 5 14,3 2 0 +0,15 - 69 4343,25 • . - - - . - - - • - +• • • Skagerrak •ormalion +0,05 - 73 4344,25 - . . - - . - - - . +OJO - 76 4345,25 . - - - - - - . +0,05 - 80 4346,25 . - - - - . - - +0,10 - 84 4347,25 - - - . - . +0,10 - 88 4348,25 - - - . - . +0,10 - 92 4349,25 - - - - - . - . +0,05 - 96 4350,25 - - - - - - - - . +0,05 - 99 4351,00 - - - - - - . - . +0,10 - 104 4352,25 - - - - - - - - +108 4353,25 - - - - - - - - - - +0,10 - 111 4354,00 - - - - . +Legend : Øim - interranular mairoporosity FIX . rock fagments 3tzCmt-cuartz cemer Disp Cl - hijhly micropc ous dispened clay Py - Opq .3yrite and o wr opaque•ninerals +20 - secor*dary porosit HM . heav minerals Feid Cmt - eldspar cer ent Clay Matrix- intergranLar clay Org - orgat c matrix +FG Other-other f råmevork grains +STATOIL +5.6 Jurassic and Triassic sediment distribution on the Gamma +High +The relation between the reservoirs of Jurassic and Triassic age found in the Sleipner Øst +area are very complex. They are either found in the Jurassic Hugin Fm. sandstones (well +15/9-19 SR, 15/9-13, 15/9-11), or in Triassic Skagerrak Fm. sandstones (well 15/9-9) or as +a combination of sandstones of Jurassic/Triassic age (well 15/9-17). However, the age of +these latter sandstones are in some cases disputable (e.g. well 15/9-17, 15/9-15, 15/9- +9). +Except from the 15/9-19 SR well, which proved oil, the Jurassic and Triassic reservoirs are +filled with gas and condensate. The well 15/9-9 is found waterbearing whereas no reservoir +is present in the 15/9-16 well at this level. The fluid contacts are different in each well. +An overview of the contacts, probable hydrocarbon columns and reservoirs in each well is +given in Figure 5.11. +A short summary of the geological evolution on the Gamma High and the Jurassic and +Triassic stratigraphy in the wells, is given below. Where nothing else is indicated, the +geological evolution is taken from Statoil (1984). The fades relations, paleo environment +and sediment distribution of the Hugin Formation in the Gamma High area, is also +discussed. +5.6.1 Deposition of Jurassic and Triassic sediments +During Triassic time, the Gamma High was subaerially exposed and continental deposits +characterize this period. Argillaceous sediments assigned to the Smith Bank Formation +constitutes most of the Triassic intervals encountered in the wells. These sediments were +probably deposited in a lacustrine or muddy floodplain environment. Rejuvenation of source +areas during the Triassic resulted in an influx of arenaceous detritus which characterizes +the Skagerrak Formation. The Skagerrak Formation is generally thinner than the Smith +Bank Fm. and in some places absent. The formation is believed to represent continental +deposits of braided stream/floodplain origin. +Rising sea level during the Early Jurassic, led to marine conditions and sedimentation +throughout the South Viking Graben and the Sleipner Terrace. There is however no direct +biostratigraphic evidence of Early Jurassic sediments in the Gamma High area. Some of +the sandstone reservoirs on the Gamma High, which lack age diagnostic fossils and show +marine sedimentary structures, may be of Early - Middle Jurassic age. +Jurassic sediments are thin on the Gamma structure compared to the Sleipner Terrace to +the west. The Jurassic, in the Sleipner Øst wells, is represented by sediments of Middle +to Upper Jurassic age (Hugin, Heather and Draupne Formations). In the Sleipner Vest +Field, thick Middle Jurassic Bathonian - Bajocian Sleipner Fm. and Callovian Hugin Fm. +77 +STATOIL +sandstones are developed. Middle Jurassic sediments, older than the Hugin Fm., may have +been deposited on the Gamma High. The sediments may then have been subsequently +eroded, contributing as a clastic source area to the Callovian (Hugin Fm.) sands deposited +on the Sleipner Terrace to the west (Cockings et al., 1992). +Corresponding to three major phases of sediment accumulation, the Hugin Formation +previously was divided into three main units, A, B and C (Statoil, 1983a). In a study +concerning the reservoir geology of the Sleipner Vest Field, a new reservoir zonation based +on a sequence stratigraphic framework has been established (Statoil, 1993a). In this study, +an overall backstepping depositional pattern is observed in the Sleipner Vest area, with the +oldest sandstones (Early Callovian) deposited in the north, block 15/6, and the youngest +sandstones (Late Callovian) deposited in block 15/9 (see Figure 5.1). The overall +backstepping pattern is caused by a stepwise transgression of the Sleipner Vest area, +though interupted by regressive events. This is seen as a result of the retreating phase of +the Brent delta megasequence southwards. A flooding event in Early-Middle Callovian time +is believed to represent the initiation of the overall backstepping. +The majority of the Hugin Formation sandstones in the Sleipner Vest area were deposited +during Middle to Late Callovian time (Statoil, 1993a). The western margin of the Gamma +High restricted deposition during Early and Middle Callovian (Statoil, 1983a). The majority +of the Hugin Formation sandstones on the Gamma High were deposited during Late +Callovian. +The present-day distribution of the Hugin Fm. sandstones are highly variable over the +Gamma High structure. The thickness vary from 36 m (e.g. well 15/9-11) to no Hugin Fm. +sands at all (e.g. well 15/9-16). This can be explained by non-deposition or later erosion. +In Early to Mid-Oxfordian, the Hugin Fm. sandstones were overlain by open-marine shales +of the Heather and Draupne Formations. At the end of the Oxfordian, the relative rise of +sea-level was sufficiently high to have eliminated any sand deposition in the Sleipner area. +5.6.2 Jurassic and Triassic stratigraphy in the wells +The observed and interpreted thicknesses of the Draupne, Heather and Hugin Formations +in the seven exploration wells on the Gamma High, are listed in Table 5.12. +In the 15/9-16 well the Jurassic section is entirely absent. The Cretaceous Shetland Group +directly overlies the Triassic Smith Bank Formation. No reservoir is encountered in the +Smith Bank Formation. +In well 15/9-9 the Jurassic sequence is represented by a 17 m thick Viking Group +(Draupne and Heather shales). The underlying sandstones proved to be barren of fossils +and have by RRI (1981) been ascribed to the Triassic Skagerrak Formation. They assume +a terrestrial setting of the whole section. On the other hand, based on fades changes and +borehole log responses, the cored interval has by Statoil (1982) been subdivided in two +78 +O STATOIL +informal subunits; an upper unit (2648 - 2703 m core depth) of marine clastic beach facies +and a lower unit (2703 - 2755 m core depth) of coastal alluvial plain facies. The possibility +that at least the upper part is Jurassic in age, either a Hugin Fm. equivalent or a marine +Early to Middle Jurassic sandstone, can therefore not be ignored. The well proved to be +waterbearing, but the cores show abundant staining of residual hydrocarbons. +In the 15/9-17 well, gas and condensate are found in Jurassic and Triassic sandstones with +gas down to the Triassic Smith Bank Formation. These sandstones are capped by a 3 m +thick Jurassic shale sequence. Based on the core descriptions, Statoil (1983c) has divided +the reservoir sandstones in an Upper Mesozoic sandstone unit (2741 - 2741) m RKB and +a Lower Triassic Skagerrak Fm. unit (2741 - 2847) m RKB. The uppermost 2 m of the +Mesozoic section is interpreted as a possible Hugin Fm. equivalent Due to the lack of age +diagnostic taxa, the age of the Mesozoic sandstone unit are indeterminate. Three alternative +interpretations are considered possible. The section is: +a) attributed to the Hugin or Sleipner Formation. There is no positive palynological +evidence of these formations, although this could be due to the occurence of +unfavourable paleo-environmental conditions. +b) a marine Early to Middle Jurassic. There is no positive biostratigraphic evidence +for this. +c) Triassic. The main argument against this alternative, is that a continental +environment was widespread in Triassic. +The thickness of the Viking Group in well 15/9-19 SR, is only 9.6 m. The underlying Hugin +Fm. reservoir, which is 18 m thick, is heavily faulted. The Hugin Formation is interpreted +to represent a possible mouth-bar setting (see Chapter 5.4.2). The oil is accumulated down +to the Triassic Skagerrak Fm. interval, which is completely tight due to extensive dolomite +and kaolinite cementation. +The Jurassic sequence in well 15/9-13 is made up of 23.5 m of Upper Jurassic shales +deposited over 26.5 m of the Hugin Formation. The Hugin Fm. sands are filled with gas +and condensate down to the Triassic Smith Bank Formation. The upper part of the Hugin +Formation is interpreted to be a progradational lower to upper shoreface sandstone, +whereas the lower part is interpreted to be lagoonal/tidal flat deposits. +Well 15/9-11 drilled a somewhat thicker Upper Jurassic shale section, totally 42.5 m. The +underlying gas and condensate bearing Jurassic Hugin Fm. sandstone is 35.5 m thick. The +depositional environment is interpreted to be progradational lower to upper shoreface +sandstone. This is based on log interpretations, as the Hugin Formation was not cored. +In well 15/9-15 as much as 70 m shales of the Jurassic Viking Group directly overlies +sandstones which constitutes a 99 m gas bearing interval. As in the 15/9-9, Statoil (1983b) +has subdivided the cored interval in an upper suggested foreshore/shoreface sand unit +(2821 - 2860.5 m RKB) and a lower alluvial sand unit (2860.5 - 2948 m RKB). No age +79 +STATOIL +evidence has been obtained from the upper interval. It has so far proven to be barren of +palynomorphs. Three alternative interpretations of their age seem possible: +a) Callovian Hugin Formation. The main argument against this alternative is that the +lithology is atypical of the Hugin Formation. The main argument for a Callovian age +is the marine influence. +b) marine Early to Middle Jurassic Formation. The gradual transition from terrestrial +conditions into marine, which are seen in the cores, may reflect transgressions in +the Early to Middle Jurassic. +c) Triassic. The cores are indicative of marine environment, whereas the environment +was continental in Triassic. +80 +Table 5.12 Thicknesses of the Draupne, Heather and Hugln Formations observed In the 15/9 exploration wells In the Sleipner +Øst area. +15/9 EXPLORATION WELLS +FORMATION -9 -11 -13 -15 -16 -17 -19 SR' +Draupne 2.0m 23.5m 21.0m 55.0m 3.0m 4.2m +Heather 15.0 m 19.0 m 2.5 m 15.0 m 5.4 m +Hugln ? 35.5 m 26.5 m ? ? 18.1 m +* faults in the Hugin Fm.. +O STATOIL +5.6.3 LIthostratigraphic correlation +A suggested lithostratigraphic correlation through the wells 15/9-17, 15/9-19 SR, 15/9-11, +15/9-13, 15/9-16, 15/9-9 and 15/9-15 is shown in Enclosure 14. The reservoir section in +well 15/9-19 SR has not a straight forward correlation with the wells on the Loke, the +Sleipner Øst and the My structures. The correlation is uncertain due to: +the questionable dating of the reservoir section in the 15/9-17 and 15/9-15 wells and +the cored section in the 15/9-9 well +the very large distances between the wells (ca. 2-16 km), which makes the +correlation very difficult +the different depositional environments of the sandstones +sparse data. +5.6.4 Facies relations, depositional environment and sediment distribution +It has not been possible to determine the age of the sandstones in the wells 15/9-9, -15 +and -17. They could probably represent deposits of Early - Middle Jurassic age. In the +Sleipner Øst area, the Hugin Formation is therefore with certainty only identified in the +15/9-11, -13 and -19 SR wells. Only these wells can be used in the sedimentological +analysis of the Hugin Formation. +The 15/9-11 well has also limited value for such analysis, because the Hugin Formation +was not cored in this well. Only two wells have been cored in the Hugin Formation (15/9- +19 SR and 15/9-13). In one of them (15/9-19 SR), the Hugin Formation is heavily faulted. +The well data information of the Hugin Formation is thereby very limited and scattered. +In addition, the present seismic data is generally of poor quality and resolution in the +Jurassic and Triassic sections. It has not been possible to pick the base of the Top +Mesozoic Sandstone reflector from the seismic. The thickness distribution of the Hugin +Formation sandstones has therefore not been possible to picture. The seismic interpretation +so far, has only been completed in the Theta Vest - Loke area and does not cover the +area south of the wells 15/9-11 and -13. +The limited data available exclude a detailed analysis and mapping of thickness and facies +distributions of the Hugin Formation in the Sleipner Øst area at present. A more +generalized description and analysis is however attempted. +Depositional environment and facies relations. +Sedimentological and biostratigraphical analyses of the cored sections in the 15/9-13 and +82 +O STATOIL +15/9-19 SR wells have been performed. +The biostratigraphic data from the 15/9-13 well, conclude that the upper part of the Hugin +Formation is marine, while the lower part lack diagnostic fossils (see paragraph 5.2.4). The +sedimentological analysis interprets the upper part as marine shoreface and the lower part +as lagoonal. Both the biostratigraphic and sedimentologic data interpret increasing marine +influence upwards through the formation. +The biostratigraphic data from the 15/9-19 SR well, conclude that the cored section is +marine with some minor input/runoff from a fresh water source indicated by the presence +of alga (see paragraph 5.2.3). The lower part of the cored interval contains marine fossils +indicative of a shallow marine, high energy "stressed" environment. The upper part of the +core interval contains marine fossils, which indicate more normal and less "stressed" +environment. This indicates a general increase in marine influence upwards through the +cored interval. +The sedimentological analysis of the cored interval in the 15/9-19 SR well, interprets the +formation as a combination of shoreface deposits with channels. These channels could +represent fluvial channels in a mouthbar setting (see paragraph 5.4.2). +Based on logs and biostratigraphy, the Hugin Formation in the 15/9-11 well is interpreted +to be marine. Coarsening upwards sequences seen on the GR and SP logs are interpreted +to represent prograding systems in a shoreface environment (Statoil, 1982). +In the neighbouring block to 15/9, the 16/7 block, the Hugin Formation is identified in two +wells. It is the 16/7-2 well, situated northeast of the Loke structure, and the 16/7-3 well, +situated east of the 15/9-11 well. The formation has been described by Esso (1987) as a +progradational unit developing from shoreface to beach to coastal plain to channelized +sandstone capped by a marine shoreface sandstone. +The shallow marine sandstones in the 16/7 block are of Late Callovian to Early Oxfordian +age (Esso, 1987). Since the Hugin Formation of the Gamma High area mainly were +deposited in the Middle to Late Callovian time, the age of the sandstones in the 16/7 block +supports the backstepping model for the Hugin Formation deposition suggested by Statoil +(1993a). +In summary, the fades described above for the cored wells, in the 15/9 and 16/7 blocks, +suggest a coastal depositional system including shallow marine shoreface deposits, coastal +plain/lagoonal deposits and channel deposits. +The coastal plain/lagoonal deposits are observed in the wells located to the south east +(15/9-13 and 16/7-3). This suggests an onshore to offshore direction towards the northwest +in the 15/9 and 16/7 block. +The description of deposits in the 16/7 wells indicates one main progradation of the +depositional system, terminated by a transgressive retreat in the uppermost part. The +maximum progradation of the coastline will be located somewhere between the 15/9-13 and +83 +STATOIL +the 15/9-19 SR well. +Schematic paleogeographic maps of the Late Callovian and Mid Oxfordian, are shown in +Figure 5.12 and 5.13. The maps show the main areas of erosion/non deposition and +shallow marine upper shoreface sand deposition in blocks 15/9, 16/7, 15/12 and 16/10. +Sand distribution and thickness variation. +The interpretation of channel deposits in the 16/7 wells and also in the 15/9-19 SR well, +implies the possible presence of a fluvial system in the area. +A mouth bar setting has been suggested for the 15/9-19 SR well. This implies the possible +formation and preservation of mouthbar deposits connected to the fluvial channel system. +The 15/9-19 SR well is located close to the main fault zone boundary between the Gamma +High and the Sleipner Terrace. It is known that there is a significant increase in the +thickness of the Hugin Formation across this fault zone in the Sleipner Terrace area (Statoil +1993a). The fault zone could have represented a fault escarpement established before +depositon started, but it could also have been active during deposition. This zone area +therefore would represent a likely position for the developement of possible mouth bar +accumulations. In this area, accomodation space may have been generated through +depositon time, with the possibility of much thicker accumulations of the Hugin Formation +than what is typically observed in the wells situated on the main Gamma High area. +The Theta Vest area is located at the north-west end of several of the NW-SE lineaments +and connected structural depressions located between the Sleipner Øst structure and the +Loke structure. Possible fluvial channel systems may have been guided towards the Theta +Vest area along such depressions. The fluvial system may have been sourced from the +elevated Sleipner Øst structure to the south. +It is therefore suggested an increasing thickness of the Hugin Formation in the areas close +to the Theta Vest structure. This would include the fault-blocks mapped north, west and +south of the Theta Vest structure and also the down-faulted side of the main fault zone. +The isochore map of the Viking Group reveals distinct increases in its thickness within +these fault blocks. The thickness changes and variations are obviously linked to the fault +blocks. This is illustrated in the isochore map of the BCU - Top Mesoz. Sandstone in +Figure 5.14. +Very thick shales (100-150 m) are found in the fault block right north of the Theta Vest +structure. East of this, is another fairly well defined fault block with thicknesses in the range +of 40-60 m. On the structural highs in the area (e.q. on the Theta Vest and Loke), the +thickness is only in the range of 10-20 m. +Although erosion of the Jurassic shales most certainly have occured over much of the area, +the present thickness distribution probably also relates to the primary thickness distribution. +As synsedimentary faulting can be assumed during the deposition of the Hugin Formation, +it is also likely that there is some relations between the thickness distribution of the +84 +STATOIL +Jurassic shales and the primary thickness distribution of the Hugin Formation. The +thicknesses of the Hugin Fm. sandstones can be expected to be larger in depressions and +down thrown areas, compared to what is observed on the highs. +The presence of an active fluvial system in the Loke and Theta Vest area, with an +associated developement of mouth-bar deposition in the Theta Vest area, must be linked +to the early stages of transgression of the sea onto the Gamma High. +85 +THE SLEIPNER AREA +O STATOIL +Middle to Late Jurassic +Chronostratigraphy +Sleipner West Sleipner West Sleipner West Theto West Sleipner East 15/9-16 +15/6 - 15/9-3 "North" "Central" ^South'1 (15/9-19SR) (15/9-11.13) Area +Chronostrotigrophy Area (15/9-1) (15/9-12,6,2.4) (Cenom) +Drauprr +Heather Fm +Hugin Fm +Mixed +Sleipner/Hugin +fades. +Sleipner Fm eipner +/Section +Absent +ui LTEK/A93/U07 Draupne Fm t I Heather Fm [ I Hugin Fi Sleipner Fm (Triossic) Section Absent +VVCLL io/y- iy on +l O ST +OTOIL +Drillinn nmnnnQiS X/prci ic (Hrillinn TPici ilt c +....... +-.•••.'•'••"• +SS:!i;,fVf. "•..:. •.;::: ,.,:;,*?•.««;* +OEJSERVATIONS PROGNOSI5 +STRATIGRAPHY LITHOLOGY LITHOLOGY +Depth +mMSL +UTSIRA +1034 "«"•"•'•"•'t'»*»*»*» 1025 +1156 +SKADE +1231 +1 +2040 +GRID +2170 +2207 2198 +BALDER VV VV VW V +2250 +2268 +SELE +1 2318 +LISTA 2355 +2405 +HEIMDAL +I lf II +2510 +2528 "TT II II +II II +SHETLAND n n II II +it n II II +2759 JJ - -IL - i +GROMER 2785 +KNOLL +i VIKING 2854 2840 +HUGIN 2864 +2882 +SKAGERAK +Sims sinn +TD TD +Legend: +Sandstone |V| Claystone, tuff +Claystone, siltstone l n I Limestone, marl +Figure 5.2 +WELL 15/9-19 SR +STATOIL +Legend of core description +Minerals Deformation structures +- pyrite - soft sediment deformation +- mica - microfault +- siderite - fracture +- carbonaceous +Miscellaneous particles Organic structures +- coal - weakly bioturbated +- moderately bioturbated +-L_-^ - shale +- strongly bioturbated +- ooid +- vertical burrow +O - quartz +- horizontal burrow +Sedimentary structures - ophiomorpha +- planar, parallel, horizontal stratification +Boundaries between units +- gradational, straight +- concave, parallel stratification +- sharp, straight +- wavy, parallel +- undulating +- mud drapes +- trough +- cemented +- hummocky |^xd - seal peal +- undifferentiated ripple +- wave ripple +- current ripple +Figure 5.3 +Sh +p| +U +A +• +TINU +.RGITARTSOHTIL +IEE1 +EI r +MIT +SE: +u. +z +o +X +oc +DC +Ul +0 +co +4.U +.VIDBUS +RIOVRESER +1 CIF 2 +VARFt• Theta Ve +SkacenåkFm. am +Triassic/.lurassic +f +Ul Ci O w +Ul u| +te. c o ) +o c.> +2 +4339— +340 — +4341 — +4342 — +4343 — +4344 — +4345 — +4346 — +4347 — +4348 — +4349 — +4350 — +4351 — +4352 — +4353 — +s +4354 —2 +] +3.19 +YGOLOHTIL +COF +£»EDin +>st WELL NO.- 15/9-1 +j Hugin Fm. CORE NO.:2,A-c +INTERVAL: t «1 S +UJ +- • 3 +-^"1T***« +px3F +1 ^ +u.. 00 ' '.- 0 "*"•» S-t +o • +I +r +0 +-S : ! +* 1 n "-* " J^— * 1s "= l ' • ' +RUBBLE | +i +^H 7 : +: I +::t:_-l += — \ : +i +r-L-.! l +*• ° o- +•t AV Q' ^ ^^\ tu += o'S\ 1 Z 0 +: I» 1^^ N +~£\ +J><^ +JLfc +^F" ~ +— HLJBBL& _j_ _J +• ! j : +' ; 1 +SEICAFBUS/SEICAF +IE +riENI +9sr +ut +,0-43 +C +A- +B +c" +A +B +LANOITISOPED TNEMNORIVNE +DESCRIPTION +fOLOGY DATA SHEET +^^^^^^HMJMPJ^^^^H O STATO l L +DATE: 20.04.93 +54.20 GEOLOGIST: J. E. Allers +DESCRIPTION +ÅND +INTERPRETATION +CC +co +Ul +z +u +_J +3 +u. +Fiaure 5.4 +s +F +U +A +TINU +.RGITARTSOHTIL +| +HCE" +IELI +NIT +GE +LL +Z +5 +3 +.VIDBUS +RIOVRESER[ +r 2 +D/AP +: Hue +Jura +)m( +HTPED +EROC[ +Of 2 +EA: Theta V +|inFnn. +ssic +EDI +est WELL NO.:15/9-1 +CORE NO.:2.A-C +INTERVAL: 4328. +GRAIN SIZE +AND +SEDIMENTARY +STRUCTURES +0 +8 4321 0-1-2-3-4-5-8-7-8 +I I I I I I I I I I 1 I I I +a« 1 *' 1 aMC to** *M lca>t* +1 II lUlM-lcwl 1 1 1 1 1 1 1 +RUBBLE : : '. +X +* ^ »* ^ J f = lo \ .7 ; +i , +**:* Ji ^ : +X +: ; - r i +^T-Ir i +! +**j"t* ^ i +..^...... ...,..n.. "" +v +SEICAFBUS/SEICAF +)E +MEN* +9sr +ut +30-4. +D +AtL +B +C +B +A +B +B-C +B +C +LANOmSOPEDi +| +? +RAB +HTUOM +| +TNEMNORIVNE +DESCRIPTION +FOLOGY DATA SHEET +DATE: 20.04.93 +338.50 GEOLOGIST: J. E. Alters +DESCRIPTION +AND +INTERPRETATION +Figure 5.4 cont. +WELL 15/9-19 SR +STATOIL +Optical micrograph +Formation +Figure 5.5 Optical micrograph from the Heimdal Formation, well 15/9-19 SR, from +3644.50 m, plug no. 7. He Porosity = 26.6%, Klh Perm. = 27.5 md (plane +polarized light, above; cross polarized light, below). Note the medium to +fine grained, moderately well sorted sandstone, with substantial amounts +of dispersed clay. Scale: 1 cm = 0.2 mm. +WELL 15/9-19 SR +STATOIL +Scanning Electron Micrograph +Heimdal Formation +H — +H — +1 10 11 +Figure 5.6 Scanning Electron Micrographs, Heimdal Formation, well 15/9-19 SR, from +3644.50 m, plug no. 7. He Porosity = 26.6%, Klh Perm. = 27.5 md. Note +the substantial amounts of mlcroporous clay (Fe-rlch Chlorite) also formed +on dlagenetic quartz cement. Bar Scale = (as shown on micrograph). +WELT15/9-19SR +Geologic controls on reservoir quality +STATOIL +Hugin Formation +Porosity vs Permeability of Hugin Petrology Data Se +MO iv^v^v:.;^,,.,,^^^ +)Dm +ni +hlk( +ytilibaemreP +10000 +Ipipi?? ; !;i i?i liliiil i ^::i5s SsiSSiSSSS; Sx:;'?;'; såiåilSSJS JSJSsS: ; +llflllillllllll +E looo +_c IIIIIIIIIIH +is4i;;;i;i;i;!^^ : : ; :- Rl £ +M +': +* 100 +3 +£ +CO +U +10 +u +o. +0,1 ::::>:::::v::>::xi:Xy:;:::::;.:: : : i :• : :: ; :j:::x::: r : : i '• .•:.v:::v:::j::::::::::::::x:-:x: +• 0,1 0,2 0,3 0,4 03 06 (1 2 4 6 8 10 12 1 +Grain Size in mm Total Petrographic Clay in Volume % +)Dm +ni +hlk( +ytilibaemreP +i!l!l!!!l!!!!!l!i!!!:!!;l;|:|;!!!^ +±''\-i\-\-\i':-:'\-i:<-: iiiijjiji.' i- '.i'- i:• j.-•':':s•• ••.'•:•.- ^-:y--: ' • .'- '-:::->:'• :\--'^:-^ :-:••- +:!:.::: : :!:: •';: . : : : iiii: . . : :. '•': • \.-:fi :; '': :!? :. ": : ':: .-".- ^HJSSHffl +;.;;v:^s•;:;:B:;::;.S;W;s;:;i;sSsi;:;s::^S;g;:;:;:S'S';:™4:Si^^^ +III '1Illl!^;;ll|| +) 10 20 30 4 +He Porosity % +(Q Geologic controls on reservoir quality of the Hugin Formation, well 15/9-19 SR. Note that variation In grain size and +§ +clay content are the main controls on permeability (A&B), and that porosity Is poorly correlated with permeability +Ol (C). +WELL 15/9-19 SR +Optical micrograph +Hugin Formation +A *\ +F- W-L +rø^sgg +«•x> ramf**&-g j* +^V>, +^^c^^^'^14 SS»S8«85P +%^^^?^^^.^CTv^t.-.iV^--^ +B +C- +u +-ll 1 III +niiiiiimiiiii! +lijlpl! Illllllll +E +~l 1 +F- +G- +"\ +H- +1 1 I I I I I +I I I +1 2 3 4 56 7 8 9 10 11 +Figure 5.8 Optical micrograph from the Hugin Formation, well 15/9-19 SR, from +4330.25 m, plug no. 20. He Porosity = 25.2%, Klh Perm. = 15300 md +showing full diameter view of blue epoxy Impregnated petrographic thin +section. Note medium to coarse grained and well sorted character of the +sandstone, with excellent reservoir properties. Scale: 1 cm = 1.5 mm. +WELL 15/9-19 SR +STATOIL +Optical micrograph +Hugin Formation +i&w^^%; i$i$MM +llf-r^r t *V Hl» /•rvj^; >^V:A.**^jfc^ vi*£7 +1**% . +^ rii'j.v**^ +g +» +c- +::|i i|i i iiiiiiiimiiiii! +|i i ,|i +1 ![l|Tjl +( +F- +"» +G- +V . +l +I l I l I l l l +2 3 4 5 6 8 99 10 11 +Figure 5.9 Optical micrograph from the Hugln Formation, well 15/9-19 SR, from +4331.25 m, plug no. 24. He Porosity = 24.7%, Klh Perm. = 115 md showing +full diameter view of blue epoxy impregnated petrographlc thin section. +Note fine grained character of the sandstone. Scale: 1 cm = 1.5 mm. +WELL 15/9-19 SR +STATOIL +Optical micrograph +Hugin Formation +/• *'A +E — +F— +G- +H — +L J +i i l i i l i i i l i +1 2 3 4 5 6 7 89 10 11 +Figure 5.10 Optical micrograph from the Hugin Formation, well 15/9-19 SR, from +4333.25 m, plug no. 32. He Porosity = 22.7%, Klh Perm. = 312 md showing +full diameter view of blue epoxy Impregnated petrographlc thin section. +Note the poorly sorted character of the sandstone. Scale: 1 cm = 1.5 mm. +SLEIPNER ØST AREA +STATOIL +^^Hydrocarbon columns +"Jurassic and Triassic reservoirs +: +TOP SLIEIPNER0STSTF1UCTURE +"; JJJJJ +2660mMSL - . +:s +TOP LOKE STRUCTURE +2670m MSI — +• +• 1;. +m HI +2693mMSL - +: +?700mMSL +TOP MY STRUCTURE +WELL 15/9-17 1 +271 Om MS L - +CC I +fiiHiSftSJS +M +U ;:S: +WELL 15/9-1 9S R +HUGIN j RESERVOIR +i +2882mMSL - +GWC +2895mMSL - +2900m MS L +hiYDROCARI3ON 1 +• +CCOLUMNS +••••• PROVENGAS +. Hm +CONDENSATE +-IIIE PROVENOIL +•II PRO BABLE +SPILLPOINT GD'r a GAS DOWN TO +' -.'-••'v.x x BWC = GAS WATER CONTACT +MSL = MEAN SEA LIEVEU 1 +Figure 5.11 +LATE CALLOVIAN +STATOIL +Regressive stage +1040' 2000' o 0' +• •/ 2 2 +• +— /* • • +-—• — +• 58°30' +• +/ • +• • +19 SR 17 +• +1 \ Sleipner +£ +11 +t • • • +\ +\ • • +.16 ,13 +• \•i !^^ +• m +\ • • +Both ere•sional ,15 ' +• periods imd +non-marine * +• +sedimentation +15/9 +16/7 +K • 58015' +• +Some paJiohighi +have no ist. +16/23 (erosion ireas). +'- 1512-1 +• • * • +• +- \ +> +l +\ +\ Fenris +\ • « • +t +16/28 16/29 , 15/12 * 16/10 +580Q01 +• \ " +V +: A +V +g\ +km 25 +Legend +Shallow marine, upper ahoreface complex, +Erosion area +medlumfeoarae aandatones. +Mainly offohoreiower ahoreface. Areas suffering both erosion +mud and aUtaonea. non-marine condensation. +Figure 5.12 Paleogeography of the Late Callovlan regressive systems tract (max. +progradatlon). +MID OXFORDIAN +STATOIL +Regressive stage +/ 1°40' 2°00' 2 o 2 0' +-f^- +/* +i +— 1 58°30' +• +/ • +• • +19 SR 17 +• +1\ £Jleipner +• » • 11 • +1 +\ +\ • • +.16 .13 / +• • +A * 9 +/ +N / Late Jurassic +\ - f erosion +1 +\ . • +V 15/9 +16/7 +• i • 58015' +\ +i\. +16/23 1 Eroi iion +1512-1 ? or thi i sst. +• • * • +• +" \ +% +\ +'. • * +\ Fenris +• +\ • • +I +\ +16/28 1 16/29 +58°00' +• \ +V +• \. +• 1 +A +km 25 +Legend +Shallow marine, upper Bhoreface complex, +Erosion area +mediunvcoarse sandstones. +Mainly offahoreiower ohoreface. Areas suffering both erosion +mud and siltsones. noivhiarinc condensation. +Figure 5.13 Paleogeography of the Mid Oxfordlan regressive systems tract (max. +progradatlon). +THETA VEST AREA +STATOIL +Isochore +CD - T.Mesozoic Sandstone +431000 432000 433000 434000 435000 436000 437000 438000 439000 440000 441000 442000 +I r-^ t i i i i if f\ i i l_i i t +» +1 +431000 432000 433000 434000 435000 436000 437000 438000 439000 440000 441000 442000 S +Meter +0 500 1000 1500 2000 2500 +I m25469 3-Dec-93 I +Figure 5.14 +STATOIL +6 PETROPHYSICAL EVALUATION +6.1 Petrophysical analysis +Well 15/9-19 SR has been logged with both MWD and on wireline (WL). Only the WL +logs are used in the petrophysical analysis. A log and core presentation of the Hugin and +Skagerrak Formations, are given in Figure 6.1. +The following wireline logs were run over the reservoir section (run 3A): +DIFL/BHC AC/GR 3567.5 - 46022 m MD RKB +ZDL/CN/GR 3567.5 - 46022 m MD RKB +Tetrofree"-mud was used when drilling the well. With this mud and a 8 1/2" hole the +induction log needs no borehole corrections. The formation resistivity (Rt) is thus set equal +to the deep induction log. +Porosity compaction from lab porosity (ty^ to reservoir porosity ($,„) is done with the +same multiplication factor that is used for this formation on Sleipner Øst. + = 0.965 * +r99 'atm +Porosity is calculated from logged bulk density (RHOB) by using the correlation between +core measured porosity, corrected for compaction, ($j and the logged bulk density. The +r +correlation only uses plug data in net sand intervals and gives: +PHIF = 1.506 - 0.568 * RHOB +Water saturation is calculated from Archies' equation +Rt = a * Rw / (<|>m * Sw") +where a, m and n are derived from SCAL on plugs from the Hugin Fm. in the wells 15/9- +13 and 15/9-17. +6.2 Formations parameters +Special core analysis (SCAL) have been performed on plugs from the Hugin Fm. of the +wells 15/9-11, 15/9-13 and 15/9-17. Conventional plugs were taken from the Hugin Fm. +of 15/9-19 SR as well as in the three above mentioned wells. +101 +STATOIL +The parameters in Archies' equation are estimated from the SCAL on plugs from the Hugin +Fm. of 15/9-17 and 15/9-13. These data define the following values for the parameters: +a=1, m=1.75 og n=1.7. +Formation water resistivity (Rw) is not measured on any water samples from the Hugin +Fm. in any of the wells on Sleipner Øst, and must therefore be estimated from other +sources. It is reasonable to first assume that the salinity in the Hugin Fm. is equal to the +salinity in the Heimdal Fm. As the water saturation calculated with this salinity is +reasonable, this resistivity is used. That is: +Rw=0.0435 am at 93°C at 2435 m TVD RKB +and when corrected to the proper reservoir temperature, assuming a temperature gradient +of 3 °C/100 mTVD: +Rw=0.041 Qm at 105°C in the Hugin Fm. +6.3 Formation temperature +Maximum logged temperature was 110°C at 4586 m MD RKB ( 3067 m TVD MSL) in well +15/9-19 SR. +6.4 Results +Mean of core measured values in net sand are given in Table 6.1 below. The measured +values are reported in Coreteam (1993a). +Table 6.1 Arithmetic mean. +Measurement # plugs mean +grdens 47 2.648 g/cc +por 47 0.233 v/v +klh 45 2762.3 mD +102 +STATOIL +Petrophysical mean results in net sand are given in Table 6.2 below, and the calculated +curves are plotted in Figure 6.2. +Table 6.2 Mean of petrophysical results for the Hugln Fm. of 15/9-19 SR. +Zone Interval Thickness Phif Sw N/G KLH +Hugin 2863.98-2882.04 m TVD 18.059 m TVT 0.226 0.110 0.924 2913.2 mD +4316.50 - 4340.00 m MD 23.5 m MD +103 +WELL 15/9-19 SR +STATOIL +and core presentation +in and Skagerrak Formation +STRATIGRAPHY 151.11 +•T +CD +DRAUPNE + +CO +X +UJ +CO LU QC +< or QC +CD LU +CD +CO +_2320 +.2X0 +Figure 6.1 +WELW5/9-19SR +CPI plott +Hugin Formation +I +i +CD +STATOIL +7 DRILL STEM TESTING +7.1 DST #1 +7.1.1 Summary of analysis +The analysis have been done basically by using Homer analysis for the pressure build-up +periods. A preliminary check of the pressure response away from the near wellbore area +has also been done by matching the data to constant pressure type curves. +The DST #1 has a pressure response away from the wellbore which indicates pressure +barriers. There are signs of a pressure barrier approximately 65 m from the well. In +addition, there are boundary effects approximately 120-260 m from the well. These can be +identified as a combination of pressure barriers and an increase in flow capacity away from +the well. +The test results indicate an oil-bearing formation with very good production capacities. +Table 7.1 gives a summary of the results from the testing phase and the analysis. +Table 7.1 Results from the testing phase and analysis. +DST#1 +Formation Hugin +Interval 4316.0 - 4338.0 m M D RKB +2863.6 - 2880.5 m TVD MSL +Fluid type Oil +Oil density 0.883 +GOR 97-130 SmVSm3 +Max. rate 1358 Sm3/d +Flow capacity, kh 20066 mDm +Test permeability 914 mD +P* 327.7 bar +Pwf 318.6 bar +Reservoir temp. 106.2 °C +PI 144 Sm3/d/bar +Skin 1.7 +The pressures are measured at 2863.9 m TVD MSL. +106 +STATOIL +7.1.2 Objectives +The objectives for the production test were: +quantify amounts of sour gas in the wellstream at surface and downhole +obtain initial formation pressure +collect data for evaluation of reservoir properties and productivity +obtain formation fluid samples and separator fluid samples +investigate boundary effects. +7.1.3 Test performance +The rate history includes the initial clean-up, followed by the test and the main flow. The +well was perforated in underbalance (>80 bar), using diesel as a cushion, with open choke. +The rate was increased in steps up to a maximum of 1358 Sm3/d, two test separators were +used. +After the initial build up, the well was opened to a rate of 75 Sm3/d for PVT sampling. After +the sampling, the well was opened for the main flow period with 1290 Sm3/d. The well +was then shut in for the main build up. See Figure 7.1 for overview of the complete test. +Table 7.2 shows the rates, pressures and flow periods. +107 +STATOIL +Table 7.2 The rates, pressures and flow periods. +Flow period Choke WHP Qo Qg GOR +( mm) (kPa) (Sm3/d) (Sm3/d)(Sm3/Sm3) +First clean up flow 12.70 11740 679 66500 98 +Second clean up flow 15.88 11256 914 88600 97 +Third clean up flow 2x15.88 90260 1358 134000 99 +Clean up build up +Wire line operation/ +BHS operation +Sampling flow 4.76 12220 75 11700 156 +First main flow 12.70 11860 660 65300 99 +Second main flow 2x 15.88 9020 1290 168000 130 +Main build up +Well killed +The pressure data from all four down-hole pressure gauges are in agreement, and the +quality of the data is acceptable. +7.1.4 Analysis +Analysis have been done on the pressure build-up data obtained by one of the four +Halliburton HMR memory gauges at 2719.0 m TVD MSL, HRS-10809. +Table 7.3 Input parameters used for the analysis. +0 +22.1 +n 0.904 (m Pas) +c, 3.38*1 OE-6 (1/kPa) +Bo 1.4374 (Rm3/Sm3) +rw 0.1080 (m) +h 22.0 (m) +T 106.2 +The pressure response indicates several boundary effects. Barriers are identified +108 +STATOIL +approximately 60 m and 250 m from the well. In addition an increase in flow capacity is +observed approximately 125 m from the well. See Figure 7.2 and 7.3. +An analytic model based on a set of pressure boundaries has been used to produce +synthetic pressure data to fit the measured data. Parallel no flow barrier 60 and 255 m +from the well, together with a perpendicular constant pressure boundary 125 m from the +well, give a good match between synthetic and measured data. See Figure 7.4. +The permeability is calculated using data from the main pressure build-up period. The test +analysis give a permeability of approximately 900 mD. The average core permeability +varies between 310 mD and 2.9 D, for various methods. Based on core observations and +log data, the permeability distribution is expected to be non homogeneous, hence the test +permeability is believed to correspond with the core and log data. +The productivity index (PI) is calculated to 145 Sm3/d/bar. +Total skin from the test analysis is approximately -0.2, the completion skin is 0. By taking +the well deviation (in the perforated interval) of 50.2 degrees into account, a damage skin +of 1.7 can be calculated. +Perforation with high underbalance is supposed to stimulate the near wellbore effects. +However, experience from the Statfjord Field shows that high rates give positive skin as +a result of pressure loss through the drill stem between the perforated interval and pressure +gauges. +A skin of 1.7 is the equivalent of a pressure loss of 1.8 bar. This is within the expectations +of a hydraulic frictionloss between the perforated interval and the pressure gauges (197 m +MD), given a heavy and high viscous oil, with a flowrate of 1,310 Sm3/d. +The extrapolated reservoir pressure is calculated to 327.7 bar. +Max. temperature during the cleanup flow was measured to 106.2 °C. +The following fluid properties were measured during the main flow period (choke 15.88 +mm): +Oil S.G. 0.882 +Gas S.G. 0.730 +H S 3.5 ppm +2 +CO 9.5 % +2 +Table 7.4 shows the fluid composition from the recombination of separator samples. Tables +7.5 and 7.6 show the composition and results from the two analysed bottom hole samples. +The results of PVT and compositional analysis of two bottom hole samples and one set +of separator samples from well 15/9-19 SR are reported in Statoil (1993b). +109 +STATOIL +Table 7.4 Composition of reservoir fluid (from recombined separator samples). +Bottle no. TS-55-08 A-14629 +Separator liquid Separator gas Recombined fluid +MOL% MOL% MOL% +Nitrogen 0.06 0.99 0.47 +Carbondioxide 2.78 7.55 4.87 +Methane 15.45 77.79 42.82 +Ethane 5.05 7.54 6.14 +Propane 6.50 3.94 5.38 +i-Butane 0.99 0.34 0.70 +n-Butane 4.02 1.03 2.71 +i-Pentane 1.52 0.21 0.95 +n-Pentane 2.54 0.28 1.55 +Hexanes 3.62 0.18 2.11 +Heptanes 5.76 0.12 3.28 +Octanes 5.64 0.03 3.18 +Nonanes 4.14 0.00 2.32 +Decanes plus 41.93 0.00 23.52 +Sum 100.00 100.00 100.00 +GOR = 88.5 SmVm3 +110 +Table 7.5 Results bottomhole samples. +Bottle no. TS-29-06 TS-61-04 +Stabilized Evolved Recombined Stabilized Evolved Recombined +oil gas fluid oil gas fluid +MOL % MOL% MOL% MOL % MOL % MOL % +Nitrogen 0.00 0.71 0.46 0.00 0.71 0.46 +Carbondioxide 0.00 7.65 4.95 0.00 7.66 4.94 +Methane 0.25 67.10 43.50 0.23 67.27 43.43 +Ethane 0.26 9.34 6.14 0.25 9.26 6.06 +Propane 0.96 7.60 5.26 0.97 7.63 5.26 +i-Butane 0.29 0.91 0.69 0.30 0.90 0.69 +n-B u tane 1.61 3.21 2.65 1.68 3.20 2.66 +i-Pentane 1.11 0.82 0.92 1.15 0.80 0.92 +n-Pentane 2.18 1.15 1.51 2.23 1.11 1.51 +Hexanes 4.46 0.81 2.10 4.47 0.77 2.08 +Heptanes 8.36 0.52 3.29 8.26 0.53 3.28 +Octanes 8.92 0.14 3.24 8.74 0.14 3.20 +Nonanes 6.75 0.02 2.39 6.64 0.02 2.37 +Decanes plus 64.86 0.00 22.90 65.08 0.00 23.15 +Sum 100.00 100.00 100.00 100.00 100.00 100.00 +STATOIL +Table 7.6 Results bottomhole samples. +Bottle no. TS-29-06 TS-61-04 +Gas oil ratio (Sm3/Sm3) 159.1 157.0 +Flash formation volume factor of bubble point 1.505 1.500 +liquid (mVSm3) +Density at bubble point (g/cm3) 0.701 0.702 +Density of stabilized oil (g/cm3) 0.883 0.883 +Gas gravity (air=l) 0.885 0.882 +Density of C10+ (g/cm3) 0.916 0.915 +Bubble point (bar) 273.8 273.2 +112 +WELL 15/9-19 SR +Test performance +BOTTOMHOLE TEMPERATURE, °C BOTTOMHOLE PRESSURE. kPa +100 105 110 30000 31000 32000 +a +IV +i— 95/04/18 — 95/04/18 +IX) ro +— 95/04/19 — 95/04/19 +ro IV +i— 95/04/20 — 95/04/20 +o — 95/04/21 a i— 95/04/21 +IV +a +Q — 95/04 — 95/04/22 +m +r\j +3J +3) +0) +O — 95/04/25 +i i i +ro +RECORDER: HRS-I08O9 RECORDER: HRSHOBOS +Figure 7.1 The performance of bottomhole pressure and temperature for the whole +test period. +WELL 15/9-19 SR STATOIL +Multiple-rate Horner analysis +BY LEAST SQUARES: +118.856 kPo/ +20.0663 +59.26 m +0.12 +M +MULTIPLE-RATE HORNER TIME. ( q - qj_, )LOG( Al/U - tj_, + AD) +; N +3 +co +i +The Semi Log Analysis. +^ +10 +WELL 15/9-19 SR STATOIL +Multiple-rate Buildup analysis +—TESi—T Di—ATEi; 9i9 /19191/9 u9 +10' T 1 I I I I ll| "I 1—I I I I II T 1—I I I I I I T 1—I I I I I I +CO +u +m 118.074 kPo/~ +kh 20.1992 [am2-m +CO +CO k = 0.9181 |am2 +LJ +ZDCt h 22.00 m +k /k 0.910 +LL v H +O CD 150 +s 0.15 +cc +LJ +a +o +\0< +CO +LU +O +l l l l I 111 O l \ +10' +10's 10 -2 10"1 10° 101 102 +MULTIPLE-RATE EQUIVALENT DRAWDOWN TIME. At.. HRS +3! The pressure data with the Type Curve match. +ID +i +Cd +WELL 15/9-19 SR STATOIL +Multiple-rate Horner analysis +o +o TEST DATE: 99/99/99 +N. ^ l l l +TWO PARALLELL N-F BOUNDARIES, 60M AND 255M FROM THE WELL +ONE PERPENDICULAR C-P BOUNDARY,.124M FROM THE WELL +O) +O) +o +o +8 w +Sl +§ +M) +118.074 kPa/~ +20.1992 pm2«m +O 0.9181 pm2 +22.00 m +§» +W) 0.910 +150 +0.15 +o +;-4 -s -2 -1 +3 MULTIPLE-RATE HORNER TIME, - qj_,)LOG(Ai/{ i - ij_, + Ai)) +N +i +The Semi Log Analysis matched with synthetic generated data. +O STATOIL +8 GEOCHEMISTRY +Organic geochemical analyses and interpretations have been carried out on gas (main +flow and bottom hole) and oil (bottom hole) samples from DST#1, well 15/9-19 SR. Gas +analysis were done by IFE. Oil analyses were performed by Statoil's Geochemistry Dept., +with the exception of sulphur content (Production Laboratories, Statoil) and isotopic +analyses (IFE). +Data for well 15/9-19 SR have been compared with results from recent studies of gas, +condensate and oil samples from Sleipner Øst/Loke and Sleipner Vest. +General information on DST#1, together with gas:oil ratios (GOR), H S concentrations and +2 +API gravity of the oil from rigsite reports, are given in Table 8.1. +8.1 Geochemical properties of gas from DST#1, well 15/9-19 SR +The chemical and isotopic composition of the gas is given in Table 8.2 and is shown +graphically in Figs. 8.1 and 8.2. The chemical composition of the gas is comparatively +normal in that it falls within the range generally found in the North Sea province, albeit +with relatively high carbon dioxide (CO ) concentration. +2 +However, the isotopic composition is very unusual compared to the normal trend of steadily +increasing ("heavier") carbon isotope values with increasing carbon number. The gas from +well 15/9-19 SR shows a "zigzag" pattern of increasing and decreasing, but always +unusually light, isotope values on going from methane to ethane, propane and the butanes +(Fig. 8.2). +8.2 Geochemical properties of oil from DST#1, well 15/9-19 SR +8.2.1 Bulk composition +In the context of the North Sea, the oil from DST#1 has a low API gravity (ca. 30° +according to rig reports, Table 8.1) and a very high sulphur content (1.7%, Table 8.3). +These properties are reflected in a high C + fraction (79%, Table 8.3) and very low +15 +saturated hydrocarbon content (30%, Table 8.3). The aromatic hydrocarbon content is +exceptionally high (57%, Table 8.3), whilst asphaltenes are somewhat elevated (3%). +The carbon isotopic composition (513C) of the oil (-27.8%o, Table 8.4) is slightly heavier +than is usually observed in the North Sea, and individual fractions surprisingly show almost +no variation (Fig. 8.3). +117 +STATOIL +8.2.2 Molecular composition +Thompson's indices are given in Table 8.5 and show that the light hydrocarbons are +depleted in branched and cyclic alkanes relative to n-alkanes and aromatics (e.g. high W, +H, S). +Pr/Ph ratio is very low from GC analysis of both the whole oil and saturated hydrocarbon +fraction (0.64 and 0.65 respectively, Table 8.6). The chromatogram from analysis of the +latter fraction (Fig. 8.4) reveals also relatively large amounts of acyclic isoprenoid alkanes +and long chain n-alkanes compared to most North Sea oils. These features are reflected +in a high Ph/nC and low nC /(nC +nC ) ratio (Table 8.6). +1fl 17 17 27 +The GC trace of the aromatic hydrocarbon fraction (Fig. 8.5) contains abundant +phenanthrenes which resulted in calculation of relatively low F1, F2 and MPI1 parameters +in Table 8.7. +The mass fragmentograms from GCMS analysis of the saturated hydrocarbons (Fig. 8.6) +and parameters derived therefrom (Table 8.8) are unusual in several respects. Most +notable are the high relative abundances of bisnorhopane (C28o|3/H = 0.58) and C35o(5 +hopanes (35/34H = 1.03) in m/z 191. Other noteworthy features are the low +diasterane/regular sterane ratio in m/z 217 (dia/reg = 0.72), low hopane/sterane ratio (H/S += 3.12) and high C^ sterane abundance (C30/st = 0.10). +The GCMS analysis of the aromatics fraction resulted in an inability to identify the +monoaromatic steroids in m/z 253 (Fig. 8.7) due to the presence of other components, +and hence failure to measure parameters Aroml and Arom2 (Table 8.9). The triaromatic +steroids were recognisable however and Crackl and Crack2 are reported in Table 8.9. +The values for both are moderate to low. +8.3 Thermal maturity +8.3.1 Gas +The gas has a normal hydrocarbon composition with a gas "wetness" (0.14 for bottom +hole sample, Table 8.2) which suggests a relatively mature sample. However, the "zigzag" +isotopic compositions of the hydrocarbons (see section 8.1 and Fig. 8.2) are extremely +unusual and are not interpretable using currently accepted isotopic models of gas +generation. Hence, no reliable estimate of the thermal maturity of the gas can be made. +118 +STATOIL +8.3.2 Oil +Both the 20S and 22S biomarker parameters (0.54 and 0.60 respectively) have reached +"equilibrium" values, which generally occurs at or around the onset of petroleum generation. +There are other bulk and molecular properties which suggest that the oil was generated +relatively early in the oil generation window (OGW). API gravity is low (ca. 30°), saturated +hydrocarbon content is very low (30%), acyclic isoprenoids are high relative to n-alkanes +(Ph/nC ca. 1), there are relatively abundant long chain n-alkanes, the pp parameter (0.56) +18 +has not reached its maximum ("equilibrium") value of ca. 0.7. +However, the source parameters (section 8.4, below) suggest an unconventional source +rock (in a North Sea context) for the oil, which - if true - may also have affected some +of the maturity parameters. Hence, it is probably safest to conclude that generation of +the oil occurred over the early (lower temperature) to main phase of the OGW. +8.4 Source classification +8.4.1 Gas +The hydrocarbon composition of this gas resembles, in particular, gas from Sleipner Vest +(see section 8.5). However, the "zigzag" trend shown by the carbon isotopes, illustrated +in Fig. 8.2 and discussed in section 8.1, is beyond the scope of current models and makes +it impossible to classify the source of the gas. +The amount of carbon dioxide in the gas is relatively high (7.6% in the bottom hole sample, +Table 8.2) and has a carbon isotope value of -8.0% . These factors together suggest that +0 +the source was mostly thermal degradation of inorganic carbonate (James, 1985). +8.4.2 Oil +The oil properties, both bulk and molecular, are remarkably consistent in indicating that +this sample was generated from a non-clastic marine source rock - i.e. not the Kimmeridge +Clay Formation (KCF) or equivalent (Draupne Formation here) in its normal form. Key +features which support this interpretation are: +i) bulk properties such as the API gravity and high sulphur content (30° and +1.7% respectively) +ii) biomarker parameters including low Pr/Ph ratio (0.65), high bisnorhopane +(C28ap/H 0.58), low diasteranes (dia/reg 0.72), abundant extended hopanes +119 +STATOIL +(35/34H 1.03). +All of the above are characteristic of oils from carbonate/siliceous source rocks and are +unusual for a North Sea oil. Other parameters, such as C30/st, confirm that the source +rock was deposited in a marine environment +Thus the oil was most likely generated from a non-clastic (i.e. carbonate or siliceous) +marine source rock. This could have been either an Upper Jurassic KCF equivalent with +an unusual facies, or a completely different and as yet undiscovered source. +8.5 Comparison of Theta Vest with Sleipner Øst, Loke and +Sleipner Vest +Sleipner Øst, Loke and Sleipner Vest have been the subjects of recent geochemicai reports +(Statoil, 1993g; Statoil, 1993h). The following is a summary of the main conclusions for +these areas. +8.5.1 Sleipner Øst and Loke +The hydrocarbon gases have very similar chemical and isotopic compositions throughout +the Heimdal and Hugin Formations, both in Sleipner Øst and Loke. Only the amount of +CO shows any trend amongst the gas components, being in lower abundance in the +2 +Heimdal Formation than the Hugin. Low amounts of CO tend also to be slightly +2 +isotopically lighter. +The gas was probably generated from either coals or marine sediments with significant +land plant input, at thermal maturities corresponding to the end of the oil window. The +hydrocarbon gases in Sleipner Øst are wetter and isotopically lighter than in Sleipner Vest, +indicating that they were generated at a somewhat lower maturity. +The very low amounts of CO in the Heimdal Formation were probably co-sourced with +2 +the hydrocarbons; where concentrations are slightly higher in the Hugin Formation, this is +a reflection of a separate input from thermal breakdown of carbonates. +The condensates in the Heimdal Formation comprise a homogeneous data set, with no +lateral (across the field) or vertical (intra-well) trends in geochemicai composition visible. +In contrast, the condensates from the Hugin Formation on Sleipner Øst form a separate +group with different geochemicai properties to those from the Hugin Formation in Loke +and well 15/9-15. The latter are more similar in geochemicai properties to those from the +Heimdal Formation. +120 +STATOIL +The condensate in the Heimdal (all wells) and in the Hugin in well 15/9-15 and Loke may +well have been co-sourced with the gas - or possibly have come from the same source +rock type (dominated by terrestrial organic matter - OM) but at slightly lower thermal +maturity. In contrast, the condensate in the Hugin on Sleipner Øst came originally from +a conventional oil-prone marine source rock, and corresponds to a fluid generated at top +of the oil window or onset of oil to gas cracking. The condensate was probably dissolved +in the gas phase by the later-generated gas from a terrestrial source. +8.5.2 Sleipner Vest +On Sleipner Vest the bulk of the gas has been derived from a different source than the +oil/condensates. Source variations have also been recognized amongst the oil/condensates. +The gases have a very uniform hydrocarbon composition, characteristic of condensate- +associated material generated at a maturity level of approx. 1 -1.5% R . The coals of the +0 +Hugin and Sleipner Fm. are the most likely source rocks for this gas, but at greater burial +depths than those present in the Sleipner Vest field. +CO content in the gases increases when going from the southern part of the field both +2 +in northern and eastern direction. This trend coincides with a larger-scale regional variation +in both content and isotopic ratio of CO , which is thought to be related to the input of an +2 +isotopically heavy, CO -rich gas from the Viking Graben into this area. +2 +The composition of the condensates from Sleipner Vest is very uniform, with the exception +of well 15/9-1 (both oil and condensate). This indicates that the latter well is located in an +isolated field segment which has received a stronger influx of material derived from marine +OM (Draupne Formation?). +All the other condensates have been generated from source rocks containing both terrestrial +and marine OM. This could be a more terrestrial facies of the Draupne Formation +(compared to 15/9-1) or it could reflect mixing of petroleum generated from the Draupne +with that from a terrestrially dominated source (Hugin/Sleipner coals?). +8.5.3 Comparison with Theta Vest +Figure 8.8 contains a comprehensive classification of fluids (gases, condensates and oils) +discovered to date in the greater Sleipner area. The fluid types are classified according +to field/structure, formation, thermal maturity and source rock type. Note that it applies +only to the hydrocarbon components of the gases - carbon dioxide is dealt with separately +below. The figure shows that four different source rock types/combinations and four +maturity levels have been identified to date (excluding the undassifiable gas from Theta +Vest). The following general points can be made: +121 +STATOIL +- throughout the area, the thermal maturity level apparently increases, as +might be expected, in the order oils < condensates < gases; +- no attempt has been made to discriminate between.thermal and phase +effects. Thus the former may in fact be due to the latter (e.g. condensate +in 15/9-1 may be a phase and not a thermal process) and hence the thermal +maturity categories are deliberately broad and overlap; +- the oil from Theta Vest is unique in coming from a non-clastic marine +source rock and has many properties which are very unusual for the North +Sea province; +- the Draupne Formation (KCFs) is the source of a) the oil in 15/9-1, +Sleipner Vest; b) the condensates in 15/9-1 and in wells from the Hugin +Formation on Sleipner Øst; +- coals, or a marine source rock dominated by terrigenous OM, are the +proposed source of i) the condensates and the gas in the Heimdal Formation +on both Sleipner Øst and Loke, as well as ii) the gas in the Hugin Formation +on both Sleipner Øst and Loke and iii) the gas in the Hugin Formation on +Sleipner Vest; +- a mixed terrigenous/marine OM source was most likely for the condensate +in the Hugin Formation on Sleipner Vest (i.e. either a mixture of fluids from +a coal and Draupne Fm. source or a single source rock with a mixed organic +input). +Thus in summary it can be seen that there are wide variations in source rock type of the +oils, condensates and gases across the Sleipner area. The oil and gas from Theta Vest +have properties which are unlike those for any other fluid found elsewhere in the area. +The origin of carbon dioxide in the area is, in one sense, simpler in that there are only +two proposed sources: either low amounts generated from OM in the source rock or high +amounts from an inorganic carbonate source. These two origins can be distinguished on +the basis of the carbon isotope values, as illustrated by Fig. 8.9 which shows %CO in +2 +the gas versus 513C for C0 for all samples from the area. It was reported previously +2 +that the CO in Sleipner Vest is more abundant and comes predominantly from breakdown +2 +of inorganic carbonate; in contrast the low amounts in Sleipner Øst and Loke originate +mostly from OM degradation. However, the CO from Theta Vest resembles that from +2 +Sleipner Vest in terms of abundance and isotopic composition, and as such is in contrast +to other samples from the Sleipner Øst area. +122 +Table 8.1 Available gas and oil samples from well 15/9-19 SR. +Formation Sample Geochem. Perforated Gas/oil API gravity2 H S2 +2 +type sample Interval1 ratio2 (ppm) +no. (mRKB) +(SM3/SM3) +Hugin DST#1 S6891 4316-4338 98-141 30.0-31.1 1-6 +1 Uncorrected depths +2 Values taken from rigsite reports +Table 8.2 Chemical and Isotoplc composition of gases from DST#1, well 15/9-19 SR1. +a) Chemical composition +Sample Sample c, c, c IC nC« IC nC COj ZC,-C: Wetmess2 +3 4 5 s 5 +type no. +Main flow 11993 75.8 8.3 4.9 0.42 1.5 0.29 0.39 8.4 91.6 0.17 +Bottom hole 11994 79.5 7.0 4.0 0.35 1.0 0.21 0.28 7.6 92.4 0.14 +b) Isotoplc composition +Sample Sample c, c, c, C IC nC CO, CO, +3 4 4 +type no. 813C 5D S13C 613C 513C 513C 513C 8190 +%oPDB %oSMOW %»PDB %>PDB %oPDB %PDB %oPDB %oPDB +Main flow 11993 -40.0 -209 -30.0 -33.2 -30.9 -35.6 -8.4 -11.4 +Bottom hole 11994 -40.5 -212 -30.3 -33.0 -30.6 -35.1 -8.0 -11.1 +1 Data from IFE +2 Wetness = ZC +Table 8.3 Bulk composition data for oil sample from well 15/9-19 SR. +Sample Sample C + Saturates Aromatlcs Polars Asphaltenes Sulphur1 +15 +type no. % % % % % % +Bottom hole S6891 79 30 57 10 3 1.7 +1 Sulphur content from PROLAB +Table 8.4 Isotoplc composition data for oil sample and fractions from well 15/9-19 SR1. +Sample Sample 813C (%.) +type no. OH Saturates Aromatlcs Polars Asphaltenes +Bottom hole 12009 -27.8 -27.9 -27.6 -27.6 -27.5 +1 Data from IFE +Table 8.5 Thompson's Indices1 from light hydrocarbons analysis of oil sample from well 15/9-19 SR. +Sample Sample A B X W CI FH U R S +type no. +Bottom hole S6891 0.55 0.86 0.41 13.7 1.8 1.5 1.5 30.8 0.7 2.8 289 +1 From Thompson, 1983 Inter alia +Aromaticity +A = benzene/nC B = toluene/nC X = m+p-xylenes/nC W = 10*benzene/cC +6 7 B 6 +Parafflnlcltv +C = (nC +nC )/(cC +mcC ) I = (2mC +3mC )/(1cis3dmcC +1t3dmcC +1t2dmcC ) +6 7 e 6 6 e 5 6 5 +F = nC /mcC H = (100*nC )/(cC +2mC +2,3dmcC +3mC +1cis3dmcC +1t3dmcC +1t2dmcC +nC +mcC ) +7 8 7 6 6 5 6 6 5 5 7 6 +Naphthene branching +U = cCe/mcCji +Paraffin branching +R = nC^mCe S = nCe/2,2dmC +4 +Codes: n = normal; c = cyclo; C = hexane (etc); m = methyl; dm = dimethyl; t = trans +6 +STATOIL +Table 8.6 Data from GC analysis of whole oil and saturates fraction, well 15/9- +19 SR. +Sample Pr/nC Ph/nC A/B Pr/Ph +17 18 +type1 (A) (B) +Whole oil 0.48 0.99 0.48 0.64 0.80 +Saturates 0.55 1.1 0.52 0.65 0.82 +1 Bottom hole sample (S6891) +Pr pristane Ph phytane nC n-heptadecane +17 +nC n-octadecane nC^ n-heptacosane +18 +Table 8.7 Data from GC analysis of aromatics fraction from oil, well 15/9-19 +SR. +Sample F1 F2 MPI1 +no/ +S6891 0.43 0.12 0.66 +1 Bottom hole sample +3/2 (2-MP + 3-MP) +MPI1 = +P + 1-MP + 9-MP +3-MP + 2-MP +F1 = +3-MP + 2-MP + 9-MP + 1-MP +2-MP +F2 = +3-MP + 2-MP + 9-MP + 1-MP +P = phenanthrene M = methyl +127 +Table 8.8 Blomarker parameters from GCMS analysis of saturated hydrocarbon fraction of oil from well 15/9-19 SR. +Sample Sample Biomarker parameter +type no. 20S PP 22S Ts/Tm TtX 30D/H ppmH ppmS +Bottom S6891 0.54 0.56 0.60 0.56 0.15 0.02 2179 698 +hole +%C27 %C28 %C29 C30/St Dla/reg C28otp/H HIS +36 28 35 0.10 0.72 0.58 3.12 +3R/H 4R/H 35/34H Dem/H O/H G/H 3000 29/30H +0.06 0.05 1.03 0.00 0.00 0.03 0.93 0.43 +Derivation of biomarker ratios +Ratio Derivation +Triterpanes +22S 32opS/(32apS+32opR) 191 +Ts/Tm 27Ts/27Tm 191 +TtX 30D/29pa 191 +30D/H 30D/3000 191 +29/30H 29apV30aB 191 +30ap 30apV(30ap+30pa) 191 +C28ap/H 28a0/30ap 191 +3R/H (23/3)/30a0 191 +4R/H (24/4)/30afl 191 +35/34H (36apR+36c +; +4 +H +' 5 +• +1ATOIL +• • •— • +-mmoMmimi mmmm mm• +•BB +m, mmm +— 1° +— ————— — +— — +- +- +••• +15/9- 19RS DSTI SAT Amoiink,: l.« •— +i) C +r- +T1 +C.) +200 +03 +«• +C a i •* +* > +L3 Cj +O> +t +* +180 o +C. cj +i +p +! jr +c. i +H > +> C +L +£ 160 +>» S +*> u +fnl Ci +C. +g +£ +M r +r5 [ +c ! 8i l} +140 C. +j +n i ; i i +Jl +* +120 +InU +IM. +J M +i. J fc t J +4i 4&k +kjH» ^JH +^l MJkl(A* X +^^ +J ^ +J +100 i +•fl 1 1 1 1 1 l l , 1 i | i i | 1 1 1 1 i i 1 1 i 1 i i i | i 1 1 1 1 +.0 10 0 15.0 20.0 25.0 30.0 X.0 40 0 45.0 +1 Time (minites) +§ +9° Gas chrornatograrn of tr ie saturatec1 hydrocart>on fi•actlcn frc>m DST*' 1 Oil weII 15!/9-19 SR. +WELCT5/9-19SR +Gas chromatogram +STATOIL +(Q +i +CD +bi 5.0 10.0 15.0 20.0 25.0 30.0 35.0 40.0 45.0 +Time (minutes) +Gas chromatogram of the aromatic hydrocarbon fraction from DST#1 oil, well 15/9-19 SR. +WELL 15/9-19 SR +STATOIL +Mass fragmentograms +OG LAB-BASE The TRIO-1 GC-MS Data System +Sanple:BIOMARKEF, SATURATED FRACTION Instrument:Trio-l +27299840 +100 +XFS- +g +J +- +•(J LAW +6- +Minis.0 20.0 25.0 30.0 35.0 40.0 45.0 50.0 +UG LAB-BASE The TRIO-1 GC-MS Data System +Sample:BIQMARKER, SATURATED FRACTION Instrument:Trio-1 +iSATBZ +7449608 +1001 +217 +•1 +XFS +Hin 15.0 20.0 25.0 30.0 35.0 40.0 +Figure 8.6A Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - long plots. +WELL 15/9-19 SR +STATOIL +Mass fragmentograms +UG LAB-BASE The TRIO-1 GC-MS Data Systen +SanpleiBlOHARKER, SATURATED F R A C T I O N I n s t r u n e n t : T r i o -l +SATEI2 +5939280 +180- 177 +«1 +XFS +e- +Min 30.0 35.0 40. B 45.0 50.0 +UG LAB-BASE The TRIO-1 GC-MS Data Systen +Sanple:BIOMARKER, SATURATED FRACTION Instrunent:Trio-l +SAT02 +27299848 +100- 191 +j •I +I +X.FS-I +(>,.-..>._--- ' +30.0 35.0 40.8 45.0 50.0 +Figure 8.6B Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - short plots. +WELL 15/9-19 SR +STATOIL +fragmentograms +UG LAB-BASE The TRIO-1 GC-MS Data System +Sample:BIOHARKER, SATURATED FRACTION Instrument :Trio-l +SAT02 +5447680 +liØØi 205 +ttl +xFS +r* Wy^ -- v +--' +ø_, +Min 30.0 35.0 40.0 45.0 50.0 +UG LAB-BASE The TRIO-1 GC-MS Data System +Sample: B lOMflRKER, SATURATED FRACTION Instrumenter i o-l +7449600 +217 +«1 +:Min 22.0 24.0 26.0 28.0 30.0 32.0 34.0 36.0 38.0 40.0 42.0 44.0 +Figure 8.6C Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - short plots. +WELL 15/9-19 SR +STATOIL +Mass fragmentograms +UG LAB-BASE The TRI0-1 GC-HS Data System +Sanpl:BIOriARKER, SATURATED FRACTION Instrument:Trio-l +e +SAT82 +2*«» 8282112 +;iøøi +'/ 218 +«1 +Zf/t/f +I/ +ixFS- +J +" WI« +0- +Min 22.0 24.0 26.0 28.0 30,0 32.0 34.0 36.0 38.0 40.0 42.0 44.0 +UG LAB-BASE The TRIO-1 GC-MS Data System +Sanple:BIQHARKER. SATURATED FRACTION Instrument:Trio-1 +SAT02 +100 3735552 +219 +#1 +XFS +i i +0- +!Min 22.0 24.0 26.0 28.0 30.0 32.0 34.0 36.0 38.0 40.0 42.0 44.0 +Figure 8.6D Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - short plots. +WELL 15/9-19 SR +STATOIL +kMass fragmentograms +UG LAB-BASE The TRIO-1 GC-HS Data System +Sanple:BIQMARKER, SATURATED FRACTION Instrument:Trio-1 +SAT* +J2 +17227776 +:100- 231 +ttl +X.FS +L +uL^^____. +j|l 1 V lv +,', , , ^Jk& >vv ' r +lVL +n +._ TJ_.-' S^v*»"1" *__-• (J 'w<-..^v-^v^s-''~-v-' -—•"•" *W **• N* +Min 22.0 24.0 26.0 28.0 30.0 32 0 34.0 36.0 38.0 40.0 42.0 44.0 +UG LAB-BASE The TRIO-1 GC-MS Data System +Sample:BIOMARKER, SATURATED FRACTION Instrument:Trio-1 +2ATB2 +1699072 +259 +ttl +XFS^ +n \\ +Min 22.0 24.B 26.0 28.0 30.0 32.0 34.0 36.0 38.0 40.0 42.0 44.0 +Figure 8.6E Mass fragmentograms from GCMS analysis of saturated hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR - short plots. +WELL 15/9-19 SR +STATOIL +Mass fragmentograms +VG LAB-BASE The TRI0-1 GC-MS Data System +Sample:BIQMARKER, AROMATIC FRACTION Instrument:Trio-l +S6891AR +løe 4214784 +142 +«l +X.FS +e +• • • i ' ' • ' i • • ' i " • • +Min 4.50 5.00 5.50 6.00 6.50 7.00 7.50 8.00 8.50 +UG LAB-BASE The TRI0-1 GC-MS Data System +Sample: B IOMARKER, AROMATIC FRACTION Instrument :Trio-l +29286400 +XFS +iMin 4.50 5.00 5.50 6.00 6.' 7.00 7.50 8.00 8.50 +Figure 8.7A Mass fragmentograms from GCMS analysis of aromatic hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR. +WELL 15/9-19 SR +STATOIL +|Mass fragmentograms +VG LAB-BASE The TRIO-1 GC-MS Data System +SanpleiBIOHARKER, AROMATIC FRACTION Instrument:Trio-1 +sbb' +31AR +\ 134078272 +10W f +P (oi*rlcr**Ud ) 178 +XFS- +L +VY, A-. yVj[uA r - ~ ',,-\_--~A -. -A -^^A'^.^,. ^•^-•-.^ _ __. . +=11- Spi +Minj 2.3 14 .0 16.0 18.0 ' 20.0 22.0 24.0 +UG LAB-BASE The TRIO-1 GC-MS Data Systen +Sample:BIOHARKER, AROHATIC FRACTION Instrument:Trio-1 +S6891AR +97648640 +100- 192 +«1 +XFS +, IA /s +Minia.0 14.0 16.0 18.0 20.0 22.0 24.0 +Figure 8.7B Mass fragmentograms from GCMS analysis of aromatic hydrocarbon +fraction from DST#1 oil, well 15/9-19 SR. +WELL 15/9-19 SR +STATOIL +Mass fragmentograms +VG LAB-BASE The TRI0-1 GC-MS Data System +SamplejBIOMARKER, AROMATIC FRACTION Instrument:Trio-l +5>68