Thesis Signe and Mari

Signe Berg Verlo and Mari Hetland

Development of a field

case with real production

and 4D data from the

Norne Field as a

benchmark case for future

reservoir simulation model

testing

Trondheim, 06.06.2008

Master thesis

NTNU

Norwegian University of Science and Technology

Faculty of Engineering Science and Technology

Department of Petroleum Engineering

and Applied Geophysics

Preface

The work presented in this Master thesis was conducted in the 10th semester of the Master

of Science studies at NTNU. It was written at the Department of Petroleum Technology and

Applied Geophysics, spring 2008. The work was prepared by the authors with Professor Jon

Kleppe as academic adviser.

We would like to express our gratitude to Professor Jon Kleppe for guidance and advice

throughout the thesis work. We are also very grateful for the help we have received from

StatoilHydro by Anna Fawke, Kristin Seim and Trine Alsos. Finally we would like to thank

Stein Krogstad from Sintef and Alexey Stovas, Jan Ivar Jensen, Knut Backe, Bjarne Foss and

Egil Tjåland at NTNU for their help and support.

Trondheim, 6. June 2008

Mari Hetland Signe Berg Verlo

I

Abstract

Reservoir simulation models are essential tools for the development of oil and gas elds. These

realistic models are used for calculating reservoir volumes, for well planning, and to predict

future behaviour of elds. Building and maintenance of robust, reliable reservoir models are

time-consuming and expensive. Research based on simulation models could improve existing

methods and tools utilized for this work. One of the objectives of the research program 2 in the

Center for Integrated Operations in the Petroleum Industry (IO Center) at NTNU is to develop

methods for rapid updates of the reservoir model or geological model for petroleum elds, based

on 4D seismics, production data and other available data. As a pilot case, the Norne Field is

selected.

It is of great importance to have a real model which is open for several research institutions,

to compare various methods used on the same set of data. Currently, there exists no model with

real data. Therefore, NTNU in collaboration with StatoilHydro wish to establish a model based

on the Norne Field.

The Norne eld is located in the Norwegian Sea. It was discovered in December 1991 and

started producing November 1997. The Norne reservoir rocks were deposited from Late Triassic

to Middle Jurassic. Petrophysical results from the Norne Field are mainly based on the results

from exploration wells. A total of 49 wells are drilled, 3 exploration wells and 46 production and

injection wells. Seismic surveys were acquired in 2001, 2003, 2004 and 2006. These surveys have

good quality and 4D seismics has been extracted. The base case simulation model is history

matched until December 2006, and predicts reservoir development until January 2022. The

model is run in Eclipse 100, which is a standard black oil simulator, and input can easily be

converted for use in other reservoir simulators.

The objective of this master thesis has been to shape a reservoir model using real data from

the Norne Field. The assignment emphasizes the design of a benchmark case for research, and

focus on the utility value of a model with real data, open for several research communities.

A number of possible cases can be designed when constructing a benchmark case. The Norne

benchmark case should exploit the good quality data which is available, and promote comparative

studies of alternative methods for history matching. Through this study it has been found that

the potential for the Norne benchmark case is great, and release of the data set could benet a

number of institutions. The challenges will be to provide synchronized data and ensure thorough

contact between StatoilHydro and the IO Center. In addition, there is a need for qualied

personnel to maintain consistency in published data and to provide support for the users.

II

Contents

1 Introduction 1

2 Introduction to the Norne Field 3

3 Detailed description of the Norne Field 8

3.1 Geology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

3.1.1 Zonation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

3.1.2 Stratigraphy and sedimentology . . . . . . . . . . . . . . . . . . . . . . . . 12

3.1.3 Reservoir Communication . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

3.2 Petrophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

3.2.1 Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

3.2.2 Interpretation parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

3.2.3 Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

3.2.4 Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.2.5 Uncertainties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

3.2.6 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

3.3 Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3.3.1 Exploration wellbores . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3.3.2 Description of exploration wells . . . . . . . . . . . . . . . . . . . . . . . . 45

3.3.3 Development wellbores . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

3.3.4 Description of development wells . . . . . . . . . . . . . . . . . . . . . . . 50

3.4 4D seismic data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

3.4.1 Introduction to 4D seismic data . . . . . . . . . . . . . . . . . . . . . . . . 59

3.4.2 Seismic processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

3.4.3 Seismics on Norne . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

3.5 Production data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

3.5.1 Data acquisition during production . . . . . . . . . . . . . . . . . . . . . . 71

4 Reservoir Simulation Model 73

4.1 Reservoir Modelling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

4.2 Description of the base case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

4.2.1 History Period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

III

4.2.2 Prediction Period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

4.3 Eclipse reservoir simulator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

4.4 Section Keywords . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

4.4.1 runspec . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

4.4.2 grid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

4.4.3 edit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

4.4.4 props . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

4.4.5 regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

4.4.6 solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110

4.4.7 summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

4.4.8 schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

5 Development of a benchmark data base 116

5.1 TNO Case Study - The Brugge Field . . . . . . . . . . . . . . . . . . . . . . . . . 116

5.2 Norne benchmark case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

5.2.1 Available data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

5.2.2 Unavailable data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

5.2.3 Description of benchmark case . . . . . . . . . . . . . . . . . . . . . . . . 118

6 Discussion 120

7 Conclusion 123

A Nomenclature 1

B Figures 3

B.1 Well plots . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

B.2 Seismic results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

B.2.1 3D seismic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

B.2.2 4D seismic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

C Tables 38

C.1 Production Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

C.2 Injection Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

D Eclipse .DATA le 74

IV

List of Figures

2.1 The location of the Norne Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

2.2 Development of the Norne Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

2.3 The Vessel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

2.4 Gross Production of Oil, April 2006 - March 2008 . . . . . . . . . . . . . . . . . . 5

2.5 Gross Production of Gas, April 2006 - March 2008 . . . . . . . . . . . . . . . . . 6

2.6 Gross Production of Sm3 o.e., April 2006 - March 2008 . . . . . . . . . . . . . . . 6

2.7 Gross Production of Water, April 2006 - March 2008 . . . . . . . . . . . . . . . . 7

3.1 Structural setting of the Norne Field . . . . . . . . . . . . . . . . . . . . . . . . . 9

3.2 Stratigraphical sub-division of the Norne reservoir . . . . . . . . . . . . . . . . . . 10

3.3 Old and new zonation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

3.4 Cross-section Through Reservoir Zone Isochores . . . . . . . . . . . . . . . . . . . 12

3.5 Stratigraphic chart . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

3.6 Structural cross sections with uid contacts . . . . . . . . . . . . . . . . . . . . . 18

3.7 Location of exploration wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

3.8 Correlation of Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

3.9 Cores from Garn Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

3.10 Cores from Not Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

3.11 Cores from Ile Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

3.12 Cores from Ror Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

3.13 Cores from Tilje Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

3.14 Cores from Tofte Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

3.15 Fluid model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

3.16 Cross plot core porosity vs. core permeability . . . . . . . . . . . . . . . . . . . . 34

3.17 CPI-plot Well 6608/10-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

3.18 Log Well 6608/10-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

3.19 Log Well 6608/10-4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

3.20 NE-SW running structural cross section through the Norne Field . . . . . . . . . 42

3.21 Map of the seismic survey area, with wells . . . . . . . . . . . . . . . . . . . . . . 60

3.22 The pre-stack portion of the full seismic processing ow . . . . . . . . . . . . . . 61

3.23 The post-stack portion of the full seismic processing ow . . . . . . . . . . . . . . 62

3.24 3D seismic, line number 1100 showing oil-water contact in 2001 and 2006 . . . . . 65

V

3.25 3D seismic, trace number 1600 showing oil-water contact in 2001 and 2006 . . . . 66

3.26 4D seismic, line number 1100, 2001-2006 . . . . . . . . . . . . . . . . . . . . . . . 67

3.27 4D seismic, trace number 1600, 2001-2006 . . . . . . . . . . . . . . . . . . . . . . 68

3.28 4D seismics overlaid interpreted pressure dierence , 2001-2006 . . . . . . . . . . 69

3.29 Example of synthetic seismics from Norne . . . . . . . . . . . . . . . . . . . . . . 70

4.1 Reservoir zonation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

4.2 Fault transmissibility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

4.3 The drainage strategy for the Norne Field from pre-start and until 2005 . . . . . 80

4.4 Reservoir simulation model at simulation start, History period . . . . . . . . . . . 81

4.5 Reservoir simulation model at the end of the history period . . . . . . . . . . . . 82

4.6 Field Oil Production Rate, History Period . . . . . . . . . . . . . . . . . . . . . . 83

4.7 Field Oil Production Total, History Period . . . . . . . . . . . . . . . . . . . . . . 84

4.8 Field Pressure, History Period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84

4.9 Field Gas-Oil Ratio, History Period . . . . . . . . . . . . . . . . . . . . . . . . . . 85

4.10 Field Water Cut, History Period . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

4.11 The drainage strategy for the Norne Field from 2005 and until 2014 . . . . . . . . 87

4.12 Reservoir simulation model at the end of the prediction period . . . . . . . . . . 88

4.13 Field Oil Production Rate, Prediction Period . . . . . . . . . . . . . . . . . . . . 89

4.14 Field Oil Production Total, Prediction Period . . . . . . . . . . . . . . . . . . . . 90

4.15 Field Pressure, Prediction Period . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

4.16 Field Gas-Oil Ratio, Prediction Period . . . . . . . . . . . . . . . . . . . . . . . . 91

4.17 Field Water Cut, Prediction Period . . . . . . . . . . . . . . . . . . . . . . . . . . 91

B.1 Oil Production Rate B-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

B.2 Watercut B-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

B.3 Gas-Oil Ratio B-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4


B.5 Watercut B-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

B.6 Gas-Oil Ratio B-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6


B.8 Watercut B-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

B.9 Gas-Oil Ratio B-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7


B.11 Watercut B-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

B.12 Gas-Oil Ratio B-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

B.13 Oil Production Rate D-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

B.14 Watercut D-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

B.15 Gas-Oil Ratio D-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10


B.17 Watercut D-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

VI

B.18 Gas-Oil Ratio D-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12


B.20 Watercut D-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

B.21 Gas-Oil Ratio D-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13


B.23 Watercut D-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

B.24 Gas-Oil Ratio D-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

B.25 Oil Production Rate E-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

B.26 Watercut E-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

B.27 Gas-Oil Ratio E-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16


B.29 Watercut E-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

B.30 Gas-Oil Ratio E-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18


B.32 Watercut E-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

B.33 Gas-Oil Ratio E-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19


B.35 Watercut E-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

B.36 Gas-Oil Ratio E-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

B.37 Oil Production Rate K-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

B.38 Watercut K-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

B.39 Gas-Oil Ratio K-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

B.40 Water Injection Rate C-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

B.41 Gas Injection Rate C-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23






B.47 Water Injection Rate F-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26




B.51 3D Seismic, line number 1100 showing the oil-water contact in 2001 . . . . . . . . 29




B.55 3D Seismic, trace number 1600 showing the oil-water contact in 2001 . . . . . . . 33



VII


B.59 4D Seismic, line number 1100, 2001-2003 . . . . . . . . . . . . . . . . . . . . . . 35

B.60 4D Seismic, line number 1100, 2001-2004 . . . . . . . . . . . . . . . . . . . . . . 36

B.61 4D Seismic, trace number 1600, 2001-2003 . . . . . . . . . . . . . . . . . . . . . 37

B.62 4D Seismic, trace number 1600, 2001-2004 . . . . . . . . . . . . . . . . . . . . . 37

VIII

List of Tables

3.1 Calculated gradients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

3.2 n-values for the zone groups . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

3.3 Recommended eld values of permeability . . . . . . . . . . . . . . . . . . . . . . 33

3.4 Cut-o values, Oil Case, Well 6608/10-2 . . . . . . . . . . . . . . . . . . . . . . . 35

3.5 Cut-o values, Gas Case, Well 6608/10-2 . . . . . . . . . . . . . . . . . . . . . . . 36

3.6 Cut-o values, Oil Case, Well 6608/10-3 . . . . . . . . . . . . . . . . . . . . . . . 36

3.7 Cut-o values, Gas Case, Well 6608/10-3 . . . . . . . . . . . . . . . . . . . . . . . 37

3.8 Petrophysical Parameters G-segment . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.9 Initial GOC and OWC on the Norne Field . . . . . . . . . . . . . . . . . . . . . . 41

3.10 Exploration wellbores . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

3.11 Development wellbores . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

4.1 Reservoir zonation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

4.2 Reservoir properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

4.3 Injection rates during the prediction . . . . . . . . . . . . . . . . . . . . . . . . . 87

4.4 New production wells during the prediction . . . . . . . . . . . . . . . . . . . . . 88

4.5 Tansmissibilities between regions . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

4.6 Fluid-in-place for each region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

4.7 Numerical layers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

4.8 Geological layers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

C.1 Production data for well K-3 H . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

C.2 Production data for template B . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

C.3 Production data for template D . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

C.4 Production data for template E . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

C.5 Injection data for template C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

C.6 Injection data for template F . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

IX

Chapter 1

Introduction

Reservoir simulation models are powerful and essential tools for the development of oil and gas

elds. These realistic models are used for calculating reservoir volumes, for well planning, and to

predict the future behaviour of the eld. Building and maintenance of robust, reliable reservoir

models are time-consuming and expensive. The objective of this master thesis is to shape a

reservoir model with real data from the Norne Field in the Norwegian Sea.

The purpose of designing this model is to provide a benchmark dataset with real data, which

can be used by dierent institutions to compare the performance of dierent simulators and

simulation methods. The Norne Field is suitable because it is a rather young eld, with high

quality 4D seismic data and production data. It has been in production since November 1997

and has still many years left of production. StatoilHydro, which is the operator of the eld, is

positive to collaborate with NTNU and the Center for Integrated Operations in the Petroleum

Industry (IO Center). The IO Center will use the Norne model in their research program 2;

Real-time reservoir management. The release of the model is to be decided by StatoilHydro

and partners. If released, several users of the dataset could discuss their results of simulations

from a common basis. The IO Center is planning to design and provide a benchmark case for

use in reservoir simulation model testing. This benchmark case could be the rst of its kind

with real data. The aim is to establish a collaboration between several research institutions,

universities and companies and communicate results of the testing.

The master thesis is divided into two main parts. The rst consists of a description of the

Norne Field independent of simulation models. The second part comprises a description of the

base case simulation, with basis in the Eclipse input data. The goal is to make a good description

of a test case for simulation and history matching based on real data. This master thesis might

be used as a foundation for the test case planned by the IO Center.

The thesis starts with an introduction to the Norne Field in Chapter 2. Chapter 3 presents a

detailed description of the eld. This includes geology, petrophysics and all the wells on the eld.

Both exploration, and production/injection wells are described. The chapter also contains an

introduction to 4D seismic data as well as available seismic data from the Norne Field. Finally,

the production data is described and rates are included in table format in appendix C.1 and C.2.

Chapter 4 provides a description of the reservoir simulation model. It comprises the base case

1

simulation, the Eclipse simulator and the Eclipse input le with explanations of all keywords

used in the data le. A proposal for how the Norne benchmark case can be designed is presented

in Chapter 5. It also gives suggestions about what types of data that should be provided and at

what time. A discussion of the utility and potential for this kind of reservoir simulation models

is stated in Chapter 6. The chapter also deals with challenges connected to the shaping of a

benchmark case. Chapter 7 nally presents a conclusion.

2

Chapter 2

Introduction to the Norne Field

The Norne Field was discovered in December 1991. Development drilling began in August 1996

and oil production started November 6th 1997. The eld is located in the blocks 6608/10 and

6508/10 in the southern part of the Nordland II area in the Norwegian Sea, as seen in gure 2.1.

Sea depth in the area is about 380 m.

Figure 2.1: The location of the Norne Field [Statoil, 2001c]

Norne consists of two separate oil compartments; Norne Main Structure (Norne C-, D- and

E-segment), which contains 97% of the oil in place, and the North-East Segment (Norne G-

segment).

A 135 m hydrocarbon-bearing column was discovered from the exploration well, 6608/10-2

3

consisting of a 110 m thick oil leg with an overlying gas cap. The hydrocarbons were found in

the rocks of Lower and Middle Jurassic age. [Statoil, 2001c]

The eld is being developed with a oating production and storage vessel tied to six subsea

templates. An illustration of the eld is shown in gure 2.2. The well stream is carried by

exible risers to the vessel, which rotates around a cylindrical turret anchored to the sea oor.

The vessel has storage tanks for stabilised oil and a processing plant is located on the deck of

the ship. Figure 2.3 shows the vessel.

Figure 2.2: Development of the Norne Field [Statoil, 2001c]

Figure 2.3: The Vessel [NPD, 2008]

Approximately 0.403 mill Sm3 of oil was produced from 11 well slots in December 2007.

Water is injected in 8 wells. The Norne Field has produced 77 mill Sm3 of oil in total per

December 2007 [NPD, 2008]. That is approximately 86% of recoverable reserves. The Norwegian

Petroleum Directorate estimated the 31st of December 2006 the recoverable reserves to be 90

mill Sm3 of oil and 10.70 bill Sm3 of gas. Remaining reserves are estimated to be 17.3 mill Sm3

of oil and 5.7 bill Sm3 of gas. Gas production started in 2001. The eld is producing about

0.052 bill Sm3 of gas/month. [NPD, 2008]

4

Figures 2.4, 2.5, 2.6 and 2.7 illustrates the gross production of oil, gas, oil equivalents and

water per month from April 2006 until March 2008. The graphs shows that the production of

oil and gas gradually decrease while the water production increases.

StatoilHydro is the operator of the Norne eld with Petoro AS and Eni Norge AS as partners,

with respectively 39.1, 54.0 and 6.9 per cent interest.

Several studies have already been performed on the Norne Field. The results are described

by [Huseby et al., 2005], [Kowalewski et al., 2006], [Selle et al., 2008], [Steensen and Karstad,

1995], [Al-Kasim et al., 2002], [Boutte, 2007] and [Ouair et al., 2005].

Figure 2.4: Gross Production of Oil, April 2006 - March 2008 [NPD, 2008]

5

Figure 2.5: Gross Production of Gas, April 2006 - March 2008 [NPD, 2008]

Figure 2.6: Gross Production of Sm3 o.e., April 2006 - March 2008 [NPD, 2008]

6

Figure 2.7: Gross Production of Water, April 2006 - March 2008 [NPD, 2008]

7

Chapter 3

Detailed description of the Norne Field

3.1 Geology

The Norne eld is located in the blocks 6608/10 and 6508/10 on a horst block in the southern

part of the Nordland II area in the Norwegian Sea. The horst block is approximately 9 kmx 3 km [Ouair et al., 2005]. Figure 2.1 shows the location of Norne, while gure 3.1 shows the

structural setting of the eld. The eld is situated at the transition between the Nordland Ridge

and the Dønna Terrace, in an area called the Revfallet Fault Complex as seen in the gure. The

Nordland Area, which includes the Norne Field, has been exposed for two periods of rifting; in

Perm and Late Jurassic - Early Cretaceous. During the rst rifting, faulting aected a wide part

of the area. Especially normal faults, with NNE-SSW trends, are common from this period. The

second rifting period can be subdivided into four phases ranged in age from Late Bathonian to

Early Albian. The trend during this rifting was footwall uplift along the Nordland Ridge, and

erosion of high structures. Between the two rifting periods the tectonic activity was limited,

although some faulting occurred in the Mid and Late Triassic. This period was dominated by

subsidence and transgression. Some unconformities are discovered, possibly related to tectonic

activity. These unconformities are found between the Tofte and Tilje Formations, and within

the Ile Formation. After the last rifting no major structural development aecting the Norne

reservoir has taken place. The reservoir has gradually been buried deeper, allowing the oil and

gas to form and to accumulate within the reservoir. The rocks within the Norne reservoir are of

Late Triassic to Middle Jurassic age.

The reservoir sandstones in the formations Tilje, Tofte, Ile and Garn, are dominated by

ne-grained and well to very well sorted sub-arkosic arenites. The sandstones are buried at a

deep of 2500-2700 m and are aected by diagenetic processes. Mechanical compaction is the

most important process which reduces reservoir quality. Still, most of the sandstones are good

reservoir rocks. The porosity is in the range of 25-30 % while permeability varies from 20

to 2500 mD. [Statoil, 2001c]

The source rocks for the oil and gas in the Norne Field are believed to be the Spekk Formation

from Late Jurassic and coal bedded Åre Formation from Early Jurassic [NPD, 2005]. A source

rock is a rock of high organic content, which under the right circumstances, temperature and

8

Figure 3.1: The structural setting of the Norne Field [Statoil, 1994a]

pressure, will form oil and gas.

The cap rock which seals the reservoir and keeps the oil and gas in place is the Melke

Formation. The Not Formation behaves as a cap rock, preventing communication between

the Garn and Ile Formations. Also keeping the hydrocarbons in place is the rotated fault

blocks, in this relation called traps. Oil and gas is lighter than water and will migrate upward

until it is trapped. Both a cap rock and a trap is needed to preserve the hydrocarbons in the

reservoir. [Statoil, 1994a]

3.1.1 Zonation

The present geological model consists of 17 reservoir zones. Today's reservoir-zonation is slightly

altered from earlier subdivisions. The main dierence is that the Ile and Tofte zones have been

further subdivided, and the Tilje zones have been simplied. An illustration of the zonation

from 2001 can be seen in gure 3.2. The zonation is made to correspond as good as possible to

9

Figure 3.2: Stratigraphical sub-division of the Norne reservoir [Statoil, 2001c]

the actual change of lithology in the layers of the reservoir. Hence, boundaries between zones

are chosen at sequence boundaries and maximum ooding surfaces. Litological boundaries and

distinct breaks in porosity or permeability that correlates across the eld can also be basis for

the zonation. [Statoil, 2001c] Oil is mainly found in the Ile and Tofte Formations, and gas in the

Garn Formation [NPD, 2008].

The geological zonations from 2002 and 2006 are illustrated in gure 3.3. As seen from the

gure; Not is called Not 1, Garn has changed name to Not 2 and Lower Melke Formation has

changed name to Not 3. The Tilje Formation is still divided into four zones with no further

subdivision. The old names will still be used in the continuance of this thesis as the geomodel

considered is from 2004.

10

Figure 3.3: Old and new zonation [Fawke, 2008]

11

3.1.2 Stratigraphy and sedimentology

The entire reservoir thickness, from Top Åre to Top Garn Formations, varies over the Norne

Field from 260 m in the southern parts to 120 m in the northern parts [Statoil, 1994a], see

gure 3.4. The reason for this dierence is the increased erosion to the north, causing especially

the Ile and Tilje Formations to decrease in height [Statoil, 1995]. This has been found from

seismic mapping [Statoil, 1994a].

Figure 3.4: Cross-section Through Reservoir Zone Isochores [Statoil, 1994a]

The Åre Formation is the lowest formation within the Norne Field and has a heterolitic

composition. It is mainly comprised of channel sandstones which are 2-10 m thick and interbed-

ded with mudstones, shales and coals. The Åre Formation was deposited during Hettangian to

Early Pliensbachian, see gure 3.5. The total thickness of the formation varies a lot; from 200 min the southern Haltenbanken Area, to a more than 800 m thick column discovered in well

6608/10-2. An increased sand/shale ratio eastwards is discovered. The depositional environment

was probably alluvial to delta plain setting, transported from a source area to the east. [Statoil,

1994a]

12

Figure3.5:

Stratigraphicchart[InternationalCom

mission

onStratigraphy,2004]

13

The Tilje Formation was deposited in a marginal marine, tidally aected environment.

Sediments deposited are mostly sand with some clay and conglomerates. The source of the

sediments was located west of the Norne Area. The formation is thinning to the north due to

decreased subsidence rate during the deposition, along with increased erosion to the north/north-

east at the base of the overlying Tofte Formation. An unconformity is discovered at the top of

the Tilje Formation. This hiatus was most likely created due to uplift, followed by subaerial

exposure and erosion. It was probably the result of an important tectonic event. The hiatus

marks the transition from heterolitic sediments of the Åre- and Tilje Formations into thicker

marine sandstones of the overlying formations. The Tilje Formation is divided into four reservoir

zones based on biostratigraphic events and similarities in log pattern. Tilje 1 is not cored in

either of the wells 6608/10-2 nor 6608/10-3, but it is believed to consist of two sequences of

sand that is coarsening upward and a more massive sand at the top. Tilje 2 has a heterolitic

composition consisting of; sandstone layers of variable thicknesses, heavily bioturbated shales,

laminated shales and conglomeratic beds. A varying depositional environment is characteristic

for Tilje 2 deposits. Tilje 3 consists of ne grained sand which has a low degree of bioturbation.

It is therefore possible to see muddrapes, crossbedding and wave ripples in the depositions. Im-

plications of the presence of fresh water are also found. Tilje 4 is a ne grained, bioturbated and

muddy sandstone in the lower parts, while upper parts have conglomeratic beds interbedded

with thin sandstone and shale layers. [Statoil, 1994a]

The Tofte Formation was deposited on top of the unconformity mentioned above dur-

ing the Late Toarcian. Mean thickness of the Tofte Formation across the eld is 50 m. The

depositional environment was marine from foreshore to oshore. To the east of the Nordland

Ridge the depositions from this age is mostly shales, whilst sand were deposited to the west. In

addition, there is proof of minor erosion at the top of the ridge. It is therefore assumed that

the Nordland Ridge was a barrier for sand transportation to the east. The Tofte Formation

is divided into three reservoir zones. Tofte 1 consists of medium to coarse grained sandstones

with steep dipping lamina. The lower parts are more bioturbated and have ner grains. The

dip of the layers suggests that the source area for sediments was to the north or northeast of

the eld. Another important issue about Tofte 1 is the limited distribution in the east-west or

northeast-southwest direction. Tofte 2 is an extensively bioturbated, muddy and ne grained

sandstone unit. Floating clasts can be found in the lowermost part of the section, which is

coarsening upward. Tofte 3 consists of very ne to ne grained sandstone where almost none

of the depositional structures are visible because of bioturbation. Some low angle dipped layers

occur in the upper part. There is a coarser grained bed representing a sequence boundary at

the top of the unit, this is the Upper Toarcian-Aalenian boundary. [Statoil, 1994a]

The Ror Formation is time equivalent with the Tofte Formation and is a very ne

grained/shaly unit. In addition to the sand content, glauconite, phosphate nodules and calcare-

ous shells can be found in the extensively bioturbated sandstone deposition. These depositions

indicate that the depositional environment was in a lower shoreface, with low sediment supply.

Despite its shalyness the formation is assumed to have good reservoir quality. The Ror Forma-

14

tion is only 8.5 m thick at the Norne Field. At the top of the formation a calcareous shells has

been dissolved and cemented, creating a calcareous cemented unit. This may be a barrier to

vertical uid ow. [Statoil, 1994a]

The Ile Formation was deposited during the Aalenian, and is a 32-40 m thick sandstone.

The depositional environment was in the shoreface. This formation is divided into three reservoir

zones; Ile 1, Ile 2 and Ile 3. The separation between Ile 1 and Ile 2 is the same as the boundary

between the Ror and Ile 1 Formations, a cemented calcareous layer. These layers are probably

the result of minor ooding events in a generally regressive period. Both the calcareous layers are

correlative in the wells 6608/10-2 and 6608/10-3, and are assumed to be continuous throughout

the Norne Field. Ile 2 and Ile 3 are separated by a sequence boundary, which is an indicator of the

change from regressive to transgressive environment. The reservoir quality of the Ile Formation

is generally good, especially in the regressive depositions, whereas the reservoir properties are

decreasing toward the top of the formation. Ile 1 and Ile 2 both consist of ne to very ne

grained sand which is coarsening to the north. Bioturbation, glauconites and plenty of calcareous

shell fragments are all evidence of the depositional environment. Despite bioturbation some

lamination and ripples can be seen, but the quantity is not sucient to determine the transport

direction. The coarser grained sequence boundary that was mentioned above is at the top of

Ile 1. Ile 3 lies above the sequence boundary and is an extensively bioturbated, upward ning

sandstone of ne to very ne grains. This zone also contains glauconites, phosphorite nodules

and clay clasts, which are signs of periods of starvation during the transgression. [Statoil, 1994a]

The Not Formation was also deposited during Aalenian time. It is a 7.5 m thick, dark

grey to black claystone with siltstone lamina. The depositional environment was quiet marine,

probably below wavebase. However, palynological ndings indicate that there was freshwater

inuencing the environment. This is explainable if one assumes that the water column in the

basin was stratied, hence preventing the water from mixing before it reached far into the basin.

The Not Formation has a coarsening upward trend which continues into the Garn Formation.

Therefore, it can be found a layer of very ne grained, bioturbated sandstone in the upper part of

the formation. The upward coarsening indicates deposition during a regression. [Statoil, 1994a]

The Garn Formation was deposited during the Late Aalenian and the Early Bajocian,

and is a 35 m thick sandstone. The depositional environment was near shore with some tidal

inuence. Reservoir quality is increasing upward within the formation, from pretty good in the

lower parts to very good in the upper parts. This formation is also divided into reservoir zones

based on diering properties and deposits. For the Garn Formation the number of reservoir zones

is three. Garn 1 is a sandstone unit which is coarsening upward, from very ne to ne grained

sand. The lower part is muddy and bioturbated, as it is the continuance of the Not Formation,

while the upper part has an increased sand content. This part of the formation has aser

beddings, ripple lamination and thin layers of coarser grained sandstone. At the top of Garn 1

a coarse to very coarse grained, garnet rich bed is found. This bed is interpreted to be a beach

deposit from the maximum regression period; it is a sequence boundary that is correlateable

in the Norne wells. Garn 2 is a transgressive deposition consisting of ne grained sandstones,

15

where some layers are bioturbated while others are laminated. At the top, a calcareous cemented

sandstone unit is discovered. It represents a starvation in the supply also called maximum

ooding surface. This layer is expected to be continuous throughout the eld and can be a local

barrier to vertical uid ow. The lower part of Garn 3 is not cored in any of the wells. The

upper part of this zone is made up of low angled cross bedded and ne grained sandstone. A

coarse grained bed is located in the top of Garn 3. This is an erosional surface from maximum

regression. The Garn Formation is much thinner in well 6608/10-1 and most of Garn 2 and the

entire Garn 3 are missing in this well. This is due to tectonic uplift in the north during the

deposition. The Garn Formation south of the Norne eld is thicker due to higher subsidence

rates, which give more accommodation space. At the top of Garn 3, sandstone and mudstone

sediments with oating clasts are found. This is a result of ravinement and reworking during a

transgressive period. [Statoil, 1994a]

The Melke Formation was deposited during the Late Bajocian to the Early Bathonian.

The thickness of the formation varies from 212 m to 160 m, in the wells 6608/10-2 and 6608/10-3.

The formation is dominated by claystones with thin siltstone lamina in between. The deposi-

tional environment was in oshore transitional to lower shoreface. Within the Norne Field the

oshore transitional environment is dominating, while the lower shoreface environment is dom-

inating to the north. This indicates that the land was located north of the Norne Field, which

also is the sedimental source area. Three coarsening upward units are found in the lower parts

of the Melke Formation. Each of these is nished o with muddy, very ne grained sandstone.

The Melke sandstones in well 6608/10-1 was earlier correlated to the Garn Formation on the

Norne Field, but by considering biostratigraphical evidence it is clear that the Melke Formation

is younger than the Garn Formation. The Melke Formation acts as a seal in the eld. This is

because it is not well enough developed to provide reservoir rock properties. [Statoil, 1994a]

Within the Tofte, Ile- and Garn Formations there exist three calcareous cemented layers, as

mentioned above. They are all interpreted to be continuous over the entire Norne Field. These

cemented layers, together with the shaly Not Formation, are believed to act as stratigraphic

barriers to vertical uid ow within the reservoir. The sealing qualities of the Not Formation have

been veried through FMT (Formation Multi Tester)-data from wells drilled since production

start. Thickness of the Not Formation across the eld is between 7-10 m, while the thickness of

the calcareous layers vary in the range of 0.5-3 m. Other layers which are believed to restrict the

vertical uid ow is Tilje 4, base Tofte 2 and base Tofte 4. ESP(Event Simularities Predictions)-

data, dip and azimuth maps generated at the top reservoir level indicate that the eld might

be more faulted than illustrated by structural depth maps as described in section 3.1.3. [Statoil,

1994a]

3.1.3 Reservoir Communication

Vertical and lateral ow in the Norne Field is aected by both faults and stratigraphic barriers.

Although these barriers are not expected to be important in a eld-wide scale, it is important

to consider the eect they have on the uid ow to enhance the drainage strategy.

16

Faults

Faults, especially major faults, can be discovered by studying seismic data. This, along with the

known history of the area, contributes to conrm the positions of the faults. As the Norne Field

is located on a horst, there are a number of faults. Figure 3.6 illustrates cross sections through

the Norne Field with uid contacts and faults. Each sub-area of the fault planes has been

assigned transmissibility multipliers. To describe the faults in the reservoir simulation model,

the fault planes are divided into sections which follow the reservoir zonation. These are functions

of fault rock permeability, fault zone width, the matrix permeability and the dimensions of grid

blocks in the simulation model.

Measurements of the permeability on Norne fault rocks are impossible because no faults or

shear fractures are encountered in the cores cut on the eld. The best analogue to Norne is the

Heidrun Field which is located about 80 km from the Norne Field. In 1996, three main fault types

in the Heidrun cores were found. These are cataclasite, pyhllosilicate framework fault rock and

clay smear. Clay content of the sediment is the most important factor for nding the dominating

rock in the fault zones. To model the faults, average permeability values were assigned to each

category fault rock. The sealing capacity of a fault is important because it determines the uid

ow across the fault. There are two ways to determine the sealing potential, the Smear Gouge

Ratio (SGR) and the Knott-method.

17

Figure 3.6: Structural cross sections through the the Norne Field with uid contacts [Statoil,2001c]

The Smear Gouge Ratio considers clay smear to be the potential sealing mechanism. Hence,

the sealing potential of the fault is based on the calculated SGR, which is the sand-to-shale ratio

in the fault gouge. In order to calculate the SGR, the following parameters need to be examined;

fault displacement, reservoir thickness and the ratio permeable/non-permeable rocks. All faults

examined on the Norne Field are intra-reservoir faults, which mean that the fault displacement

is less than the reservoir thickness. The equation for the SGR is then:

SGR = (sand/shaleratioforRu + sand/shaleratioforRd) /2

The ratio of reservoir to non-reservoir rocks has been determined from gamma ray and neutron

density logs in the exploration wells 6608/10-2 and 6608/10-3.

18

The Knott-method calculates the Fault Seal Probability (FSP). The calculation is based on;

the normalized displacement, connectivity and the net-to-gross interval. This method has been

calibrated using known sealing and non-sealing faults from the Brent Group in the North Sea.

Based on this, the FSP is classied as; low for FSP=0-30%, medium for FSP=33-66% and high

for FSP=66-100%.

Results of the fault seal analysis, using both methods, indicate that the faults within the

Norne horst block most likely are non-sealing. However non of the methods are calibrated to

apply to the relatively new Nordland Area formations and it is therefore dicult to know if it

can be directly applied to the Norne Field.

A signicant amount of lineaments are discovered from ESP data including dip and azimuth

maps generated at the Top Garn level. These lineaments trend NNW-SSE and SW-NE parallel

to the two main fault strike directions on the eld. Some of the lineaments are identied as

small faults on the seismic data, which lead to a more faulted eld than shown in the structural

maps. The displacement of these faults is probably between 5 and 20 m. [Statoil, 2001c]

Stratigraphic barriers

Several stratigraphic barriers are present in the eld. Their lateral extent and thickness variation

are assessed using cores and logs. Continuous intervals which restrict the vertical uid ow within

the Norne Field are listed below;

Garn 3/Garn 2 - Carbonate cemented layer at top Garn 2Not Formation - Claystone formationIle 3/Ile 2 - Carbonate cementations and increased clay content at base Ile 3Ile 2/Ile 1 - Carbonate cemented layers at base Ile 2Ile 1/Tofte 4 - Carbonate cemented layers at top Tofte 4Tofte 2/Tofte 1 - Signicant grain size contrastTilje 3/Tilje 2 - Claystone formation

Core photography's have been used to select representative core plugs. To determine average

vertical permeability kv for each barrier, kv measurements are used. Pressure development in the

eld clearly indicates what inuence the stratigraphic barriers have on ow within the reservoir.

Most prominent barriers to ow are the Not Formation, the carbonate cemented layers which

separate Ile 1 and Tofte 4 Formations, and the claystone which separate Tilje 3 and Tilje 2

Formations. [Statoil, 2001c]

19

3.2 Petrophysics

The petrophysics of the Norne main eld is based on data from the two exploration wells 6608/10-

2 and 6608/10-3. In 1994 the exploration well 6608/10-4 was drilled in the G-segment creating

base for the petrophysical interpretation of this area. The base measurements for the evaluation

are; wireline log data, core analysis, formation pressure points and uid samples. [Statoil, 2001c]

A total picture of the porosity of the Norne Field is obtained by relating the core porosity

to the density log. As a consequence, the water saturation has to be calculated using Archie's

formula. The net to gross ratio and permeability were also estimated in this study. For the

G-segment, separate values for net to gross ratio, porosity, water saturation and permeability

were calculated. [Statoil, 2001c]

Since the rst study, other wells have been cored on the Norne Field. This includes wells

6608/10-D-1 H, 6608/10-C-4 H and 6608/10-F-1 H. Based on these new cores, revision has been

worked out on porosity/permeability relations and the water saturation. [Statoil, 2001c]

The petrophysical parameters have been modelled in the geological model using co-located

co-kriging to acoustic impedance [Fawke, 2008].

3.2.1 Data

Well Information

Well 6608/10-2 was spudded October 28th 1991. The well was located at

66°,00',49.35"N08°,04',26.48"E

Total depth (TD) of the well was at 3678 m below Rotary Kelly Bushing (RKB), and this

depth was reached December 16th the same year. In January 1992, there were carried out four

drill stem tests on this well, which tested gas in the Garn Formation, oil in the Tofte Formation

and water in the Tofte/Tilje Formation.

The well discovered a hydrocarbon column of 135 m in the rocks of Lower and Middle

Jurassic. 110 m was oil, and the rest was an overlying gas cap.

Well 6608/10-3 was located at

66°,02',06.66"N08°,04',57.97"E

This well was spudded January 1993 and Total Depth (TD) was reached at 2991 m February

19th 1993. The month after, one drill stem test was performed, which tested oil in the Ile

Formation.

The well conrmed the test results from well 6608/10-2, and proved the extension of the eld

to north.

20

66°,02',25.26"N08°,09',41.74"E

Well 6608/10-4 was spudded in the end of 1993 and was located at

This well was drilled in the northeast segment, which is located approximately 3 km east of

the main structure. An oil column of 30.5 m was discovered in the same structures as the main

eld.

Figure 3.7 illustrates the location of the exploration wells. Alternating red and green indicates

that there exist both oil and gas. Green represents oil, while red represents gas.

Figure 3.7: Location of exploration wells [NPD, 2008]

21

Log data

The wells 6608/10-2, 6608/10-3 and 6608/10-4 have been logged with generally good quality.

Logs give important data for geophysical interpretation of the area. The dierent logs used for

acquiring data in the eld are mentioned below along with the logging interval given in m.

Well 6608/10-2:

mwd - 465-3335lwd-cdr cdn - 2100-2573difl acl gr - 867-3661zdl gr - 867-1525zdl cnl cal gr - 1520-2141zdl cnl cal gr - 2559-3644dll mll sl - 2559-2758diplog gr - 1520-2140diplog gr - 2559-3332diplog gr - 3329-3661fmt hp gr - 2579-2800fmt hp gr - 2650-2650cbl vdl gr - 394-1520acbl gr - 1563-2559acbl gr - 2505-3319velocity - 930-3640

Well 6608/10-3:

mwd - 472-2920difl acl gr - 863-1587cdl cnl gr - 1575-2914difl dac gr - 1574-2555dipl mac sl - 2430-2915dll mll gr - 2539-2800fmt hp gr - 2498-2862fmt hp gr - 2650-2650cbl vdl gr - 646-2871diplog gr - 1900-2555hrdip gr - 2563-2905swc - 894-2901vsp - 1240-2900

22

Well 6608/10-4:

mwd - 477-2558difl mac sl - 2175-2795zdl cnl gr - 2465-2794dll mll gr - 2465-2650hrdip gr - 1396-2555fmt gr - 2485-2662cbl vdl gr - 800-2746swc gr - 1430-2774vsp - 500-2750

[NPD, 2008]

The layers Ile 2, Ile 1, Tilje 4, Tilje 3 and Tilje 2 are eroded in well 6608/10-4. This can be

seen for instance from logs as demonstrated in gure 3.8, which illustrates correlation of wells

in the Norne Area.

Figure 3.8: Correlation of Wells in the Norne Area [Statoil, 1995]

Logs from the wells B-1 H, D-1 H and E-1 H are included on a CD accompanied with this

thesis. These logs are attached in relation with the 4D seismic data in section 3.4.3. Few of the

wells on the Norne Field have been logged with sonic logs, i.e. dt or dts. Only D-1 H has sonic

data of the three wells B-1 H, D-1 H and E-1 H. The log for D-1 H is edited and corrected for

mud ltrate invasion, and are suitable for modelling. The logs used for this well is gr, phie,

phit, rhob_v, vp_v and vs_v. For the two other wells there exist data for dt_synt, gr,

phif, and rhob. dt_synt is a synthetic dt log made with linear relation and are not logged

in the bore hole.

23

Core data

Core data has also been used as a basis for determination of the petrophysical properties of

the Norne Field. From well 6608/10-2 there has been cut six cores, eleven cores are cut from

well 6608/10-3 and 7 from well 6608/10-4. All this data has been depth shifted to match the

zdl-cn-gr. Photos of cores from the dierent formation are included in gures 3.9-3.14.

Use of core measurements is introducing some uncertainties which should be mentioned.

When drilling the cores, the transportation of the cores and the treatment of the core material

are vital. When performing measurements on the cores, there can be systematic errors connected

to equipment and methods. The plug may not be of general reservoir quality and will because

of that give incorrect results.

Figure 3.9: Cores from well 6608/10-2, inter-val 2600-2605 in the Garn Formation [NPD,2008]. Sandstones deposited near shore withsome tidal inuence

Figure 3.10: Cores from well 6608/10-2, interval 2611-2616 in the Not Forma-tion [NPD, 2008]. Grey to black claystonewith siltstone lamina, deposited in quiet ma-rine environment

24

Figure 3.11: Cores from well 6608/10-2, in-terval 2627-2632 in the Ile Formation [NPD,2008]. Sandstones deposited in shoreface en-vironment

Figure 3.12: Cores from well 6608/10-2, interval 2661-2665 in the Ror Forma-tion [NPD, 2008]. Very ne grained/shalysand, deposited in lower shoreface environ-ment with low sediment supply

25

Figure 3.13: Cores from well 6608/10-2, interval 2724-2729 in the Tilje Forma-tion [NPD, 2008]. Sand, with some clay andconglomerates, deposited in a marginal ma-rine, tidally aected environment

Figure 3.14: Cores from well 6608/10-2, interval 2674-2679 in the Tofte Forma-tion [NPD, 2008]. Channel sandstones

Test data

Well 6608/10-2: Test data from four drillstem tests (DST) has been reported for this well.

One of the tests showed evidence of Joule-Thomson eect as the temperature decreased when

the gas owed from the reservoir to the wellbore [Schlumberger Oileld Glossary]. As this test

was performed close to the gas-oil contact it is likely that the eect is a result of coning. All the

other DST's produced uids in accordance with the petrophysical evaluation made here [Statoil,

1994a].

DST 1 tested the interval 2715-2720 m in the lower Tofte Formation. Max bottom hole

temperature here was 100 C. 310 Sm3 water/day was produced through a 2" choke.

DST 2 tested the interval 2673-2695 m in the upper Tofte Formation. The production rate

measured was 1165 Sm3/d oil and 108667 Sm3/d gas through a 1.5" choke. Gas-Oil Ratio

was 93 Sm3/Sm3, oil density was 0.856 g/cm3, the gas gravity was 0.65 and the gas contained

1.8% CO2 and 4 ppm H2S. Max bottom hole temperature was 98.4 C.DST 3 tested the interval 2605-2610 m in the lower Garn Formation. The test produced 33 Sm3

26

condensate and 582600 Sm3 gas/day through a 19.05 mm choke. Measured GOR was 17654 Sm3/Sm3,

and max bottom hole temperature was 91.4 C.DST 3B tested the interval 2590 2603 m in the Garn Formation. Measured rates recorded

were 100 Sm3/d condensate and 9645000 Sm3 gas/day through a 38.1 mm choke. GOR were

recored to 9450 Sm3/Sm3. The condensate density was 0.783 g/cm3, the gas gravity was 0.645

and the gas contained 1.1% CO2 and 0.5 ppm H2S. Maximum bottom hole temperature measured

was 95.5 C. [NPD, 2008]

Well 6608/10-3: One drill stem test was carried out in this well. The test was performed

in the Ile Formation, in the perforated interval 2617-2648 m. The production was measured

to 1250 Sm3/d oil with density of 860 kg/m3 at standard conditions. 102500 Sm3/d gas was

produced with relative density of 0.65. The choke was of the size 60/64". [NPD, 2008]

Well 6608/10-4: In this well, three drill stem tests were performed.

DST 1 tested the Tofte Formation in the interval 2635-2640 m. No formation uid was

produced to the surface. Minifrac tests were performed at the end of this test, and the fracture

closing pressure was evaluated to 405 bar bar.DST 2 tested the Garn Formation in the interval 2566.2-2582.2 m. This test produced a

maximum of 900 Sm3/d oil with a density of 858 kg/m3 at standard conditions. 75000 Sm3/dgas with a relative density of 0.648 was measured. The choke was of size 80/64" (31.75 mm).

Minifrac tests were performed at the end of this test, and evaluated the fracture closing pressure

to be 410 bar.DST 3A and DST 3B tested the Melke Formation. DST 3A in the intervals 2484.5-2599 m

and 2505-2514 m, and DST 3B in 2524-2531 m. No formation uid was produced to the surface.

This test proved that the Melke Formation was tight with oil in place. [NPD, 2008]

FMT-data

The nal data type used for the petrophysical evaluation was the Formation Multi Tester (FMT)

log. This tool enables conrmation of a water bearing reservoir using pore pressure gradient.

It also allows sampling of the formation water. [NPD, 1994] Evaluation of the FMT-data gives

a base case oil-water contact at about 2688.5 m TVD/MSL for both well 6608/10-2 and well

6608/10-3. Well 6608/10-4 had a oil-water contact at 2574.5 m. Dierent gas-oil contacts were

observed in wells 6608/10-2 and 6608/10-3, while well 6608/10-4 did not contain any gas [Statoil,

1995]. Well 6608/10-2 had a gas-oil contact at 2580 m TVD/MSL and in well 6608/10-3 the gas-

oil contact was at 2575 m TVD/MSL. The FMT data also suggests that there is a small pressure

barrier in the northern segment (Segment E), caused by the presence of the Not Formation.

Figure 3.15 illustrates this feature.

However, it is shown by uid analysis that it is the same composition of oil above and below

this barrier. The calculated gradients are given in table 3.1. Reference depth used in the oil

zone was 2639 m and the formation pressure was 273.2 bar. [Statoil, 1994a]

27

Figure 3.15: Fluid model, from [Statoil, 1994a]

Table 3.1: Calculated gradients, with some uncertainty [Statoil, 1994a]Fluid Gradient

[ g/cm3]

Gas 0.19Oil 0.72

Water 1.02

3.2.2 Interpretation parameters

a, m and n The lithology factor, a, the cementation factor, m, and the saturation exponent,

n, have been estimated based on core analysis from wells 6608/10-2 and 6608/10-3. For the rst

two parameters the values were found from plug data with overburden measurements. Estimated

values are; a = 1.0 and m = 1.84. The saturation exponents are found for three dierent zone

groups, from Resistivity Index (RI) measurements. The groups and the n values are given in

table 3.2. 6 plugs from group 1, 9 plugs from group 2 and 5 plugs from group 3 are used as a

basis for the RI-measurements. [Statoil, 1994a]

Grain density

The average grain density for the entire reservoir, based on all core data from both wells are

ρma = 2.67 g/cm3. Zones of dierent grain densities are Tofte 3 and 2, 2.65 g/cm3 and Tofte

1, 2.71 g/cm3. [Statoil, 1994a]

Overburden corrections

The overburden pressure was calculated to correct results accordingly. To calculate the overbur-

den pressure, the density logs in wells 6608/10-2 and 6608/10-3 were integrated. A minimum

horizontal stress at depth 2673 m of 389 bar was indicated in a minifrac test [Statoil, 1992]. At

that depth, the pore pressure was 273 bar, hence the minimum horizontal stress is 116 bar and

28

Table 3.2: n-values for the zone groups [Statoil, 1994a]Group n- Formationnumber value names

Garn 2+11 1.84 Not

Ile 32 2.02 Ror

TofteGarn 3

3 2.20 Ile 2+1Tilje

the dierence between the horizontal and the vertical stress is 123.5 bar. Due to rock mechanicsthe conning pressure will be 123.5/3 + 116 bar. In [Statoil, 1994a] the equations for porosity

and permeability are given as:

Φres = 0.967Φatmos

Kres = 0.856Katmos1.004

Water resistivity

The resistivity of the formation water is found from the water sample from DST 1 in well

6608/10-2. It is temperature corrected using Arps formula. The resistivity is:

Rw = 0.054 Ω at 98.3 C

[Statoil, 1992]

Formation temperature

Both the formation temperature and the temperature gradient were determined from the DST.

They are:

T = 9.83 C at depth 2639 m TVD/MSL

∆T = 3.5 C/100 m

These values were in good agreement with the estimation carried out in [Statoil, 1992], where

the temperature was estimated to be 121.8 C at 3322 m MD/RKB. [Statoil, 1994a]

29

3.2.3 Evaluation

Porosity

Generation of total porosity is executed by use of the equation

φ = a+ b ∗ ρb

ρb is the bulk density, while a and b are constants. Crossplots of overburden corrected core

porosity vs. density log are used to nd these constants. The constants are found for the dierent

zones, which are grouped together for improving correlations. Some uncertainties are related to

the determination of the constants a and b from crossplots. [Statoil, 1994a]

Fluid contacts

As mentioned in section 3.2.1 there was a common oil-water contact at 2688.5 m TVD/MSL

for wells 6608/10-2 and 6608/10-3, while well 6608/10-4 had a oil-water contact at 2574.5 mand did not contain any gas. There were two dierent gas-oil contacts for wells 6608/10-2 and

6608/10-3; 2580 m and 2575 m respectively. The gas systems seem to be common over the entire

eld. That is also the case for the oil systems, except the oil above the Not Formation in well

6608/10-3. These contacts were also determined by FMT and DST data.

Formation resistivity

Calculations of the true formation resistivity in both the hydrocarbon zones and the water

zones were performed. The logs used for the calculations were environmentally corrected. In

the hydrocarbon zones the dll-mll log was used along with [Western Atlas Logging Services,

1985], while the deep induction logs were used for the water zones.

Water saturations

Two dierent models; Archie and Capillary pressure, were used to determine the water satura-

tion. These models are described in the following.

Archie The Archie equation is given below, and was used to evaluate Sw assuming clean sand.

The parameters needed for the equation are given in section 3.2.2.

Sw =(Rwa

Rtφm

)1/n

The average values of the water saturation, are given in tables 3.4, 3.5, 3.6 and 3.7.

It was assumed that Archie's equation could be used to estimate water saturation in the two

wells, and the constant a was treated without uncertainty. [Statoil, 1994a]

30

Capillary pressure The capillary pressure model is based on core data and was compared to

the log model, Archie. Estimations of water saturation were only made for the oil zones.

To normalize the capillary pressure data a J-function was used. The only assumption needed

for this method was: from a set of capillary pressure measurements for a reservoir, a single curve

of J vs. Sw can be drawn and used to determine the water saturation for a eld. The Leverett-

function was used.

J(Sw) = Pc

√KΦ

σ cos θ

where:

Pc = Capillary pressure (bar)K = Klinkenberg corrected core permeability (mD)

Φ = Helium porosity (fraction)

σ = Interfacial tension (dynes/cm)

θ = Contact angle

As input for the permeability the Klinkenberg-corrected gas permeability was used. Since

the interfacial tension and the contact angle were not measured in connection with the capillary

pressure test, these values are much more uncertain. Values from the literature were therefore

used.

For laboratory conditions, capillary pressure measurements from mercury injection were

used. Interfacial tension and contact angle are showed below;

σcosθ = 368.

Each of the plugs has a calculated J. The function used is:

Sw = (51.4 ∗ Jlab)−0.4085

Laboratory data were converted to reservoir conditions.

The interfacial tension and contact angle at reservoir conditions were found from the litera-

ture. Some uncertainties were connected to these. For oil-water at reservoir conditions we have

the following relation;

σcosθ = 25.

The J-function was found from the Leverett-function:

Jres = 0.0012949 ∗H√K

Φ

Corrections for overburden were applied for permeability and porosity. The following relation

was assumed:

Jres = Jlab

The water saturation is connected to height above free water, with overburden corrected

permeability and porosity like this:

31

Sw = (0.066559 ∗H√K

Φ)−0.4085

The data from well 6608/10-3 was compared to the data from well 6608/10-2 and proved

good similarity. Hence, the developed function for water saturation from well 6608/10-2 could

be used in the following. [Statoil, 1994a]

Water saturation modelling The modelling of the water saturation was performed by use

of a J-function derived water saturation in the oil formation. Log derived water saturation based

on Archies formula was employed in the gas zones. The equations for the oil zone and the gas

zone are given below.

SWJ =

(h

a2

√K

φ

) 1b2

(3.1)

Sw =((Rwa) /Rmtφ

)1/n (3.2)

[Statoil, 2001c]

a, m, n, a2 and b2 are constants. The 2000 reservoir model handled all segments equally.

The same water saturation model, average zone permeability and average zone depth corrected

porosity were used.

The water saturation within the G-segment was modelled as function of height over the oil-

water contact, for Garn 2, Garn 1 and Ror, according to the J-function described above. The

remaining reservoir zones in this segment were modelled as constant average values from well

6608/10-3. [Statoil, 1995]

Permeability

Log estimations Log estimated permeability was established by use of the relationship be-

tween overburden corrected core porosity and overburden corrected core permeability. Log per-

meabilities in the horizontal and vertical directions were found to be unrelated. Hence, vertical

permeability was dened in the same way as the horizontal permeability. It is found that both

horizontal and vertical permeability were overestimated in Tilje 3, Tilje 4 and Tofte 3 zones.

Core permeability was less than 2000 mD in these zones, so the log derived permeability was cut

on a maximum value of 2000 mD here. In the other zones, the maximum value was 10000 mD.

Data from well 6608/10-4 were used for determining the permeability in the G-segment. [Sta-

toil, 1995]

Log/core permeabilities compared to test permeabilities A comparison of the log and

core permeabilities and the test permeabilities showed a generally good similarity between log

and test data.

The k*h product from tests and logs were compared. This was done to verify the quality

of the log derived evaluated permeability. The overall impression was that there were a good

32

agreement between k*h products from tests and logs.

The arithmetic means of the log permeabilities were closest to the test permeabilities. Use of

arithmetic mean in reservoir simulations is recommended. To assure accuracy in the whole eld,

geometric means may be used in more heterogeneous sections of the reservoir. [Statoil, 1994a]

Conclusions Permeability Some intervals of the formation have overestimated or under-

estimated log permeability when comparing with core permeability. Beyond that, there is a

good accordance between core and log derived permeabilities. Table 3.3 gives recommended

permeabilities. k*h-products resulting from tests and logs have good agreement. The test gives

a permeability which lies between arithmetic and geometric mean values determined from logs.

However, the permeabilities are closest to the arithmetic mean in all cases. As consequence of

that, it has been recommended to use arithmetic means in reservoir simulations. [Statoil, 1994a]

Table 3.3: Recommended eld values of permeability [Statoil, 1994a]Zone KLHarith [mD] KLHgeo [mD] KLVharm [mD]

Garn 3 2500 1300 200Garn 2 400 130 17Garn 1 20 12 5Not - - -Ile 3 100 65 13Ile 2 1000 800 75Ile 1 800 450 150Ø.Ror 150 100 20Tofte 3a 1065 850 680Tofte 3b 200 175 120Tofte 2 40 25 7.5Tofte 1 1200 350 19.5Tilje 4 450 70 2.0Tilje 3 875 250 12Tilje 2 400 50 5.8Tilje 1 2000 650 30

Net sand

Cut-o on porosity and manual correction is used to dene net sand. Net sand denitions for

both oil and gas are used for Norne. To dene the cut-o values, the porosity corresponding to a

Klinkenberg and overburden corrected permeability of 0.1 mD for gas-lled formation and 1 mD

for oil-lled formation was employed. Porosity cut-o values were generated based on cross plots

of overburden corrected core porosity vs. overburden corrected and Klinkenberg corrected core

permeability. In addition, photos of cores, see gures 3.9 - 3.14, were used to decide the cut-o

values.

Plots of Garn, Not, Ile 3, Tofte 1 and Tilje Formations show low permeability values. It

denotes that cut-o values can be determined. Figure 3.16 shows an example of how the cross-

33

plot of Garn, Not, Ile 3 is used to nd the cut-o values. The remaining zones have high

permeability values, and cut-o values are chosen in agreement with low permeability zones.

Porosity cut-o values used are shown in the following:

Zones Gas Oil/waterGarn, Not, Ile 3 12% 16.5%Tofte 3-2Tofte 1, Tilje 7.5% 12.5%Ile 2-1Ror

Manually correction from Net Sand curves was performed for the Not Formation which

mainly consists of organic shale. In the Garn Formation in the interval from 2600 m down to

the Not Formation there is presence of shale. Chosen cut-o values were 0.2 mD for gas-sand

and 2 mD for oil-sand for this interval. Manual editing for eliminating shaly intervals in the Tilje

Formation was performed while the cemented layers in the dierent formations were excluded

by the porosity cut-o values.

Uncertainties in the cut-o denitions and the manual editing can occur. [Statoil, 1994a]

Also for the G-segment each reservoir zone has separate modelled values. These are found

from the evaluation of well 6608/10-4. Table 3.8 shows the parameters for the G-segment. [Sta-

toil, 1995]

Figure 3.16: Cross plot of overburden corrected core porosity vs. overburden corrected andKlinkenberg corrected core permeability [Statoil, 1994a]

34

Porosity-permeability relations

To estimate the permeability based on the porosity, the linear log relation showed below was

used.

K = 10(a1+b1φ)

[Statoil, 2001c]

3.2.4 Results

The petrophysical evaluation gave important information for the development of the eld, and

the results are demonstrated in gures and tables below. Tables 3.4, 3.5, 3.6 and 3.7 includes

cut-o values for wells 6608/10-2 and 6608/10-3 for both oil and gas, while table 3.8 shows values

for the G-segment. Figures 3.17, 3.18 and 3.19 show logs from wells 6608/10-2, 6608/10-3 and

6608/10-4, respectively.

Table 3.4: Cut-o values, Oil Case, Well 6608/10-2 [Statoil, 1994a]Zone Fluid Thickness ΦF Sw N/G

TVD [m] [fraction] [fraction] [fraction]

Garn 3 Gas 11.0 0.302 0.121 0.982Garn 2 Gas 10.3 0.258 0.145 0.844Garn 1 Total 12.2 0.215 0.269 0.485

Gas 5.0 0.205 0.249 0.742Oil 7.2 0.231 0.298 0.305

Not - 7.5 - - 0Ile 3 Oil 21.6 0.247 0.183 0.894Ile 2 Oil 16.0 0.287 0.123 0.981Ile 1 Oil 2.9 0.259 0.185 0.828Ø.Ror Oil 8.6 0.254 0.221 0.907Tofte 3 Oil 29.1 0.280 0.187 1.00Tofte 2 Oil 6.6 0.228 0.430 0.985Tofte 1 Total 15.5 0.254 0.471 0.851

Gas 9.0 0.256 0.339 1.00Oil 6.5 0.248 0.767 0.644

Tilje 4 Water 11.3 0.214 0.845 0.796Tilje 3 Water 22.5 0.250 0.984 0.929Tilje 2 Water 37.7 0.187 0.922 0.587Tilje 1 Water 28.2 0.277 0.987 0.847

35

Table 3.5: Cut-o values, Gas Case, Well 6608/10-2 [Statoil, 1994a]Zone Fluid Thickness ΦF Sw N/G



Gas 5.0 0.192 0.270 0.980Oil 7.2 0.203 0.331 0.791

Not - 7.5 - - 0Ile 3 Oil 21.6 0.240 0.187 0.949Ile 2 Oil 16.0 0.285 0.124 1.0Ile 1 Oil 2.9 0.233 0.206 1.0Ø.Ror Oil 8.6 0.251 0.222 0.930Tofte 3 Oil 29.1 0.280 0.187 1.00Tofte 2 Oil 6.6 0.227 0.431 1.00Tofte 1 Total 15.5 0.239 0.504 0.961

Gas 9.0 0.256 0.339 1.00Oil 6.5 0.212 0.813 0.907

Tilje 4 Water 11.3 0.206 0.867 0.867Tilje 3 Water 22.5 0.245 0.993 0.960Tilje 2 Water 37.7 0.162 0.971 0.889Tilje 1 Water 28.2 0.265 0.997 0.911

Table 3.6: Cut-o values, Oil Case, Well 6608/10-3 [Statoil, 1994a]Zone Fluid Thickness ΦF Sw N/G



Gas 7.6 0.252 0.204 0.960Oil 9.0 0.241 0.259 0.486

Not - 7.3 - - 0Ile 3 Oil 16.9 0.236 0.225 0.826Ile 2 Oil 11.0 0.279 0.149 1.0Ile 1 Oil 3.5 0.269 0.173 0.914Ø.Ror Oil 8.4 0.234 0.258 0.819Tofte 3 Oil 28.5 0.276 0.170 1.00Tofte 2 Oil 6.1 0.231 0.359 1.00Tofte 1 Total 14.9 0.262 0.239 0.898Tilje 4 Water 6.9 0.235 0.568 0.716Tilje 3 Water 18.0 0.266 0.937 0.897Tilje 2 Water 34.4 0.223 0.958 0.672Tilje 1 Water 25.6 0.272 0.987 0.830

36

Table 3.7: Cut-o values, Gas Case, Well 6608/10-3 [Statoil, 1994a]Zone Fluid Thickness ΦF Sw N/G



Gas 7.6 0.252 0.204 0.960Oil 9.0 0.226 0.301 0.774

Not - 7.3 - - 0Ile 3 Oil 16.9 0.229 0.231 0.943Ile 2 Oil 11.0 0.279 0.149 1.0Ile 1 Oil 3.5 0.254 0.183 1.0Ø.Ror Oil 8.4 0.225 0.269 0.946Tofte 3 Oil 28.5 0.276 0.170 1.00Tofte 2 Oil 6.1 0.231 0.359 1.00Tofte 1 Total 14.9 0.250 0.248 0.990Tilje 4 Water 6.9 0.215 0.605 0.934Tilje 3 Water 18.0 0.258 0.957 0.949Tilje 2 Water 34.4 0.203 1.0 0.858Tilje 1 Water 25.6 0.260 1.0 0.901

Table 3.8: Petrophysical Parameters G-segment [Statoil, 1995]. * Modelled as function of heightover oil-water contact (OWC)

Zone ΦF Sw N/G[fraction] [fraction] [fraction]

Garn 3 0.33 0.11 1.00Garn 2 0.27 * 0.99Garn 1 0.23 * 0.46Not - - 0Ile 3 0.25 * 0.64Ile 2 0.28 0.15 1.00Ile 1 0.27 0.17 0.91U.Ror 0.26 0.26 0.90Tofte 3 0.28 0.17 1.00Tofte 2 0.24 0.36 1.00Tofte 1 0.16 0.25 0.41Tilje 4 0.24 0.5 0.72Tilje 3 0.27 0.5 0.90Tilje 2 0.22 0.5 0.67Tilje 1 0.25 0.5 0.95

37

Figure 3.17: CPI-plot Well 6608/10-2 [Statoil, 1994a]

38

Figure 3.18: Log from NPD Well 6608/10-3 [NPD, 2008]

39

Figure 3.19: Log from NPD Well 6608/10-4 [NPD, 2008]

40

3.2.5 Uncertainties

Uncertainties in the study of petrophysics are associated to the used methods' assumptions

and simplications, input data and core measurements. Assumptions connected to the use of

Archie's equation, are mentioned in the section 3.2.3. Input data may have both random and

systematically errors. Measurements from cores have uncertainties connected to the handling

of cores from drilling and transport to measurement performance. The uncertainties introduced

by use of core measurements are discussed in section 3.2.1

3.2.6 Conclusions

The petrophysical evaluation of the eld has established parameters for; porosity, net to gross,

water saturations and permeability. These are used in the geological model and in the reservoir

simulation.

A continuous gas system for the eld is found in the upper part of the Garn Formation. Oil

is present below and down to the lower part of the Tofte Formation and the upper part of the

Tilje Formation. The oil system is divided in two parts; one in the Garn Formation in segment

G which is isolated by the Not Formation, and a continuous oil system for the rest of the main

eld. The initial GOC and OWC in the dierent formations and segments are listed in Table 3.9

and illustrated in gure 3.20.

Table 3.9: Initial GOC and OWC on the Norne Field [Statoil, 1994a]Formation C-segment D-segment E-segment G-segment

OWC GOC OWC GOC OWC GOC OWC GOCGarn 2692 2582 2692 2582 2618 2582 2585 No gas capIle 2693 2585 2693 2585 2693 2685 Water lled Water lled

Tofte 2693 2585 2693 2585 2693 2585 Water lled Water lledTilje 2693 2585 2693 2585 2693 2585 Water lled Water lled

Both well 6608/10-2 and well 6608/10-3 give good petrophysical properties. The average

porosity is in the range of 20-30%, permeability 20-2500mD, net to gross values in the range of

0.7-1 and water saturations 12-43% for hydrocarbon zones. Small variations in reservoir quality

between the three wells occur. Best reservoir quality is found in the upper part of Garn, Ile, Ror

and the upper part of Tofte. These are the most homogeneous parts of the reservoir. The Not

Formation consists of organic shale and net to gross here is zero. Sand intervals of good quality

are also found in Tilje and lower parts of Garn. However, these parts are more laminated and

cemented.

High permeability values are found in sand with good porosity. More shaly and cemented

sand has lower permeability. It is from this study generated a recommendation of what kind

of permeability that should be used for reservoir simulation. In accordance with permeabilities

from the DST tests, it is recommended to use the arithmetic means of permeabilities.

41

Figure 3.20: NE-SW running structural cross section through the Norne Field with initial andindications of present uid contacts, and current drainage strategy [Statoil, 2006a]

42

3.3 Wells

The Norne Field is being developed with a oating production and storage vessel. The vessel

is connected to six subsea wellhead templates named B, C, D, E and K, as seen in gure 2.2.

Template K was placed on the sea bottom in 2005, south of B, C and D templates. The K

template has 4 slots available; 3 for production and 1 for injction or production. The Norne

Field was discovered with well 6608/10-2 in 1991. Well 6608/10-3 conrmed the result of hydro-

carbons in the discovery well, while well 6608/10-4 encountered oil in the North-East segment.

Development drilling started with well 6608/10-D-1 H in August 1996. [Statoil, 2006a]

3.3.1 Exploration wellbores

To test the hydrocarbon potential in the sandstones and appraise oil accumulation in dierent

formations, 4 exploration wells were drilled. Several intervals were perforated and tested.

An overview of the exploration wells is presented in table 3.10 below.

43

Table3.10:Exploration

wellbores

[NPD,2008]

Nam

eUTM

En try

Date

Com

pletion

Purp ose

Status

Contents

TrueVertical

Hydrocarbon

coordinates

Date

Depth

[m]

form

ation(s)

6608/10-2

7321933.62N,457994.68E

28.10.1991

29.01.1992

WILDCAT

Plugged

and

OIL/G

AS

3677

FangstandBåt

Abandoned

6608/10-3

7324321.37N,458426.47E

07.01.1993

11.03.1993

APPRAISAL

Susp.

OIL/G

AS

2920

F angstandBåt

reenteredlater

6608/10-3R

7324321.37N,458426.47E

08.08.1995

17.08.1995

APPRAISAL

Plugged

and

OIL/G

AS

2920

FangstandBåt

Abandoned

6608/10-4

7324847.23N,462006.74E

15.12.1993

06.03.1994

WILDCAT

Plugged

and

OIL/G

AS

2800

Melke

andGarn

Abandoned

44

3.3.2 Description of exploration wells

Well 6608/10-2

Well 6608/10-2 was the well that rst discovered oil and gas on the Norne Field. The drilling

started the 28th of October 1991. The objectives were to test the hydrocarbon potential of

the Fangst Group of Middle Jurassic age, and to see if it was a sandy equivalent to the Rogne

Formation in the Viking Group. The plan was to drill a near to vertical well into rocks of Triassic

age at a total depth of 3225 m.

There were some problems with tight hole during drilling, which lead to extension in required

time. The extension was accepted because hydrocarbons had been proved and the goal of drilling

into the rocks of Triassic age was important. When drilling, it turned out that the Triassic

Formation were located deeper than expected, and the total depth of the hole ended at 3678 m.

Oil and gas were encountered in both the Båt and Fangst Groups from Lower and Middle

Jurassic. The uid contacts were found from logs and test, and revealed a gas-oil contact

at 2605 m and a oil-water contact at 2713.5 m. Cores recovered from well 6608/10-2 have a

total length of 141.5 m from the Båt and Fangst Groups. Two FMT samples have also been

collected; one gas sample and one oil sample.

The well was permanently plugged and abandoned on the 29th of January 1992. [NPD, 2008]

Well 6608/10-3

The second exploration well drilled on the Norne eld was 6608/10-3. This well was spudded

7th of January 1993. The purpose of was to evaluate the accumulation of oil in the Båt and

Fangst Groups in the Northern fault block on the Norne Field.

The well was drilled to a total depth of 2921 m, into Lower Jurassic formation. Oil and gas

were encountered in both Båt and Fangst Groups. A total of 11 cores were cut from Lower

Melke to Tilje Formations. In addition, four FMT samples were taken, containing mudltrate,

oil and gas.

The well was suspended as an oil and gas appraisal well the 11th of March 1993. A re-entry

of the well was performed the 8th of August 1995, and the well was permanently plugged and

abandoned as an appraisal well the 17th of August 1995. [NPD, 2008]

Well 6608/10-4

Well 6608/10-4 was the rst exploration well to be drilled on the North-East area. Its purpose

was to prove the presence of oil in the Middle Jurassic sandstones in the G-segment.

Drilling started on the 15th of December 1993, and the well was drilled to a total depth

of 2800 m. It reached rocks of the Lower Jurassic Åre Formation. As anticipated, oil was

encountered in the Melke and Garn Formations of Middle Jurassic age. A total of 8 cores were

cut from the Cretaceous Nise Formation to the Åre Formation. FMT samples were extracted

from the Melke, Garn and Ile Formations with content varying from only mudltrate to also

containing traces of oil and gas.

45

The 7th of March, well 6608/10-4 was plugged and abandoned as an oil and gas discov-

ery. [NPD, 2008]

3.3.3 Development wellbores

The Norne Field has 4 templates for production and 2 templates for injection. Each template

has 4 slots available. Oil was produced from all 12 slots in January 2006, and all 8 injection wells

were used for water injection. This was before the wells on the K-template were completed. The

eld is developed only with horizontal producers today. Some of the producers were rst drilled

vertical to some deviated, to accelerate the build-up of well potential until plateau production was

reached. These wells have been sidetracked to horizontal production wells. [Statoil, 2001c] New

well technology has been implemented on Norne to increase recovery, for instance multilateral

wells.

Both gas and water have been injected into the reservoir, but the gas injection was stopped

in 2005 [Statoil, 2001c]. However, injection of gas from the C-wells started again in 2006 for an

extended period to avoid pressure depletion in the gas cap [NPD, 2008].

The decision of wellbore locations is based on these principles:

Water injectors located at the anks of the reservoir

Gas injectors located at the structural heights of the reservoir

Oil producers located between gas and water injectors for delaying gas and water break-

through

Oil producers located at some distance from major faults to avoid gas inow

The principles presented above are used for all well locations as an initial location. The locations

are thereafter optimized with regard to gas and water breakthrough times by use of reservoir

simulation studies.

Total number of active wells in December 2006 was 17, with 11 oil producers, 3 water injectors

and 3 gas injectors. The wells are completed in dierent formations depending on the drainage

strategy. A summary of each well is presented in section 3.3.4. [Statoil, 1994b]

Drilling history

10 wells were predrilled to obtain plateau production from the production start-up. 7 of the 10

wells were oil producers with good productivity and late breakthrough of gas and water. 3 wells

were predrilled for injection; 1 for injection of produced gas, and two for pressure maintenance

water injection. The water injectors were perforated below oil-water contact, and gas injectors

in the top Garn Formation. [Statoil, 1994b]

The development wells are presented in table 3.11 below. A more detailed description of all

the development wells are given in section 3.3.4. Appendix B.1 contain plots of oil production

rate, water cut and gas-oil ratio for all production wells and injection rates for the injection

wells.

46

Table3.11:Developmentwellbores

[NPD,2008]

Nam

eUTM

En try

Date

Com

pletion

Purp ose

Status

Contents

Total

coordinates

Date

Depth

[m]

6608/10-B-1

H7322128.37N,457125.62E

26.01.1999

05.04.1999

PRODUCTIO

NPLUGGED

OIL

4300

6608/10-B-1

AH

7322128.37N,457125.62E

06.11.2005

03.12.2005

OBSE

RVATIO

NPLUGGED

NA

3478

6608/10-B-1

BH

7322128.37N,457125.62E

04.12.2005

09.01.2006

PRODUCTIO

NPRODUCING

OIL

2976

6608/10-B-2

H7322122.85N,457121.88E

13.12.1996

09.12.1997

PRODUCTIO

NPRODUCING

OIL

3862

6608/10-B-3

H7322135.86N,457122.07E

21.05.1999

05.07.1999

PRODUCTIO

NPRODUCING

OIL

4150

6608/10-B-4

H7322136.28N,457114.14E

12.01.1998

06.02.1998

PRODUCTIO

NPLUGGED

NA

2555

6608/10-B-4

AH

7322136.28N,457114.14E

13.06.2001

12.07.2001

OBSE

RVATIO

NPLUGGED

NA

3900

6608/10-B-4

BH

7322136.28N,457114.14E

13.07.2001

07.08.2001

PRODUCTIO

NPLUGGED

OIL

4346

6608/10-B-4

CH

7322136.28N,457114.14E

03.06.2004

19.06.2004

OBSE

RVATIO

NPLUGGED

NA

3630

6608/10-B-4

DH

7322136.28N,457114.14E

20.06.2004

10.07.2004

PRODUCTIO

NPRODUCING

OIL

2870

6608/10-C-1

H7322024.28N,457190.08E

12.02.1998

20.07.1998

INJE

CTIO

NINJE

CTING

WATER

3255

6608/10-C-2

H7322026.87N,457182.56E

01.10.1998

27.11.1998

INJE

CTIO

NINJE

CTING

WATER

4421

6608/10-C-3

H7322029.45N,457175.54E

06.04.1999

20.05.1999

INJE

CTIO

NINJE

CTING

WATER

3800

6608/10-C-4

H7322034.03N,457180.02E

18.11.1996

18.08.1997

INJE

CTIO

NPLUGGED

GAS

2900

6608/10-C-4

AH

7322034.03N,457180.02E

15.11.2003

13.01.2004

INJE

CTIO

NINJE

CTING

WATER

3638

6608/10-D-1

H7321942.88N,457269.01E

28.09.1996

18.11.1996

PRODUCTIO

NPLUGGED

NA

3500

6608/10-D-1

AH

7321942.88N,457269.01E

28.05.2002

25.06.2002

OBSE

RVATIO

NPLUGGED

NA

2897

6608/10-D-1

BH

7321942.88N,457269.01E

26.06.2002

05.09.2002

PRODUCTIO

NPLUGGED

NA

4852

6608/10-D-1

CH

7321942.88N,457269.01E

30.09.2003

07.11.2003

PRODUCTIO

NPRODUCING

OIL

4575

6608/10-D-2

H7321938.31N,457264.41E

09.01.1997

05.01.1998

PRODUCTIO

NPRODUCING

OIL

4174

6608/10-D-3

H7321948.37N,457254.48E

05.07.2000

04.08.2000

PRODUCTIO

NPLUGGED

NA

4198

6608/10-D-3

AH

7321948.37N,457254.48E

05.08.2000

30.08.2000

PRODUCTIO

NPLUGGED

OIL

5100

Continued

onNextPage...

47

Table3.11

Continued

Nam

eUTM

Entry

Date

Com

pletion

Purpose

Status

Contents

Total

coordinates

Date

Depth

[m]

6608/10-D-3BY2H

7321948.37N,457254.48E

12.08.2000

25.09.2005

PRODUCTIO

NSU

SP.ATTD

OIL

5400

6608/10-D-3BY1H

7321948.37N,457254.48E

06.07.2005

07.10.2005

PRODUCTIO

NSU

SP.ATTD

OIL

5400

6608/10-D-4

H7321952.94N,457259.08E

07.01.1998

18.06.1998

PRODUCTIO

NPLUGGED

NA

3137

6608/10-D-4

AH

7321952.94N,457259.08E

11.01.2003

09.06.2003

PRODUCTIO

NPRODUCING

OIL

5829

6608/10-E-1

H7325447.22N,459204.35E

28.05.1999

19.06.1999

PRODUCTIO

NPRODUCING

OIL

4350

6608/10-E-2

H7325441.40N,459199.73E

16.10.1999

21.11.1999

PRODUCTIO

NPLUGGED

OIL

4075

6608/10-E-2

AH

7325441.40N,459199.73E

28.07.2005

15.08.2005

PRODUCTIO

NPLUGGED

OIL

3775

6608/10-E-2

BH

7325441.40N,459199.73E

23.11.2007

OBSE

RVATIO

NPLUGGED

4204

6608/10-E-2

CH

PRODUCTIO

N

6608/10-E-3

H732545.14N

,459189.80E

29.07.1998

23.09.1998

PRODUCTIO

NPLUGGED

OIL

3110

6608/10-E-3

AH

732545.14N

,459189.80E

02.10.2000

12.12.2000

PRODUCTIO

NPLUGGED

OIL

4849

6608/10-E-3

BH

732545.14N

,459189.80E

09.03.2005

03.04.2005

OBSE

RVATIO

NPLUGGED

NA

3259

6608/10-E-3

CH

732545.14N

,459189.80E

04.04.2005

07.05.2005

PRODUCTIO

NPRODUCING

OIL

4018

6608/10-E-4

H7325455.72N,459194.27E

05.02.2000

12.03.2000

PRODUCTIO

NPLUGGED

NA

4508

6608/10-E-4

AH

7325455.72N,459194.27E

12.03.2000

01.06.2000

PRODUCTIO

NPRODUCING

OIL

6069

6608/10-F-1

H7325354.98N,459309.39E

29.04.1999

27.05.2005

INJE

CTIO

NINJE

CTING

WATER

3170

6608/10-F-2

H7325350.39N,459304.92E

18.09.1999

15.10.1999

INJE

CTIO

NINJE

CTING

WATER

3048

6608/10-F-3

H7325357.56N,459301.87E

02.12.1999

05.02.2000

INJE

CTIO

NINJE

CTING

WATER

3370

6608/10-F-4

H7325364.72N,459299.20E

10.06.2001

06.07.2001

INJE

CTIO

NINJE

CTING

WATER

4280

6608/10-F-4

AH

7325364.72N,459299.20E

01.10.2007

08.11.2007

INJE

CTIO

NSU

SP.ATTD

WATER

4080

6608/10-J-2H

7325822.28N,462456.23E

02.11.2005

22.12.2005

PRODUCTIO

NPRODUCING

OIL

3290

6608/10-K-1

H7321915.19N,457092.53E

18.10.2006

20.12.2006

PRODUCTIO

NSU

SP.ATTD

3795

6608/10-K-3

H7321926.4N

,457087.91E

04.09.2006

17.10.2006

PRODUCTIO

NSU

SP.ATTD

3849

Continued

onNextPage...

48

Table3.11

Continued

Nam

eUTM

Entry

Date

Com

pletion

Purpose

Status

Contents

Total

coordinates

Date

Depth

[m]

6608/10-K-4

H7321918.24N,457095.73E

29.03.2007

29.10.2007

PRODUCTIO

NSU

SP.ATTD

OIL

4104

49

3.3.4 Description of development wells

Well 6608/10-B-1 H

The tenth development well to be drilled on the Norne Field was well 6608/10-B-1 H. This was

a horizontal well, producing from Ile 2 and Tofte 3 Formations. The purpose was to drain oil

from the C-segment, mainly the north eastern parts. Reasons for drilling this well was the desire

to achieve low GOR and at the same time rapidly build up to plateau production. Production

start was 1st of April 1999.Two horizontal segments were the producing parts of the B-1 H well. The rst, in the

heal of the well, was 400 m long and located in the top of the Ile 2 Formation. The second

horizontal segment, located in the Tofte 3 Formation, was 600 m long and was the toe of the

well. Further completions were possible and also side-tracking toward the northern parts as a

horizontal producer in the Ile Formation. The well was plugged in October 2005. [Statoil, 1999a]

A pilot well, 6608/10-B-1 AH, was drilled as a sidetrack to 6608/10-B-1 H to conrm the

location of the OWC as interpreted from the 2004 4D seismic data. This was done to optimise

the placement of the production well 6608/10-B-1 BH, which started production January 2006.

Pressure data from the dierent reservoir sections were acquired in the pilot. [Statoil, 2005a]

Well 6608/10-B-2 H

As the third development well to be drilled, well 6608/10-B-2 H started to produce the 9th of

December 1997. It produces from the eastern part of the C-segment with a horizontal section

from northwest to southeast in the top of the Ile Formation.

The horizontal section of the well is 850 m long and is completed in the Ile Formation for

production. At a later stage the whole reservoir can be completed for production, from top Garn

to total depth. This will allow for both oil and gas production. [Statoil, 1997a]

Well 6608/10-B-3 H

At 1st of July 1999, well 6608/10-B-3 H started to produce from the western part of the D-

segment and the southern part of the E-segment. The well is completed in Ile 2 and Tofte 3

Formations.

The well was drilled in two horizontal sections to enable production from both Ile and Tofte.

As there are two major faults in this area, the completed intervals are much shorter than in

B-2 H for instance. The depths of both sections were set based on the goal of not having early

water break through or high gas-oil ratio. The well was initially completed in the Ile and Tofte

Formations, and can be further completed along the entire reservoir interval in the future if that

is needed. [Statoil, 1999b]

50

Well 6608/10-B-4 H

Well 6608/10-B-4 H was the fth development well drilled on the eld. It was a vertical pro-

ducer, drilled through Garn, Ile, Ror, Tofte and Tilje Formations. The well was planned to

drain the western part of the C segment and started producing the 27th of April 1998. It was

perforated only in the Tofte 3 Formation, while the whole interval is available for perforation,

and modications have been performed. The well was shut May 31st 2001. [Statoil, 1998a]The well 6608/10-B-4 AH was drilled as a pilot for well 6608/10-B-4 BH to locate the present

oil-water contact and the formation tops in the D-segment. With this information, the placing

of well B-4 BH in the exact right spot was easier. A better understanding of the pressure balance

was also achieved. The pilot well B-4 AH was a success. [Statoil, 2002a]

The objective of drilling well 6608/10-B-4 BH was to make a 600 m long horizontal well

within the Ile 2 Formation. The oil-water contact was actually deeper than rst anticipated,

and the result was a 483 m long horizontal section in the upper part of the Ile 2 Formation.

Perforations were made in this section as well as in the Garn 3 Formation where a gas lift valve

was installed. The production from B-4 BH started the 1st of August 2001 and lasted until the

1st of September 2003 when it closed due to high water production. [Statoil, 2002a]

Well 6608/10-B-4 CH was planned and drilled as a pilot for well 6608/10-B-4 DH to verify

the uid contacts in the location where B-4 DH was planned. The pilot were drilled because of

uncertainties about location of the gas-oil and oil-water contacts in the C-segment. In addition to

this, a calibration of the contacts to the 2003 4D seismics was important in order to place B-4 DH

in the optimal position. Two dierent gas-oil systems with dierent levels of the uid contacts

were discovered in the pilot drilling. Some were higher than expected and some lower. Residual

gas was found below the Not Formation in addition, this came from the C-3 H injector. [Statoil,

2005b]

The objective of drilling well 6608/10-B-4 DH was to drain oil from the upper Ile Formation

in the south western area of the C-segment. This was done with a horizontal production well.

As a result of the pilot drilling, the planned well path was changed to the alternative location

to avoid the large amounts of injected gas around well C-3 H. The rst attempt to drill this well

was stopped due to failure in the PowerDrive BHA, and the hole was plugged and abandoned.

The next attempt was called B-4 DHT2. This was side-tracked in the Melke Formation and

drilled much further to the east, away from C-3 H. The well was drilled through the Garn

Formation and into the upper Ile Formation where it has a 357 m long perforated, horizontal

section. Production from this well started the 4th of July 2004. [Statoil, 2005b]

Well 6608/10-D-1 H

This well was the rst development well to be drilled on the Norne Field. The plan was to drill

it as a producer in the Ile, Ror and Tofte Formations in the southern part of the eld. Average

inclination of the well from top Ile to total depth was 44. As this was the rst well to be drilledin this area, results from the well was important for the further development of the eld and

numerous tests were performed. The production start in this well marks the start of the life of

51

the Norne Field; the production start date was the 7th of November 1997. The well was shut

the 1st of September 2002. [Statoil, 1997b]When well D-1 H was shut, a side-track was planned. A pilot, 6608/10-D-1 AH, was to be

drilled rst to log the formation, nd uid properties and the oil-water contact in the southern

part of the C-segment. When the drilling of the pilot started, the drillstring got stuck and the

well needed to be redrilled to run the logs. It was decided not to do this due to a relatively

high cost and risk compared to gain. The well was plugged back and drilling of the producer,

6608/10-D-1 BH, commenced. The plan for well 6608/10-D-1 BH was to have a highly deviated

section placed in the Ile Formation using geosteering. Logging While Drilling (LWD) through

the Garn, Not, Ile 3 and Ile 2 Formations was performed to achieve a sucient production

interval in Ile 3 and Ile 2 Formations. A 350 m long interval was achieved in Ile 3, while in Ile

2 a 800 m long interval was achieved. The gas lled Garn Formation, is open for perforation at

a later stage. This well started to produce the 2nd of November 2003. [Statoil, 2003]

Well 6608/10-D-2 H

The plan for well 6608/10-D-2 H was to drill a horizontal producer through the Ile Formation

in the C-segment. Because of lost cones in the hole, the rst track was plugged back soon after

entering the Ile reservoir.

The second track, 6608/10-D-2 T2H, was more successful and reached its target in Ile 2 and

Ile 3 with a near horizontal section of almost 1.1 km. This well was abandoned for a short while

with the plan of perforating it in Ile 2 for production. The well started producing the 24th of

December 1997. [Statoil, 1997c]

Well 6608/10-D-3 H

The well 6608/10-D-3 H was drilled as a pilot to conrm the location of the oil-water contact in

the C-segment. The producer in the area was planned to be well 6608/10-D-3 AH. The plan was

to make a horizontal producer through Ile 2 and Tofte 3 reservoirs. The result was according to

plans with a 53 m long section of Ile 2 Formation and a 998 m long section of Tofte 3 Formation

penetrated. At rst, only the Tofte 3 reservoir was perforated for production, which started the

28th of August 2000. The well was closed the 2nd of June 2005. [Statoil, 2001a]When well D-3 AH was shut, a multilateral side-track was planned. This was to consist of

one lateral to drain oil from the Ile 2 Formation in the C-segment, 6608/10-D-3 BY1H, and one

lateral to drain oil from the Ile 2.2 Formation in the western part of the D-segment, 6608/10-D-3

BY2H. [Statoil, 2006b]

The rst lateral, D-3 BY1H, was side-tracked from D-3 AH in the Spekk Formation and the

goal was to drill through the Spekk, Melke, Garn and Not Formations and then land horizontally

in the Ile 2 Formation. The rst attempt on this failed because the required buildup angle was

not achieved. The hole was cemented back and a new attempt was made. This attempt, D-3

BY1HT2, was again side-tracked from the Spekk Formation, and this time it was a success. The

target was reached and logging indicated hydrocarbons along the entire reservoir section.

52

The second lateral, D-3 BY2H, was side-tracked from D-3 AH in the Lyr Formation. The

well was successfully drilled down to the Not Formation and into the Ile 1.3 and 1.2 Formations

where it went almost horizontal until it reached a main fault. Then it went through a short

section of the Not Formation before it was drilled through the Ile 2.2 and 2.1 Formations. Due

to complications when the production liner was to be run, this lateral was abandoned and the

D-3 BY1HT2 was completed as a single bore producer. [Statoil, 2006b]

The production from D-3 BY1HT2 started the 26th of February 2006.

Well 6608/10-D-4 H

This sixth development well to be drilled on the Norne Field, 6608/10-D-4 H, was a deviated

production well with an inclination of 40 through the Garn, Not, Ile, Tofte, Tilje and Åre

reservoir intervals. The purpose was to drain the eastern part of the C-segment and to contribute

to a rapid build-up to plateau production. At rst, the well was perforated in the Ile and Tofte

reservoirs and started production the 17th of June 1998. At a later stage, the entire reservoir

section can be completed for production or the well can be side-tracked to a more north-eastern

prospect. [Statoil, 1998c] Production from well 6608/10-D-4 H was shut the 16th of November

2002 because of water breakthrough.

When well D-4 H was shut, a plan for the side-track was made; well 6608/10-D-4 AH. The

plan was to drain oil from the Garn Formation in the north-eastern part of the D-segment

with a highly deviated well. To reach the goal, the well was to be drilled with Gyro. When

rigging up for this, the drill string got stuck and it was shot o. Well D-4 AH was plugged and

abandoned. [Statoil, 1998b]

A second attempt of drilling the producer was made, called 6608/10-D-4 AHT2. The plan

was to perforate large intervals of the Garn 3 and Garn 2 reservoirs. A section of 300 m of the

Garn 3 reservoir was planned to be perforated initially. Thereafter 100 m of the Garn 2 reservoir

was to be perforated. When the well was drilled, an unexpected fault was penetrated in the

Garn 3 reservoir. The result was 155 m long perforation in the Garn 3 Formation and 122 mlong perforation in the Garn 2 Formation, with a possibility of expanded perforation interval

in the Garn 2 Formation. The total length of the perforation was according to plan, but the

perforations in the Garn 3 Formation were reduced due to the fault. [Statoil, 1998b] Production

from D-4 AHT2 started the 4th of June 2003.

Well 6608/10-E-1 H

Well 6608/10-E-1 H was the ninth oil production well and the fourteenth development well

drilled on the eld. It was designed as the fth horizontal production well, to drain oil from the

southern part of segment E. Low GOR oil was planned to be produced from the well, and it

should facilitate the rapid build up to plateau production on the eld.

Ile 2 and Ile 3 Formations were completed, but the entire reservoir interval can be completed

if necessary in the future. [Statoil, 2000a] Production from well 6608/10-E-1 H started September

1999.

53

Well 6608/10-E-2 H

The tenth oil producer and sixteenth development well to be drilled on Norne was well 6608/10-

E-2 H. The well was horizontal, and should drain oil from the southern part of the E-segment.

This well was planned for producing a low GOR oil, and facilitating the rapid build up to plateau

production.

The reservoir was at 2604 m TVD MSL, and the well was drilled horizontal at that depth. Ile

3 and Ile 2 Formations were perforated. The location of GOC and OWC were studied when the

well was to be placed to prevent early water break through and high GOR oil. [Statoil, 2000b]

Well 6608/10-E-2 H started producing oil November 1999 and was producing until July 2005.

The objective for well 6608/10-E-2 AH was to drain the remaining oil in segment E. The

well trajectory was planned as a horizontal section below the Top Ile Formation, over the OWC

at approximately 2606 m TVD MSL. It was drilled deeper than planned and penetrated higher

than the anticipated OWC, before it was steered back through Ile 2.1 Formation. [Statoil, 2006c]

The well started to produce oil in August 2005.

Well 6608/10-E-3 H

Well 6608/10-E-3 H was the eighth development well and rst production well planned in the

northern part of segment E. An inclination of 16 in the well path through Garn, Not, Ile, Tofte

and Åre Formations was used. The central part of segment E was the target for draining. The

well was designed to contribute to a low GOR oil production, and provide a reference point in

the northern part of the eld to conrm reservoir communication.

Ile and upper Tofte Formations were completed, but the entire reservoir interval was planned

to be available for completion at later stages. In addition, the well can be sidetracked as a

horizontal well toward the western part of segment E. [Statoil, 1999g] Well 6608/10-E-3 H

started production December 2000 and was plugged May 2000.

Well 6608/10-E-3 AH was designed as a horizontal well to drain oil from the Garn Formation

in the northern area of Segment E. It was assumed that the OWC was at 2688.5 m TVD/MSL

and the path was planned thereafter. During drilling it was found that the OWC was at a

shallower depth than rst expected. The consequence was a drilling stop and plugging back

before sidetracking as well 6608/10-E-3 AHT2.

Well 6608/10-E-3 AHT2 penetrated the Garn Formation horizontally. The well was located

in sands containing oil the whole section except for an interval in the water zone. The OWC

could in that way be dened in the Garn Formation to be 2617 m TVD MSL in the central

part of Segment E. [Statoil, 2002b] It started up production December 2000 and produced until

January 2005.

Well 6608/10-E-4 H

Well 6608/10-E-4 H was a pilot well drilled to test the depth of the Garn Formation in Segment

G. Bad weather suspended drilling of the well, and the BHA was pulled into the casing. When

54

the hole was reentered, the BHA hit an obstruction which could not be bypassed. The solution

was to sidetrack the well to 6608/10-E-4 HT2.

Well 6608/10-E-4 AH was the eleventh oil producer drilled, located in the G-segment. It

was horizontal, placed 5-10 m TVD below the top of the Garn Formation, sidetracked from pilot

well 6608/10-E-4 H. During completion, problems occurred and the well had to be sidetracked

to 6608/10-E-4 AHT2.

Well 6608/10-E-4 AHT2 was completed in the Garn Formation, with a 600 m interval per-

forated. [Statoil, 2002c] Well 6608/10-E-4 AHT2 started production in June 2000. Then there

was a stop in production from June 2001 until August 2002 and from July 2005.

Well 6608/10-K-1 H

The actual trajectory of well 6608/10-K-1 H did not follow the planned wellbore because the

main fault between C and D segments was greater than prognosed. The well was cemented to

the Not 1 Shale, and sidetracked with the K-1 HT2 through Ile 2.2 and Ile 2.1 Formations. The

well entered the Ile 1.3 before it crossed the main fault and entered the Ile 2.2 where it was

perforated.

The well was planned to drain remaining oil from the Ile Formation in the north-western

part of segment C and south-western part of segment D. K-1 H was designed as a producer only

and the whole interval was planned to be available for perforation. In the future, it is possible

that K-1 H may be sidetracked from Not Formation or Melke Formation. [Statoil, 2007a]

Well 6608/10-K-3 H

Well 6608/10-K-3 H started to produce oil 15th of October 2006. It was the rst production welldrilled from the K-template. This well was also used to drill the exploration well 6608/10-11 S

Trost, before proceeding down, deviated to horizontal, to the base of the Melke Formation. The

well was completed in the Ile 2.2 Formation.

The primary objective of the well was to drain the remaining oil in the Ile Formation in

segment C. The well can be sidetracked at later stages from the Not Formation or Melke For-

mation. [Statoil, 2007b]

Well 6608/10-K-4 H

Well 6608/10-K-4 H was designed as a horizontal producer through the Ile 2.2 Formation. When

drilling through Not 1 Shale, it collapsed, and the wellbore was abandoned. Thereafter the

sidetracked K-4 HT2 was steered according to the plan.

Primary objective of the well was to drain oil from the Ile Formation in the north-western

part of Segment C. The well was designed as a producer only, where the whole reservoir interval

was planned to be available for completion in the future. [Statoil, 2008]

55

Well 6608/10-C-1 H

Well 6608/10-C-1 H was the seventh development well and the rst water injection well drilled

on the Norne Field. It injects water into the water leg. This well could also inject gas at a later

stage if needed. All injectors on the C template can convert between water and gas injection.

An inclination of 12 was used and the well was drilled through Garn, Ile, Ror, Tofte, Tilje and

Åre Formations. Completion of the well was performed with a perforated cemented liner within

the base Tofte and upper Tilje Formations, and the injection started the 21st of July 1998. Thewell can be perforated through the whole interval later if needed. Side-tracking of the well in

north-east direction is also possible if water support is required in the Norne G-segment. [Statoil,

1999c]

Well 6608/10-C-2 H

The second water injector to be drilled on the Norne eld was the 6608/10-C-2 H injector. The

plan was that this injector should support the already existing injection into the southern part of

the eld provided by C-1 H. This well can also easily be converted to a gas injector if needed. It

was drilled through the Garn, Ile, Tofte, Tilje and Åre Formations with an inclination of 50-45.The well was perforated within the Tilje 3 and 4 Formations. The entire reservoir interval is

available for perforation at a later stage and there is a possibility of side-tracking toward the

southern parts of the C-segment. [Statoil, 1999d] The injection started the 21st of January 1999.

Well 6608/10-C-3 H

Well 6608/10-C-3 H was the third water injection well to be drilled on the Norne eld. The

plan for this well was to support the existing injection from C-1 H and C-2 H in the southern

part of the eld, by injecting water into the water leg. As for the other injection wells at the

C-template, C-3 H can easily be converted from water injection to gas injection. The well was

drilled through the Garn, Ile, Tofte, Tilje and Åre reservoir intervals with an inclination of

15-10. The perforation started about 10 m TVD above the oil-water contact, in the Tofte 3

Formation, and continued within the Tofte 2, Tofte 1 and Tilje 4 Formations. Injection start

was on the 21st of May 1999.

The well is located in the south-western part of the C-segment with the bounding faults of

the main eld to the north and southwest. When the well was pressure tested it was discovered

that there were poorer communication between Ile, Tofte and Tilje than expected. This was the

reason why the injection from C-1 H and C-2 H increased the pressure only in the Tilje Formation

and not in the Tofte Formation. To enhance the pressure support in the Tofte Formation the

perforations were made higher up than originally planned. [Statoil, 1999e]

Well 6608/10-C-4 H

Well 6608/10-C-4 H was drilled in the north-western part of the C-segment as the second devel-

opment well. The well penetrates the Garn Formation and is a vertical gas injector. Perforations

56

are made with a cemented liner in Garn 3. The injection started the 22nd of November 1997

and lasted until the well was shut the 18th of November 2003. Well C-4 H was then plugged and

side-tracked to well C-4 AH. [Statoil, 1999f]

The reason for shutting well C-4 H was that it contributed to a high gas-oil ratio and water

cut in the neighbouring production wells. Well 6608/10-C-4 AH was drilled as the rst injector

in the Ile Formation on the C-segment. It was placed there to provide pressure support, enhance

the oil sweep from the Ile Formation and to verify the oil-water contact in the Garn Formation.

The well was drilled to total depth in the Åre Formation with an inclination of less than 20.The initial perforations were a 38 m long section in the Ile Formation, with the possibility of

extending to cover the entire reservoir section, from Garn to Tilje, at a later stage. As for the

other wells at the C-template, it can easily switch between water and gas injection. [Statoil,

2004]

Based on new seismic data, the original target was moved about 100 m to the southwest to

be able to verify the oil-water contact in the Garn Formation. The contact was not proved in

the well and suggested that the oil-water contact still corresponds to the initial of 2692 m TVD

MSL. The injection from C-4 AH started the 20th of January 2004. [Statoil, 2004]

Well 6608/10-F-1 H

Well 6608/10-F-1 H was the fourth water injector to be drilled, located to the north of the Norne

E-Segment. The well was designed to inject water in the water leg in northern part of the eld.

All wells on the F-template can easily be converted from water to gas injection. Well F-1 H was

drilled vertically through Garn, Ile, Tofte, Tilje and Åre Formations. The well was perforated

approximately 23 m TVD below the oil-water contact in the Ile and Tofte Formations. Injection

from this well started September 1999.

The entire reservoir interval can be perforated in the future. Pressure testing from the well

has proved good communication between Ile and Tofte. [Statoil, 1999h]

Well 6608/10-F-2 H

The fth water injector drilled on Norne was well 6608/10-F-2 H, located to the north of the

Norne D-Segment. An angle of 13 was used on the trajectory through Garn, Ile, Tofte, Tilje

and Åre Formations. The well was perforated within the interval of Ile and Tofte, approxi-

mately 31.5 m below the oil-water contact. The well started injection of water in October 1999.

As for well F-1 H, the entire reservoir interval is available for further completion, and pressure

testing from the well has proved good communication between Ile and Tofte Formations. [Statoil,

2000c] The well can easily be converted from water to gas injection. [Statoil, 1999h]

Well 6608/10-F-3 H

This was the sixth water injector drilled on the eld, located in the south-western part of the

E-segment. The well was drilled with an angle of up to 50 in the top hole section and less

than 20 in the reservoir. It was perforated in the Tofte and Tilje Formations [Statoil, 2001b].

57

Injection start was in September 2000. As for the other wells in the F-template it is easy to

convert from water to gas injection. [Statoil, 1999h]

Well 6608/10-F-4 H

Well 6608/10-F-4 H was the seventh water injector drilled with purpose to inject water into the

water leg south of well E-4 AHT2 in the G-segment. This well had no pressure support and had

to be shut in for a period in 2001 and 2002 due to low reservoir pressure. [Statoil, 2002d] The

injector started injecting water in September 2001 and it can easily be converted to inject gas.

58

3.4 4D seismic data

3.4.1 Introduction to 4D seismic data

4D seismic data is 3D seismic data acquired over the same area at dierent times. Time-lapse

seismics is another word for this technology, which purpose is to detect changes in the subsurface

during production of hydrocarbons. The observed changes are changes in uid location and

saturation, as well as in pressure and temperature. This kind of seismic data can be acquired

either on the surface or in a borehole. [Schlumberger Oileld Glossary] It is important to have

the various surveys surveying the exact same locations to achieve reliable results. The best

results are obtained if receivers are permanently placed at the seabed so that the signals are

recorded from the exact same places during each survey.

Statoil has used 4D seismic data in the reservoir management for approximately 70% of

their operating elds. The data has produced important information used to locate remaining

hydrocarbons in the reservoirs. [Ouair et al., 2005] On the Norne Field, a total of 5 seismic

surveys have been carried out, starting with the rst conventional base survey in 1992. The next

four surveys have been rendered with a Q-marine vessel in 2001, 2003, 2004 and 2006. [Statoil,

2006a] The survey area is shown in gure 3.21. Repeatability is good and the survey data is of

high quality. The only place where the data is poorer, is in the area around and beneath the

Norne production vessel. Undershoot was performed in the monitor surveys in order to generate

coverage beneath the vessel. This gives a fairly acceptable repeatability in this area. [Ouair

et al., 2005] The next Q-marine survey is to be performed during June 2008 [Cheng and Osdal,

2008].

The survey performed in 2001 was a 40 km2 single source survey. It was named ST0113 and

was intended as a time-lapse survey. ST0113 was compared to the survey from 1992. Earlier

in 2001, a survey on the Norne Area was performed with reservoir characterisation as purpose.

The survey was called ST0103 and data from this was included in the processing of ST0113

to ensure the necessary migration aperture. The Q-marine survey acquired in June 2003 was

named ST0305. It covered 85 km2 and was carried out as identically as possible to ST0113. The

3rd Q-marine survey, ST0409 covered a larger area, approximately 146 km2. It was acquired in

July 2004, as identically as possible to the 1st and 2nd survey. The 4th Q-marine survey, ST0603,

was shot in July/August 2006, as identically as possible to the 3rd survey. Time-lapse changes

in the reservoir between the years 2001, 2003, 2004 and 2006 could now be identied. Several

undershoot lines were acquired to monitor beneath the Norne production vessel. Two dierent

undershoot vessels and source were used. The rst was used in the 2001 and 2003, while the

second was used in the 2004 and 2006. [WesternGeco, 2007]

Seismic data available in this work:

3D seismic survey from 2006 with near, far, mid and full osets

4D cubes from the years 2006-2001, 2006-2003, 2003-2001 and 2004-2001

interpreted top reservoir horizon

59

interpreted faults

well paths for all wells

interpreted oil-water contacts from 2001, 2003, 2004 and 2006

interpreted cubes of pressure and water and gas saturations from the years 2006-2001,

2006-2003 and 2003-2001

2 velocity cube for conversions, both time and depth

All the data can be acquired by requesting [Department of Petroleum Engineering and Ap-

plied Geophysics].

Figure 3.21: Map of the seismic survey area, with wells

The usage of the 4D seismic data at the Norne Field has been to observe the dierence

in amplitude and acoustic impedance. Results have then been used to adjust the simulation

model [Cheng and Osdal, 2008]. The 4D results have indicated changes in the saturations,

which the simulation model did not predicted. In the Garn Formation, water was predicted

from the model as migrating to the northwest and south of one of the wells. However, 4D

inversion clearly indicated migration of water to the east. This demonstrates the importance

time-lapse seismics has for a eld with complex geology as Norne. Two additional cases have

60

involved issues where the model could not predict future behaviour with condence, and 4D

data provided the required data. [Boutte, 2007] The 4D seismic data is also an important tool

in the process of targeting the remaining oil. [Statoil, 2006a]

3.4.2 Seismic processing

The processing of each survey was performed in two phases; a generation of a fast-track cube and

a full processing. The pre-stack and post-stack portions of the full seismic processing ow of the

2006 survey are illustrated in gures 3.22 and 3.23. A detailed description of all the processing

steps can be found in [WesternGeco, 2007], attached digitally.

Figure 3.22: The pre-stack portion of the full seismic processing ow [WesternGeco, 2007]

61

Figure 3.23: The post-stack portion of the full seismic processing ow [WesternGeco, 2007]

62

4D Quality Control

The quality control (QC) of 4D seismics included generation of 3D stacks of the full volume. It

also involved analysis of amplitude, phase and time dierences between data sets from dierent

years, normalised rms dierence amplitudes and visual inspection of inline and crossline dier-

ence data sets. These attributes were computed in a 2000-3000 ms window, after use of a 5-40

Hz bandpass lter. A full 4D QC was performed at the following stages:

- Missing shot interpolation- SRME (Surface Related Multiple Elimination)- Taup mute and radon demultiple- Swath dependent time shifts- Dip-moveout- Inverse dip-moveout- Final stack- Final post processing

No problems of importance were observed in the 4D QC. The 4D QC steps performed

throughout the processing ow, see gures 3.22 and 3.23, indicate that the processing ow was

performed as intended. [WesternGeco, 2007]

63

3.4.3 Seismics on Norne

The SeisWorks® 3D software is used for viewing of seismics in this thesis. Seisworks provides

innovative 3D viewing and interpretation capabilities and is an industry standard software.

3D seismics

To get an impression of how the Norne Field looks like in the subsurface, 3D seismics can be

studied. Geophysicists can interpret faults, horizons and other trade terms, based on available

geological information and seismic images. Knowledge of the locations of top reservoir and

oil-water contacts, is important information required for calculation of the reservoir volume.

Observed changes in the horizons over time are also of interest. When the oil-water contact

moves up, it denotes that the amount of hydrocarbons left in the reservoir decreases. A change

in the position of the top reservoir horizon can suggest that there has been a change in the

pressure, accordingly a compaction.

For this master thesis, line number 1100 and trace number 1600 are selected to represent the

eld. However, all lines and traces are available for the work. Three wells located in the vicinity

of line 1100 are selected to be represented by logs. These are wells are B-1 H, D-1 H and E-1 H.

The gures B.51- B.54 in appendix B.2.1 demonstrates the oil-water contact at dierent years.

The top reservoir is represented as the horizon called Top Not 2. Several faults are marked, and

the three wells B-1 H, D-1 H and E-1 H are also included in the gures. The same properties

are shown for trace 1600 in gures B.55-B.58.

Logs from the three chosen wells are attached to the thesis digitally on a CD. A few of the

wells on Norne have been logged with sonic logs, i.e. dt or dts. Only D-1 H has sonic data

of the three wells B-1 H, D-1 H and E-1 H. The log for D-1 H is edited and corrected for mud

ltrate invasion, and are suitable for modelling. The logs used for this well is gr, phie, phit,

rhob_v, vp_v and vs_v. For the two other wells, there exist data for dt_synt, gr, phif

and rhob. dt_synt is a synthetic dt log made with linear relation and is not logged in the

bore hole.

Changes of the oil-water contact from the rst survey, 2001, to the last, 2006, are shown in

gures 3.24 and 3.25 for the line and the trace, respectively. The gures are made in time, i.e.

the y-axis. As can be seen, the wells are not located far from the oil-water contact in 2006, but

both the production wells, B-1 H and D-1 H, was sidetracked to higher formations before this

survey.

64

Figure 3.24: 3D seismic, line number 1100 showing oil-water contact in 2001 and 2006

65

Figure 3.25: 3D seismic, trace number 1600 showing oil-water contact in 2001 and 2006

66

4D seismics

The Q-marine surveys shot in 2001, 2003, 2004 and 2006 are used for 4D seismics. Time-lapse

changes in the reservoir between the dierent years are identied by use of these data. In

this work, data cubes with dierence between acoustic impedance between the following years:

2001-2003, 2001-2006 and 2003-2006 are studied. These dierences are extracted by subtraction.

4D data with dierence between 2001 and 2006 are shown in gures 3.26 and 3.27. Result for

the same line and trace for the years 2001-2004 and 2001-2003 are given in gures B.60, B.62, B.59

and B.61 in appendix B.2.2, respectively.

Figure 3.26: 4D seismic, line number 1100, 2001-2006

Changes in acoustic impedance are due to pressure or saturations changes which lead to a

dierent velocity. The interpretations are made by geophysicists in StatoilHydro working with

the eld on a daily basis. To be able to show the interpreted changes in relation to the seismic

area it belongs to, it is necessary to display both pictures. This can be done with the overlay

function in seisworks. The pressure or saturation change is shown as variable density, while the

4D cube is put on top as wiggle. In order to do this, it is important that both the 4D data and

the interpretations are made in either depth or time. It is possible to convert the cubes between

67

Figure 3.27: 4D seismic, trace number 1600, 2001-2006

depth and time by use of a velocity cube.

The gure 3.28 shows 4D seismics overlaid interpretation of pressure changes from 2001 until

2006.

4D seismics is an important tool in connection with well planning. By studying the water

saturation changes in the reservoir, water ooded areas can be located and avoided as possible

well locations. To avoid high gas-oil ratio, the gas saturation changes should be studied. The

4D seismics can also be utilized in the work of history matching by comparing real seismics with

synthetic seismics created from the simulation output. Agreement and disagreement between

the simulation model and the historical data can be discovered from such a comparison.

68

Figure 3.28: 4D seismics overlaid interpreted pressure dierence , 2001-2006

69

As mentioned above; synthetic seismics can be made from simulation programs. A program

which generates seismic pictures from the Eclipse simulation is developed by Alexey Stovas

at NTNU. The software enables the ability to compare real seismics with synthetic seismics.

Dierences found from comparisons can tell something about accuracy of the Eclipse simulation.

However, uncertainties related to the seismic processing have to be considered in this work.

Figure 3.29 illustrates synthetic seismics from Norne with Common Midpoint (CMP) vs. Time.

This gure is generated from data from the Eclipse simulation.

Figure 3.29: Example of synthetic seismics from Norne [Stovas, 2008]

70

3.5 Production data

The Norne Field is being developed with a oating production and storage vessel tied to six

subsea templates. The templates are placed on the sea bottom approximately 380 meters below

sea level, and are grouped together in two clusters. The southern cluster consists of templates

B, C, D and K, while the northern cluster includes templates E and F. The distance between

these two clusters is approximately 3900 meter, and the templates on each cluster are located

approximately 120 meter from each other. The vessel is positioned between the two clusters.

Template K was the last template to be added to the Norne Field. It was placed on the seabed

in 2005, 150-200 meters south of B, C and D templates.

Each template has 4 well slots. Two of the templates are dedicated for injection, and four

for production. Template C and F are injection templates, while the rest are for production.

The injection templates are for combined water and gas injection, where all slots can change

between injection of water and gas by use of a ROV. [Statoil, 2001c] [Statoil, 2006a]

Gas export from the eld started in February 2001. The gas is exported through the Norne

Gas Export Pipeline and the Åsgard Transport trunkline via Kårstø north of Stavanger to

continental Europe. [StatoilHydro, 2008]

Production an injection rates are included in the tables C.1-C.6 in appendix C.1 and C.2.

The rates are also attached digitally on a CD in excel format. The rates are constant in periods,

and only dierences in rates are given in the tables. Plots of production rates, water cut and

gas-oil ratio for all the production wells are presented in appendix B.1 in gures B.1-B.39. The

injection rates are also plotted in the same appendix in gures B.40-B.50.

3.5.1 Data acquisition during production

Production testing, production logging and reservoir pressure monitoring are carried out regu-

larly during production for reservoir management purposes.

A multiphase meter installed on the production vessel is used for production testing. The

testing is performed to measure production potential and wellstream composition (gas-oil ratio,

water cut and sand content) and to allocate production to the individual well. Another aspect

of the well testing is production loss, or delay, during the testing. This can make it dicult to

justify testing when short term production goals needs to be fullled. Having enough data to

allocate production rates to wells on a daily basis is important, especially in case of unexpected

circumstances, and this can justify the need for testing. In 2001 the average test frequency for

a well was every second month [Statoil, 2001c], while the average test frequency for a well was

every month in 2007 [Fawke, 2008].

Logging during production is run for identifying the composition of production and well-

stream from the dierent reservoir zones and to detect uid contact movements. The ndings

from the production logging can improve the understanding of the reservoir dynamics. It is also

done to evaluate possible zone isolations.

Down hole pressure gauges in the production wells are monitoring the reservoir pressure.

71

These pressure measurements can be important for the description of the reservoir, together

with FMT pressure measurements.

Tracer injection is also accomplished. This is done to get information about reservoir com-

munication and it can detect seawater breakthrough in production wells. [Statoil, 2001c]

72

Chapter 4

Reservoir Simulation Model

4.1 Reservoir Modelling

A geological reservoir model was created based on executed reservoir geological interpretations.

The model is used for reservoir simulation, well planning and calculations of reservoir volumes.

Reservoir zonation

The reservoir was divided into 22 reservoir zones for the modelling. Some of the boundaries

between zones were selected as sequence boundaries and maximum ooding surfaces. Other

boundaries were based on lithology or dened on porosity/permeability from wells 6608/10-2

and 6608/10-3. Surrounding wells were used for correlation of boundaries. The reservoir zones

are listed in table 4.1. An old reservoir zonation is shown in gure 4.1; this includes explanation

of boundary denitions. In addition, the gure indicates that Garn 2, Ile 1 and Ror are top

of calcareous cemented horizons. After this gure was made, the names have been updated.

The zones Ile 3, Ror and Tofte 3 have been included in the zones listed in table 4.1. Tilje has

been subdivided into 4 zones, Garn into 3, and Ile and Tofte are subdivided into 2 zones. All

the Ile and Tofte zones are rened, especially Ile 2.1, Tofte 2.1 and 1.2, to enhance vertical

resolution [Statoil, 2005c].

Correlation of reservoir zones led to the result of the reservoir division and is illustrated in

gure 3.4. From the gure it is noted that the Norne reservoir is thinning to the north due to

erosion at the base Tofte and base Ile 3 sequence boundaries. [Statoil, 1994a]

Isochores

Isochore maps were generated for every individual reservoir zone. They were constructed based

on reservoir zonation data, available sedimentological data and overall gross reservoir thickness

variations determined by seismic data.

An indication of a general thinning of the reservoir toward northeast was found from the total

seismic isochore between Top Garn and Top Åre reectors. This thinning is parallel and op-

posite to the sediment transport direction found from paleogeographical interpretations. These

73

Table 4.1: Reservoir zonation from the BC0407.DATA le

Layer Layer Layer Layernumber name number name

1 Garn 3 12 Tofte 2.22 Garn 2 13 Tofte 2.1.33 Garn 1 14 Tofte 2.1.24 Not 15 Tofte 2.1.15 Ile 2.2 16 Tofte 1.2.26 Ile 2.1.3 17 Tofte 1.2.17 Ile 2.1.2 18 Tofte 1.18 Ile 2.1.1 19 Tilje 49 Ile 1.3 20 Tilje 310 Ile 1.2 21 Tilje 211 Ile 1.1 22 Tilje 1

interpretations indicated a sediment transport direction from northeast toward southwest for

several reservoir intervals. Analysis of paleo-current directions from dipmeter data supported

this interpretation. The variation of gross reservoir thickness was led by a quite constant dier-

ential subsidence over the area. The amount of erosion along the intrareservoir unconformities

and depositional thickness of the reservoir intervals are indications of this. Also, the sediment

transport direction from dipmeter data supported this conclusion.

The result of the above discoveries was that reservoir zone isochores and intrareservoir un-

conformities reect a northwest-southeast trending coastline. When constructing the isochores

the rst time, only one well correlation prole through the eld was available, so all isochores

were constructed with linear contours with a trend in the direction of northwest-southeast,

about 125°. Figure 3.4 shows an illustration of internal reservoir geometry dened by isochores;

a cross section through the wells where zone isochores are added to a top Garn plane surface

datum. [Statoil, 1994a]

The reservoir model

The isochores were used to form the spatial reservoir model together with seismic depth structure

maps. For reservoir modelling, the IRAP (Interactive Reservoir Analysis Package) mapping

system was used. Grid cell sizes of 50*50 meters is used for representing the reservoir. True dips

are modelling the major faults in the eld, while small faults less than 20 meters are represented

by simple addition. Wells in the eld are treated as deviated wells, by employing true vertical

depths and deviation data.

The rst step of the modelling was to stack the isochores within the seismic envelope de-

ned by top Garn and top Åre structure maps. This led to a mismatch between gross seismic

isochore and the sum of geological zone isochores. The mismatch was distributed between the

individual zone isochores proportional to the zone thickness within each grid block. Adjustments

of isochores were extrapolated into the fault zones as the second step using non-vertical fault

modelling. [Statoil, 1994a]

74

Figure 4.1: Reservoir zonation [Statoil, 1994a]

The next step was to model the faults. It was done by dividing the fault planes into sections

that followed the reservoir zonation. After that, each subarea of the fault planes needed to

be assigned transmissibility multipliers. These are a function of rock permeability, fault zone

width, matrix permeability (host rock) and dimensions of the grid blocks in the simulation

model. Figure 4.2 illustrates this, and the equation for the transmissibility multiplier is given

below.

75

Figure 4.2: Fault transmissibility, from [Statoil, 2001c]

Average permeability for ow between two neighbour grid blocks:

No fault: knofault =L

12L

k1+

12L

k2

With fault: kwithfault =L

12L

k1+ Lf

kf+

12L

k2

Transmissibility multiplier =kwithfault

knofault

[Statoil, 2001c]

New geological models and simulation models have been made gradually as more and more

information about the eld is available. Results from well 6608/10-4 showed small dierences

from the two other exploration wells and these were also taken into account in the new mod-

els [Statoil, 1995]. In 2005 a new simulation model based on the geological model from 2004 was

created. The new simulation grid was built based on updated fault polygons and new structural

and isochore maps produced in 2004. To generate the grid and ll it with petrophysical prop-

erties, Roxar's Reservoir Modeling System (RMS) was used. The geological model consisted of

20 structural maps, while the simulation model was modied to include 22 layers. To improve

the monitoring of uid and gas ow in the top Ile Formation, and enhance vertical resolution,

renement of Ile 2.2 and Ile 2.1 was performed. The grid consists of 44 431 active cells. [Statoil,

2005c]

Seismic surveys covering the eld were recently used for imaging the eld after reprocessing

the collected data. Pre-stacking and depth migration are important for the data quality. Fault

denitions and intra reservoir interpretation on the eld were improved by use of the seismic data.

New depth maps and reservoir zonation were used in an updated geological model built in 2006.

76

The simulation model was updated thereafter. New structural and isochore maps, produced

in 2006, as well as updated fault polygons will be fundamental for the new simulation model.

Porosity, permeability and net-to gross were imported from the geological model. MULTZ-maps

were also imported from the geological model and used for implementing vertical barriers. The

MULTZ-maps are generated from well- and pressure data. MULTZ-maps include transmissibility

values which are adjusted as part of the history matching process. [Statoil, 2006a]

The amount of initial oil in place is 160.6 MSm3 for the simulation model, compared to 160.8

MSm3 for the geological model. Calculated dierences between these two models are small for

the individual formations and segments as well. [Statoil, 2005c]

Parameters used in the model

Determination of reservoir parameters for use in the model was accomplished after evaluation

of petrophysics. It was found that the two wells 6608/10-2 and 6608/10-3 gave similar values

of porosity, permeability, net sand and water saturation. Therefore, the modelling of these

parameters was simplied and reservoir properties were imported from the geological model. For

the G-segment, separate parameters based on the evaluation of well 6608/10-4 were used. The

rest of the modelling was performed in the same way as for the main structure of Norne. [Statoil,

1995]

Porosity and net-to-gross ratio are modelled as constants for the individual zones. A value

of the average of zone averages for the wells 6608/10-2 and 6608/10-3 are used. Dierent

permeability cut-o values are used in the denition of net sand in the oil and gas zones.

Therefore, separate constants are applied in each of these hydrocarbon zones. To calculate the

porosity grids in the simulation model, the following equation is used.

φ = φ0 + (z0 − z)

where φ is the depth corrected porosity, φ0 the reference porosity, z0 the reference depth

and z the depth at a grid node for a given zone. Porosity is modelled as a function of depth by

use of an empirical porosity gradient of 1 porosity unit reduction per 100 m increase in depth.

Each reservoir zone has individually calculated reference values. Most of the wells are situated

in the central part of the C-segment where the structure is rather at. The reference values are

calculated as the arithmetic average of porosities and zone tops for all wells in this segment.

The above equation is used with relevant depth grid to generate porosity grids for each zone.

When the porosity grid is generated, it is adjusted to match the porosities calculated in the

wells. [Statoil, 2001c] Table 4.2 shows the average porosity and permeability in each zone which

are used in the reservoir model in 2000.

Water saturation is modelled as constant average values for each of the gas zones, based on

the log derived well zone data. The water saturation above OWC is modelled as a function of

height over OWC within the oil zone based on capillary pressure data, constant average porosity

and permeability data for each zone. Adjustments are performed to t the log evaluated water

saturation. [Statoil, 1994a]

77

Table 4.2: Reservoir properties [Statoil, 2001c]Reservoir Porosity Net to gross Permeabilityzone: Fraction Fraction [mD]

Garn3 0.29 0.94 813.9Garn2 0.23 0.86 518.6Garn1 0.18 0.78 44.5Not 0.12 0Ile3.2 0.23 0.89 137.6Ile3.1 0.23 0.92 87.6Ile2.2.2 0.26 0.99 723.9Ile2.2.1 0.28 1 1006.4Ile2.1 0.22 0.8 508.1Ile1 0.27 0.97 793.5

Tofte4 0.23 0.93 108.8Tofte3.4.2 0.31 1 1348.2Tofte3.4.1 0.3 1 1063.7Tofte3.3.2 0.28 1 590.7Tofte3.3.1 0.27 1 375.3Tofte3.2 0.26 1 255.9Tofte3.1 0.26 1 166.7Tofte2 0.22 0.97 58.5Tofte1.2 0.24 0.9 971.6Tofte1.1 0.23 0.89 819.6Tilje4 0.18 0.83 308.7Tilje3 0.24 0.87 555.4Tilje2 0.16 0.72 212.4Tilje1 0.25 0.9 1614.1

78

History matching

A history matching of the production on the Norne Field was performed in 2005. The period

covered is from production start in 1997 to a revision stop August 22th 2004.To assess the reliability and prediction capability of a simulation model, it is possible to

history match the model up to a certain date, and not include all available data. When the

history match is accomplished, a prediction can be made. The prediction is run until the date

of the last available eld data. Then the results from the simulator can be compared to the real

data and the reliability of the history matched model can be assessed. The period from August

2004 to June 2005 was used to compare the real data to the prediction.

The history matching is performed by use of pressures from FMT logs, GOR, water cut and

oil-water contact rise interpreted from 4D data. The transmissibilities of faults and vertical

barriers are adjusted, and some relative permeability curves are changed to provide a better

t. [Statoil, 2005c] To assess and minimize the mismatch between observed and simulated data

in computer-assisted history matching, objective functions are used. Because uncertainties are

weighted and put into the objective function, it is important that they are properly assessed. It

is especially hard to assess the uncertainties in Time-lapse seismics because of the complexity

of data acquisition, survey repeatability, seismic processing and seismic inversion. [Ouair et al.,

2005] The history match has been updated since 2005. The present model is matched until

December 1st 2006.

79

4.2 Description of the base case

The simulation model is divided into two main parts; the history period and the prediction

period. The rst part covers 9 years in great detail, and the second part covers the next 15

years. The CPU times for these models are approximately 4 and 2 hours for the history and

prediction, respectively [Statoil, 2005c]. The next sections will describe these two parts which

compose the base case.

4.2.1 History Period

The simulation base case starts the 6th of November 1997, when production starts in well D-1 H.The model is history matched until the 1st of December 2006. At that time there are 12 activeproducers; B-1 BH, B-2 H, B-3 H, B-4 DH, D-1 CH, D-2 H, D-3 BH, D-4 AH, E-1 H, E-2 AH,

E-3 CH and K-3 H, along with 8 active injectors; C-1 H, C-2 H, C-3 H, C-4 AH, F-1 H, F-2 H,

F-3 H and F-4 H. The last well that started producing was K-3 H which started 15th of October2006. Wells that have been shut down or sidetracked are; B-1 H, B-1 AH, B-4 H, B-4 AH, B-4

BH, B-4 CH, C-4 H, D-1 H, D-1 AH, D-1 BH, D-3 H, D-3 AH, D-4 H, E-2 H, E-3 H, E-3 AH

and E-3 BH.

Injection uids have been both gas and water. The wells on template F have only injected

water while the wells on the C-template have injected both water and gas in an irregular pattern.

How the injection and production strategies have changed since the start up is shown in gure 4.3.

Red illustrates gas, green is oil and blue is water.

Figure 4.3: The drainage strategy for the Norne Field from pre-start and until 2005 [Statoil,2006a]

The base case model is based on the geological model from 2004, which has been updated

both in 2005 and 2006. This model consists of 44 431 active cells, and the eld is divided into 22

layers. Figure 4.4 and 4.5 shows the change in oil saturation in the eld from start of production

until 1st of December 2006.

80

Figure 4.4: Oil saturation applied to the reservoir simulation model seen from above at simulationstart

81

Figure 4.5: Oil saturation applied to the reservoir simulation model seen from above at the endof the history period

82

Plots of base case simulation results and historical values for the history period are shown

in gures 4.6-4.10; where the base case results are shown in blue, while the actual results are

shown in pink.

Figure 4.6: Field Oil Production Rate, History Period

The oil production rate has some discrepancies over the entire simulation time, varying

between higher and lower values than the actual case, see gure 4.6. The match is quite good,

but improvements can be made - especially for the last year.

When total oil production is considered, the errors in the total oil production match is not

of signicance. This is illustrated in gure 4.7. The only discrepancy that should be improved

is the one in 2006, which is the one that inuences the major dierence in the total amount of

oil produced.

There is no record of the actual eld pressure in the simulation model. It is therefore dicult

to make comments on the reliability of the calculated eld pressures. However, as seen from

gure 4.8, the pressure is rst declining, but in mid 1999 the pressure starts to build up again, and

eventually exceeds the initial pressure. This denotes a greater injection volume than production

volume.

83

Figure 4.7: Field Oil Production Total, History Period

Figure 4.8: Field Pressure, History Period

84

Figure 4.9: Field Gas-Oil Ratio, History Period

The gas-oil ratio for the eld lies between 160 and 300 during the entire base case simulation,

see gure 4.9. As for the oil production rate, the match is quite good, but for the gas-oil ratio

the match improves in 2006 when the oil production rate match was rather poor. Due to the

higher oil production rate and the match in as-oil ratio, the gas production rate in the base case

is higher than the actual. The ratio also decreases at this time and is only about 130 Sm3/Sm3.

The eld water cut is steadily increasing over the simulation time of the history period, see

gure 4.10. In the last part, 2006, the actual water cut is higher than the calculated. This is

connected to the discrepancy in the oil production rate. The simulated base case is producing a

higher amount of oil and gas than the historical data, hence decreasing the amount of water it

should be producing and the result is discrepancy in the water cut.

85

Figure 4.10: Field Water Cut, History Period

Total amounts of produced and injected uids per 1st of December 2006 are:

Field Oil Production Total = 73711304 Sm3

Field Gas Production Total = 15.293217 109Sm3

Field Water Production Total = 15642383 Sm3

Field Water Cut = 0.47463846 fracField Gas-Oil Ratio = 205.56699 Sm3/Sm3

Field Water Injection Total = 103.96547 106Sm3

Field Gas Injection Total = 8.6845399 109Sm3

A total oil production of 73711304 Sm3 equals 45.9% of the original oil in place in the

simulation model [Statoil, 2005c]. Another comparison is recoverable reserves calculated by the

Norwegian Petroleum Directorate [NPD, 2008], where the base case production equals 81.9% of

the recoverable oil reserves.

4.2.2 Prediction Period

A prediction has also been made until 1st of January 2022. The drainage strategy for this periodis shown in gure 4.11. The uids produced in the prediction are both oil and gas. As the

pressure in a eld decreases, more of the dissolved gas becomes free gas. Most of the remaining

hydrocarbons on the Norne Field lie in the upper parts of the reservoir, in the Garn and upper

Ile Formations. The injection uid is water and it is injected into the lower Tofte Formation.

During the prediction only water is injected in all wells. All injection wells except F-4 AH

86

Figure 4.11: The drainage strategy for the Norne Field from 2005 and until 2014 [Statoil, 2006a]

inject at constant rates given in table 4.3. The rate in well F-4 AH is under group control,

and it is injecting its share of a group target with a maximum rate of 2500 Sm3/d. Rates for

this well is steadily increasing during the prediction, from 1400 Sm3/d, January 2007, until it

reaches the injection limit in September 2019. The rate is then kept constant at 2500 Sm3/duntil simulation end in January 2022.

Table 4.3: Injection rates during the predictionWell WIRname Sm3/day

C-1H 12000C-2H 12000C-3H 8000C-4AH 12000F-1H 13000F-2H 11000F-3H 13000

Production during the prediction period is controlled by total liquid rate for the templates

and the eld. This results in rates that vary every day during the simulation. New wells that

start producing during the prediction period are shown in table 4.4 along with start date. All

the new wells are mainly oil producers, except for P-20 which is a gas producer perforated in

the Garn 3 and Garn 2 layers. Old wells that are reopened during the prediction are E-1 H, E-2

AH and E-4 AH, all reopened during 2007. No producers are shut during the prediction period.

An illustration of the simulation model and the oil saturation at end of the prediction period

is shown in gure 4.12. The gure shows that the oil saturation has decreased in all layers

previously containing oil. The values are reaching the irreducible oil saturation in multiple

layers.

87

Table 4.4: New production wells during the predictionWell Startname date

K-1H 03.01.2007K-4H 11.06.2007K-2H 04.01.2008P-20 11.01.2014

Figure 4.12: Oil saturation applied to the reservoir simulation model seen from above at the endof the prediction period

88

No historical data is available during the prediction period. On basis of that, no discussion

of the model's reliability with comparisons of simulated results and actual values, are included.

However the performance of the eld can be assessed by studying some plots, see gures 4.13-

4.17.

Figure 4.13: Field Oil Production Rate, Prediction Period

The oil production rate is steadily declining, see gure 4.13, as a consequence of end of

plateau production. A small peak in the rate can be observed in the beginning of 2014. That

might be the result of the new well P-20 that opens the 11th of January 2014.

The total amount of oil produced is also increasing, but not as fast as before, see gure 4.14.

This is due to the decreasing production rates.

From gure 4.15 it can be seen that the reservoir pressure continues to increase during the

rst years of the prediction period. The turning point is in 2014 when the pressure starts to

decline quite fast. It is due to the start-up of the gas producer P-20, which starts to produce

gas from the Garn Formation. The nal reservoir pressure is 234 bar.Field gas-oil ratio is rather constant until the gas producer P-20 starts to produce in 2014,

see gure 4.16. The gas-oil ratio increases rapidly the rst months and continues to increase

until the end of 2018, when it starts to decrease.

The eld water cut is steadily increasing over the entire prediction period. As can be seen

from gure 4.17, there are only a few minor exceptions to this, which is when new wells start to

produce in 2007 and 2014.

89

Figure 4.14: Field Oil Production Total, Prediction Period

Figure 4.15: Field Pressure, Prediction Period

90

Figure 4.16: Field Gas-Oil Ratio, Prediction Period

Figure 4.17: Field Water Cut, Prediction Period

91

Total amounts of produced and injected uids per 1st of January 2022 are:

Field Oil Production Total = 100.43956 106Sm3

Field Gas Production Total = 25.503697 109Sm3

Field Water Production Total = 162.8764 106Sm3

Field Water Cut = 0.94593531 fracField Gas-Oil Ratio = 701.75629 Sm3/Sm3

Field Water Injection Total = 294.80131 106Sm3

Field Gas Injection Total = 8.6845399 109Sm3

The total oil production of 100.43956 106Sm3 equals 62.5% of the original oil in place in

the simulation model [Statoil, 2005c]. It exceeds the recoverable reserves calculated by the

Norwegian Petroleum Directorate [NPD, 2008] by more than 10 106Sm3.

92

4.3 Eclipse reservoir simulator

In order to run numerical simulations on a reservoir model, a simulator is needed. Reservoir

simulations divides the reservoir into a number of small blocks and applies the fundamental

equations of uid ow through porous media, phase behaviour and conservation to each block.

The result is display of variations in reservoir rock and uid parameters in space and time. The

numerical work involved in actual simulation problems is very large and requires the use of high

speed computers. For the Norne Field base case, the Eclipse reservoir simulator has been used.

This simulator consists of two separate simulators; Eclipse 100 and Eclipse 300 specializing in

black oil modelling and compositional modelling, respectively.

For the Norne Field, Eclipse 100 is used. It is a fully implicit, general purpose black oil simu-

lator that can handle up to three phases in three dimensions. It also has a gas condensate option.

Eclipse is written in FORTRAN and will run on any computer that has an ANSI-standard FOR-

TRAN90 compiler and sucient memory, or it can be run in a parallel mode [Sch, 2007b]. Other

important options available in Eclipse are corner-point versus block-center geometry and radial

versus cartesian coordinate systems [NTNU, 2007].

An input le is needed to be able to run a simulation. This le must contain all data

concerning the reservoir and how it is exploited. A special name format has to be used for

the Eclipse input le, namely FILENAME.DATA. The input le is constructed using certain

keywords used in the right order. There are eight main sections that can be included in the input

le. These are given by the section-header keywords runspec, grid, edit, props, regions,

solution, summary and schedule, where all are mandatory except for grid, regions and

summary. Each of these sections is followed by multiple keywords, where some are required

while others are optional. They will be thoroughly described in the next section, by use of the

Eclipse Reference Manual, reference [Sch, 2007a].

The Norne input les are included on a CD, because of the enormous amount of data.

However, the .DATA le is attached in appendix D as a sample.

93

4.4 Section Keywords

4.4.1 runspec

The runspec section is required as the rst section of an Eclipse data input le. It includes

title, start date, problem dimensions, switches, phases/components present etc.

Several keywords are introduced in the runspec section. These turn on various modelling

options or contain data. The set of runspec keywords included in the Norne le will be

presented below.

Keywords in the RUNSPEC section

The dimens keyword denes the number of blocks in X, Y and Z directions. The numbers for

the Norne eld are 46, 112 and 22.

The gridopts keyword requests additional options for processing the grid data. It is followed

by two items; the rst allows the alternative transmissibility multipliersmultx-, multy-,multz-

etc. to be used in the grid, edit or schedule sections. The keyword is also used if the

alternative diusivity multipliers diffmx-, diffmy-, diffmz- etc. are used. When YES is

typed as item 1, keywords as multx-, diffmx- etc. may be used. Item 2, nrmult, is the

maximum number of multnum regions entered in the grid section. This apply either to inter-

region transmissibility multipliers, using the multregt keyword, or pore volume multipliers

using the multregp keyword. This item is set to zero in the Norne le, which means that any

multiplier is applied between ux regions entered using fluxnum, see section 4.4.2.

The active phases present in the runs are dened by typing their names. The Norne Field

has oil, water, gas, disgas and vapoil included. These words represents oil, water, gas,

dissolved gas and vaporized oil in wet gas.

Unit convention in the le is dened as eld, metric or lab units. The Eclipse le of Norne

uses metric units.

The hysteresis option is enabled by use of the hyst keyword. If the hyst keyword is selected,

imbnum values must be entered in the regions section.

The start date of simulation is entered after the start keyword. The start of the Norne run is

November 6th 1997. eqldims consists of three items and species the dimensions of equilibration

tables. The rst item, ntequl denes the number of equilibration regions entered by use of

eqlnum in the regions section, see section 4.4.5. 5 regions are established in the Norne

case. The second item gives the number of depth nodes in any table of pressure versus depth

constructed internally by the equilibration algorithm. The number entered here is 100. Finally,

the maximum number of depth nodes, which is 20, in any rsvd, rvvd, rswvd, rtempvd,

pbvd or pdvd table entered in the solution section to dene the initial Rs, Rv, Tr, Pb or Pdversus depth is typed.

eqlopts denes several options for equilibration. The keyword is followed by one item in the

Norne Eclipse le. This is thpres which enables the threshold pressure option. When thpres

is entered, ow will be prevented from occurring between dierent equilibration regions until

94

the potential dierence exceeds a threshold value. The threshold value is to be specied with

the keyword thpres in the solution section. Also, if named faults have threshold pressures,

the option is required.

Dimension data of regions are entered under the regdims keyword. The data consists of

4 items in the Norne case, and these describe the maximum number of regions associated with

miscellaneous keywords in other sections. An illustration of how it is done is show below. Item

1, which is 22, is the maximum number of uid-in-place regions (NTFIP) dened with keyword

fipnum in the regions section, see section 4.4.5. Item 2 (NMFIPR) is the number of sets of

uid-in-place regions. 3 sets are present. Item 3 (NRFREG) denes the maximum number of

independent reservoir regions. This option is set to 0 for Norne. The nal item (NTFREG)

gives maximum number of ux regions for the Flux option, or the maximum number of regions

used by the fluxnum keyword in the grid section, see section 4.4.2. 20 ux regions is the

maximum number for Norne.

Tracer dimensions and options are introduced in the runspec section. The tracers are

described and options for the tracer tracking algorithm are included here. The tracers keyword

is followed by up to six items, but only one is included for the Norne case. This is the maximum

number of passive water tracers entered using tracer in the props section, section 4.4.4. 10

water tracers are the maximum amount in the Norne case.

Well dimensions are given under the keyword welldims. The data can consist of up to 10

items, but for the wells in the Norne eld only 4 items are used to describe the dimensions of

the well data to be used in the run. The entered numbers in the Norne le are as follows; the

maximum number of wells in the model is 130, the maximum number of connections per well

is 36, the maximum number of groups in the model is 15 and the maximum number of wells in

any group is 84.

Dimensions of tables are dened by use of the tabdims keyword as shown in the gure

below. The data describes the sizes of saturation and PVT tables, and the number of uid-in-

place regions used in the run. The Norne le uses 6 items to describe table dimensions. Item

1 gives the number of saturation tables in the props section, which is 107. Item 2 denes the

number of PVT tables in the props section. There are 2 such tables in the BC0407.DATA le.

Maximum number of saturation nodes in any saturation table is given as item 3, and the number

is 33. Item 4 is the maximum number of pressure nodes in any PVT table or rock compaction

table. 60 pressure nodes are the maximum in the Norne le. Item 5 gives the maximum number

of FIP regions given in the regions section under the fipnum keyword, see section 4.4.5. 16

such regions are the maximum here. The last item denes the maximum number of Rs nodes in

a live oil PVT table or Rv nodes in a wet gas PVT table, which is 60 for the Norne eld.

The vfpidims keyword denes injection well VFP table dimensions. The data consists of

95

three items and describes the dimensions of the injection well Vertical Flow Performance tables

entered in the schedule section using the vfpinj keyword. Item 1 is the maximum number

of ow values per table. Item 2 is the maximum number of tubing head pressure values per

table, while item 3 gives the maximum number of injection well VFP tables. The numbers are

respectively 30, 20 and 20 for Norne.

As for the injection wells, the VFP table dimensions must be described for the production

wells. This is done by use of the vfppdims keyword. The data consists of six items. These

are as follows; 1: The maximum number of ow values per table, 2: The maximum number of

tubing head pressure values per table, 3: The maximum number of water fraction values per

table, 4: The maximum number of gas fraction values per table, 5: The maximum number of

articial lift quantities per table and 6: The maximum number of production well VFP tables.

Numbers used for Norne are shown below.

Dimensions for fault data are specied by use of the faultdim keyword. One single item of

data denes the maximum number of segments of fault data entered in the grid section with

the faults keyword, see section 4.4.2. Maximum number of fault segments is 10000 here.

The pimtdims keyword is used to describe the number of tables of PI scaling factor versus

maximum water cut entered in the pitmultab keyword, and the maximum number of entries

in any table. The two integers for the Norne case are 1 and 51.

The nstack data represents the size of the stack of previous search directions held by the

ORTHOMIN linear solver. By increasing the value of nstack, the memory required for a run

is increased as well. The stack size is 30 in the Norne case.

The keywords unifin and unifout indicate that input les and output les, which can be

multiple or unied, are to be unied.

The option keyword activates special program options. The options are principally of a

temporary or experimental nature. They can also act to restore back-compatibility with earlier

versions of the code. The option keyword is followed by a number of integers. Each of these

activates a special option. A value equal to zero switches o the special option, while a value

other than zero activates a special option. In the Norne Eclipse le, there are 77 integers which

are set equal to 1. These 77 options are described in detail in the Eclipse Reference Manual[Sch,

2007a].

96

4.4.2 grid

The purpose of the grid section in the BC0407.DATA le is to specify the geometry of the

computational grid, and to set rock properties for the grid blocks in the grid. Based on this

information, Eclipse calculates grid block mid-point depths, pore volumes and inter block trans-

missibilities.

The system in the Norne le is of cartesian geometry and the keywords used in this section

depends on the geometry option.

All keywords used in this section are described in the following.

Keywords in the grid section

When the keyword newtran is set it means that the transmissibilities are calculated from the

cell corner points. It also enables automatic calculation of fault transmissibilities.

The gridfile keyword is used to control the output of the geometry. It is followed by one

or two integers. The rst integer denes whether a .GRID le is to be written and the extension

of this, while the second integer denes the .EGRID le which is to be written and what format

it should have. In this case both extended .GRID and .EGRID les are written.

The keyword mapaxes is used to enable storage of the origin of the maps used to generate

the grid. For post-processing purposes, the origin is available through the .GRID le. The

number of items following the keyword is six, consisting of three pairs of coordinates. The rst

pair gives the coordinates of one point of the grid y-axis relative to the map, the second gives

the coordinates of the grid origin relative to the map origin, and nally the coordinates of one

point of the grid x-axis relative to the map. For this case the values are 0 100 0 0 100 0.

To specify the grid data units, the gridunit keyword is used. The keyword is followed by

two items where the rst states the unit of length of the grid data, while the second indicates the

relation of the measured grid data. The second item is set to MAP if the grid data is measured

relative to the map, or is left blank if it is relative to the origin given in the mapaxes keyword.

In the Norne case the grid data units are given in meters and are relative to the origin given by

the mapaxes keyword.

The init keyword requests that an .INIT le should be created and outputted. Such a le

contains a summary of all the data entered in the grid, props and regions sections. An .INIT

le can be either formatted or unformatted. The later is the case here.

If there is a desire to reset print and/or stop limits for messages of any severity type, the

messages keyword is used. There are 6 levels of severity in Eclipse from the informative

MESSAGE, to the suspected programming error printed as a BUG. The rst 6 items following

the messages keyword resets the print limit for each of the severity levels, while the last 6

items resets the stop limits for each of the severity levels. For this case all of the print limits,

and the stop limits for the two least severe messages is set to 10000, while the stop limits for a

WARNING, PROBLEM, ERROR and BUG are 20000, 10000, 1000 and 1, respectively.

To activate the minimum pore volume a cell has, the minpv keyword is used. It is followed

by a single, positive number which is the minimum pore volume of an active cell. For the Norne

97

Field the minimum pore volume for an active cell is 500.

A pinch-out is when a layer of rock is terminated by thinning or tapering out against another

type of rock [Schlumberger Oileld Glossary]. To generate connections across such pinched-out

layers the pinch keyword is used. It can be followed by up to ve items. The rst item states the

pinchout threshold thickness, while the second item controls the generation of pinchouts when a

minimum pore volume has been set by the minpv keyword. As a third item, the maximum empty

gap allowed between cells in adjacent grid layers where non-zero transmissibility is wanted, is

set. The fourth item states in which way the pinchout transmissibilities should be calculated.

It can be done either by using harmonic average of the z-direction transmissibilities of all cells

nearby (ALL), or only by half-cell z-direction transmissibilities of active cells on each side of

the pinchout (TOPBOT). The nal item is used to account for multz through a pinched-out

column, but is only used if the fourth item is set to TOPBOT. The transmissibility multiplier

that will be used can be the multz (TOP) or the minimum of this value for the active cells

at the top of the pinchout (ALL). For the Norne simulation model the treshold thickness is set

to 0.001 m. The generation of pinchouts is set to GAP which indicates that non-neighbouring

connections are allowed across cells that are inactive even if the thickness exceeds the treshold.

As maximum empty gap in item 3 the value is set to innity, 100* 1018. The last two items are

set to TOPBOT and TOP, respectively.

To reduce the amount of print-outs from a run or to avoid the out-put of large included les

the keyword noecho can be used. Here it is used to avoid the print-out of all the included les

into the .PRT le.

Dening the grid In the Norne case Corner Point geometry is used. It requires that all the

corner point are given, but there is no requirement for the corner angles to be right.

This model consists of 46x112x22 grid blocks in the x-, y- and z-direction, respectively.

The coordinate system that denes the grid is given in UTM, Universal Transverse Mercator,

coordinate system for the x and y coordinates and depth in meters for the z coordinates.

The grid is dened in the IRAP_1005.GRDECL le. The rst keyword in this le is the

specgrid keyword. This keyword repeats the specication of dimensions, number of reservoirs

and type of coordinates dened in the runspec section, it is an optional keyword used only

to control the settings. The rst item is the number of grid blocks in the x-direction, second

the number of grid blocks in the y-direction and thirdly comes the number of grid blocks in

the z-direction. Item number four and ve are number of reservoirs and type of coordinates,

respectively. The coordinate type is either cylindrical (T) or cartesian (F). For the Norne Field

the values are as follows; 46 112 22 1 F.

The next step is to dene coordinate lines between two points, which is done under the

coord keyword, see gure below. These lines dene possible positions for the grid block corner

points. The depth of each corner point is given in the same le under the zcorn keyword,

see gure below. With this information the x- and y-coordinates for the corner points can be

calculated, hence specifying all the grid blocks in the model.

98

Active cells

The entire model consists of 113344 cells, where 44431 are active cells. To dene active cells,

integers 0 or 1 are used for each cell in the ACTNUM_0704.prop le under the actnum keyword.

Active cells are assigned the value 1, while the inactive cells are assigned the value 0. Grid blocks

are ordered with the index for the X-axis cycling fastest, and then followed by the Y- and Z-

axis, respectively. Starting with block (1,1,1) moving to block (2,1,1) then, for a 2x2x2 system,

moving on to (1,2,1) and (2,2,1) before moving to (1,1,2), (2,1,2), (1,2,2) and nally (2,2,2).

Faults

The faults are dened in the FAULT_JUN_05.INC le under the faults keyword. First the

fault name is given. Then the position of the fault, which grid blocks it is connected to, by giving

the lower and upper I-, J- and K-values of the grid blocks. Finally the face of the fault, which

states what side of the grid block the fault is connected to, is dened. It is done by entering the

name of the face X, Y or Z or the corresponding negative face.

To set the transmissibility of the fault the keyword multflt is used. This keyword is

presented in the FAULTMULT_AUG-2006.INC input le. It is followed by the fault name and

the corresponding transmissibility multiplier. The multiplier in this eld ranges from 0.00075 to

20, where a low multiplier seals the fault.

Porosity The porosity is imported from the geological model and is calculated for each grid

block in the model.

The porosity is included in the Eclipse le with keyword poro in the PORO_0704.prop le.

A part of the included porosity le can be seen below.

99

Net-to-gross Net-to-Gross Ratios are dened in the grid section with the keyword ntg.

Net-to-gross values are calculated for each reservoir zone.

The ntg keyword is followed by a non-negative real number for every grid block, as a

fraction. Gross thickness is the thickness of the rock between top and bottom. The amount of

gross thickness that is of reservoir quality is called Net thickness. To convert from gross to net

thicknesses the values specied in the le NTG_0704.prop are used. These converted values

act as multipliers of grid block pore volume and transmissibilities in the X and Y directions.

In addition, the values are used on DZ for the calculation of well connection transmissibility

factors. The ntg keyword with input data from the Norne le can be seen below.

The grid blocks are ordered with the X-axis index cycling fastest, followed by the Y- and

Z-axis indices.

Permeability Permeability is dened under the keywords permx, permy and permz in the

PERM_0704.prop le. The values are calculated for each reservoir zone. The permeability is

an arithmetic average of the permeability in the net sand interval. [Statoil, 2001c]

permx species the permeability values in the X-direction as shown in the gure below. All

values for Y- and Z-direction are copied from the permx array under the copy keyword.

In addition, equals and multiply keywords are used to specify the permeability for the

various segments, wells and layers. By using equals, the array is set to a constant in the

current box. The rst item after the keyword denes the name of the array to be modied, the

second item states the constant to be assigned to the array specied by item 1. Items 3-8 are

used to redene the input box for this and subsequent operation within the current keyword.

Item 3 points out the number of the rst block that is modied on the X axis, while item 4

declare the last modied block on the X-axis. Item 5 and 6 denes the same on the Y axis, and

subsequent item 7 and 8 are doing the same for the Z-axis. multiply have identical method of

use as equals, but now the array is being multiplied by item 2. The next gures show how this

is done.

100

Transmissibilities between layers To dene the transmissibility in the z-direction between

the grid blocks, a le with multipliers is created. This le, MULTZ_HM_1.INC, consists of

the multz keyword followed by one number for each grid block. In this case the numbers are

mainly ones and zeroes. For some areas the transmissibility in the z-direction has been altered

as part of history match studies. The altered le is called MULTZ_JUN_05_MOD.INC. In

this le the equals keyword is used to alter some of the multz or transmissibilities between

certain layers. There the rst value is the array to be modied, in this case the multz, next is

the new value and nally the X-, Y- and Z-ranges of the grid blocks.

Flux regions and transmissibilities The FLUXNUM_0704.prop le is used to dene re-

gions in the model. Each cell is given an integer from 0-20 under the fluxnum keyword. 1 is

default, see gure below. These 20 regions can acquire dierent properties independent of the

other regions. A region can also be run separately from the entire model using ux boundaries.

In the Norne Field there has been dened four regions for each geological layer; Garn, Ile, Tofte,

Tilje-top and Tilje-bottom. The regions are C, D, E and G, where the rst three belong to

the main structure, while the G region belongs to the smaller structure north-east of the main

structure.

Transmissibilities between neighbouring regions can also be dened. In Eclipse this is carried

out by using the multregt keyword. The le MULTREGT_D_27.prop contains the speci-

cation of this, by rst setting the region number to start from, then the region number of the

last region. Finally the transmissibility multiplier that is to be used between these two regions

is set. This is given in table 4.5.

101

Table4.5:

Tansm

issibilitiesbetweenregions,from

includeleMULT

REGT_D_27.prop

Garn

Ile

Tofte

Tilje4&

3Tilje2&

1F orm

ation

CD

EG

CD

EG

CD

EG

CD

EG

CD

EG

Segm

ent

12

34

56

78

910

1112

1314

1516

1718

1920

Fluxnum

FLUX

11

10.005

00

00

00

00

00

00

00

00

1C

Garn

FLUX

11

10

00

00

00

00

00

00

00

02

DFLUX

11

00

00

00

00

00

00

00

00

3E

FLUX

10

00

00

00

00

00

00

00

04

GFLUX

11

10.01

11

11

0.1

0.1

0.1

0.01

00

00

5C

Ile

FLUX

10.05

11

11

10.1

10.1

0.1

00

00

6D

FLUX

11

11

11

0.1

0.1

0.1

0.1

00

00

7E

FLUX

11

11

10.1

0.1

0.1

0.1

00

00

8G

FLUX

11

10.01

11

11

0.001

00

09

CTofte

FLUX

11

11

11

10

10

010

DFLUX

11

11

11

00

0.001

011

EFLUX

11

11

10

00

112

GFLUX

11

10.01

0.0008

00

013

CTilje4&

3FLUX

11

10

0.1

1*10−

60

14D

FLUX

11

00

0.05

015

EFLUX

10

00

0.001

16G

FLUX

11

10.1

17C

Tilje2&

1FLUX

11

118

DFLUX

11

19E

FLUX

120

G

102

4.4.3 edit

The edit section includes instructions for modications to calculated pore volumes, grid block

centre depths, transmissibilities, diusivities and non-neighbour connections computed by the

program from data in the grid section.

Keywords in the edit section

In the Norne case, modications in the edit section are connected to transmissibilities for dierent

wells and faults. The keywords to overwrite transmissibility array values used are tranx and

trany. These keywords are used through the operational keywords multiply and equals.

tranx and trany are the transmissibility for the current input box in respectively X and Y-

directions. An example is shown in gure below.

4.4.4 props

The props section contains input of uid properties and relative permeability of the reservoir.

Multi-tabular keywords are used, and only one entry of any keyword is accepted. The runspec

section of the le has specied which tables that are needed and the maximum size of these.

The correct length and number of tables must be provided.

Keywords in the PROPS section

The noecho keyword is disabling the echo of the data input, see explanation in section 4.4.2.

PVT and rock properties PVT properties are given by use of the PVT keywords, and are

included in the le called PVT-WET-GAS.DATA. Two PVT regions are present in the model.

Region 1 includes the C-, D- and E-segments, while region 2 consists of the G-segment.

pvtg denes tables with PVT properties of wet gas. Item 1 gives the gas phase pressure

Pg given in bar, item 2 is the vaporized oil-gas ratio for saturated gas at pressure Pg. The gas

formation volume factor for saturated gas at Pg is item 3 and the last item gives the gas viscosity

for saturated gas at Pg in centipoise(cP). The gure below shows how this is done.

103

The pvto keyword is used for PVT properties of live oil. The data is given as 4 numbers.

The rst number is the dissolved gas-oil ratio, Rs. The second is the bubble point pressure, Pbubfor oil with dissolved gas-oil ratio given by Rs. The oil formation volume factor for saturated

oil at Pbub is entered in place 3, while the oil viscosity for saturated oil at Pbub is given as item

4. A part of the input le can be seen below.

Water PVT functions are given by use of the pvtw keyword. Item 1 gives reference pressure

Pref for items 2 and 4, thereafter the water formation volume factor, Bw at reference pressure

(Pref ) is dened. Water compressibility is the third item, and water viscosity at reference

pressure the fourth. The last item includes the water "viscosibility" which is zero in the Norne

case. A part of the input le can be seen below.

The rock keyword denes the compressibility of the rock for each pressure table region.

Each record can consist of 6 items of data, but in the Norne le there are only two items. The

rst is the reference pressure (Pref ) and the second the rock compressibility.

Surface densities of the reservoir uids for the two PVT regions are given under the density

keyword. Three numbers are used, respectively values for oil, water and gas densities.

Set up of tracers are done by use of the tracer keyword as shown below. Each tracer is

associated with a particular uid used in the run. The keyword is followed by one line for each

tracer, which includes the name of the tracer and the name of the uid connected to the tracer.

7 tracers are introduced in the Norne le; all of these have water as uid.

Relative Permeability and Capillary Pressure The swof_mod4Gseg_aug-2006.inc le

contains data for oil-water imbibition curves. Drainage curves are equal to imbibition curves.

The swof keyword is used in runs where both oil and water is present as active phases. It is

applied by including tables containing the following 4 columns; water saturation, water relative

permeability, oil-in-water relative permeability and water-oil capillary pressure. The rst value

104

in column 1 is interpreted as the connate water saturation, while the last value is interpreted as

Sw=1-Sor. Two dierent relative permeability curves are included for the oil-water system; one

for the Tofte Formation, and one for the remaining formations. A part of the le is show below.

The gas-oil drainage curves are dened in the sgof_sgc10_mod4Gseg_aug-2006.inc le where

the keyword is sgof and includes gas-oil saturation functions versus gas saturation. Each table

consists of 4 columns where column 1 is the gas saturation, column 2 the corresponding gas

relative permeability, column 3 the corresponding oil relative permeability and the last column

the corresponding oil-gas capillary pressure.

WAG hysteresis model Wag hysteresis parameters model is activated by using thewaghystr

keyword in the waghystr_mod4Gseg_aug-2006.inc le. This enables a better modelling of the

WAG injectors. The required data for the model is presented here. The keyword is followed

by 8 items of data. Item 1 is Land's parameter, C, and governs the trapped gas saturation on

imbibition and the shape of the imbibition curve. The following equation is used:

Sgtrap = Sgcr +(Sgm − Sgcr)

(1 + C ∗ (Sgm − Sgcr))

where

Sgtrap is the trapped gas saturation, Sgm is the maximum gas saturation attained and Sgcr is

the critical gas saturation.

Item 2 is the secondary drainage reduction factor, α. The third item is the gas model ag,

where YES indicates that WAG Hysteresis Model for the gas phase relative permeability is used,

while NO means that the WAG Model is turned o and drainage curves are used instead. In the

Norne case, WAG Model is used. The fourth item is the residual oil ag. If modication of the

residual oil in the STONE 1 3-phase oil relative permeability model is needed, YES indicates

that trapped gas saturation will be used for this. NO will not modify the oil relative permeability

this is the case for the Norne simulation. Item 5, called water model ag has YES and NO as

options. If YES is typed the WAG Hysteresis Wetting Model is applied to the water phase,

while NO indicates that the WAG hysteresis model is not applied. The WAG hysteresis model

is not applied for the Norne case. Item 6 has the number 0.1 which is the imbibition curve

linear fraction. This is the fraction of the curve between Sgm and Sgtrap that uses a linear

transformation. 3-phase model threshold saturation is given in item 7 as 0.1. The nal item

gives the residual oil modication fraction as 0.0. A part of the input le can be seen in the

gure below.

105

4.4.5 regions

Reservoirs can have dened dierent regions with certain, common properties; for instance

uid in place, saturation table number, imbibition saturation function number, PVT data or

equilibration. The regions section divides the computational grid into such regions.

Keywords in the regions section

Fluid-in-place regions Fluid-in-place regions are dened by use of fipnum keyword. Each

grid block is given a region number, see gure below. All grid blocks in the same region share the

same initial uid in place volumes/saturations. For the Norne Field there are 16 dierent regions

dened in FIPNUM_0704.prop. The uids in place for these regions are given in table 4.6.

Additional Fluid-in-place regions As an addition to the Fluid-in-place regions dened un-

der the fipnum keyword, Fluid-in-place regions based on the geological- and numerical layers

are dened. The keywords used are fipgl and fipnl for geological and numerical layers respec-

tively. How the formations are divided into the fipgl and fipnl regions are shown in tables 4.7

and 4.8.

106

Table4.6:

Fluid-in-placeforeach

region

from

includeleBC0407.PRT

Region

OOIP

[Sm

3]

OOIP

[Sm

3]

OOIP

[Sm

3]

WOIP

[Sm

3]

GOIP

[Sm

3]

GOIP

[Sm

3]

GOIP

[Sm

3]

Pressure

Porevolume

number:

Liquid

Vapor

Total

Total

Free

Dissolved

Total

[barsa]

[Rm

3]

15357744

311330

5669074

11495451

5426677329

591643401

6018320730

268.94

44732385

23229039

88235

3317273

3087927

1534993705

362558460

1897552164

269.03

14752345

32280208

60909

2341116

13980845

1049854062

256698501

1306552563

269.64

22490709

45279750

1062

5280812

7625996

19474906

497484252

516959158

267.68

14729288

541754724

89346

41844070

22392417

1549276984

4587679020

6136956005

270.87

85477884

611111392

6308

11117700

4241475

109292523

1215300430

1324592952

271.26

19512663

710874378

3068

10877446

13886905

53139636

1182176434

1235316070

272.23

28917966

80

00

9038812

00

0274.66

9384376

947567775

047567775

45677106

05109706183

5109706183

273.78

109569600

1014007759

014007759

9657870

01503314643

1503314643

273.89

28325189

1111412025

011412025

33667931

01223933869

1223933869

274.12

49835664

120

00

30552206

00

0275.23

31718517

134818368

04818368

112636220

0514599558

514599558

275.37

123139730

141427140

01427140

25011391

0152394634

152394634

275.62

27813651

151136787

01136787

49097756

0121386548

121386548

275.52

52405951

160

00

9966663

00

0280.08

10342360

107

Table 4.7: Numerical layers from include le EXTRA_REG.incNumerical

Region number layer number Formation name

1 1 Garn 32 2 Garn 23 3 Garn 14 4 Not5 5 Ile 2.26 6 Ile 2.1.37 7 Ile 2.1.28 8 Ile 2.1.19 9 Ile 1.310 10 Ile 1.211 11 Ile 1.112 12 Tofte 2.213 13 Tofte 2.1.314 14 Tofte 2.1.215 15 Tofte 2.1.116 16 Tofte 1.2.217 17 Tofte 1.2.118 18 Tofte 1.119 19 Tilje 420 20 Tilje 321 21 Tilje 222 22 Tilje 1

Table 4.8: Geological layers from include le EXTRA_REG.incFrom numerical To numerical

Region number layer number layer number Formation name

1 1 3 Garn2 4 4 Not3 5 5 Ile 2.24 6 8 Ile 2.15 9 11 Ile 16 12 12 Tofte 2.27 13 15 Tofte 2.18 16 18 Tofte 19 19 22 Tilje

108

Saturation function regions The saturation function regions are dened in the same way as

the uid-in-place regions. It is done in the SATNUM_0704.prop le under the satnum keyword,

by assigning one integer for each grid block, see the gure below. This number states which

saturation region the grid block is a part of. All grid blocks in a saturation function region

use the same saturation function to calculate the relative permeabilities for all the grid blocks

belonging to that region. The saturation functions have already been dened as described in

section 4.4.4.

Imbibition saturation function regions Another set of regions that has to be dened, is the

imbibition saturation function regions, imbnum. Saturation functions for the imbibition process

are needed because this is a hysteresis case. It is dened in the le IMBNUM_0704.prop. As for

the preceding region types a grid block is assigned to a region by dening one integer for each

grid block under the imbnum keyword, see gure below. The imbibition saturation function is

used to calculate the relative permeability and the capillary pressure for the grid block. If the

imbibition saturation function region number is equal to the saturation function region number

the hysteresis model is turned of for that grid block.

PVT regions The PVT regions are dened in the le PVTNUM_0704.prop under the pvt-

num keyword. Here every grid block is assigned an integer that species what PVT region it

belongs to, see gure below. The region number states which set of PVT tables that should be

used to calculate the PVT properties for the uid in that grid block.

Equilibration regions The nal set of regions dened are the equilibration regions, eqlnum.

These are dened in the EQLNUM_0704.prop le under the eqlnum keyword, by assigning

109

one integer to each grid block, see the gure below. All grid blocks in a PVT region must also

be part of the same Equilibration region.

4.4.6 solution

This section contains sucient data for dening the initial state of every grid block in the

reservoir. Pressure, saturations and compositions are described.

Keywords in the solution section

The rptrst keyword controls the output of data to the restart le. It is set to print a basic

restart le of type 2, which means that the restart les are created at every report time until

this switch is reset, and all are kept.

The rptsol keyword controls the output of the solution section data to the print le.

The mnemonic here is fip=3, which denotes that initial uid in place are reported for all sets

of uid in place regions dened with the fip keyword.

Equilibrium data specication Equilibrium data is included from the E3.prop le. The

keyword equil sets the contacts and pressures for conventional hydrostatic equilibrium. Each

record contains 9 items of data and refers to a separate equilibration region, see section 4.4.5,

from 1 to ntequl. ntequl is the rst item connected to the keyword eqldims, see section 4.4.1

and sets the number of equilibration regions. In the Norne case, this value is 5. Item 1 of the

equil keyword contains the datum depth. Item 2 gives the pressure at the datum depth. The

next number is the depth of the oil-water contact, followed by the oil-water capillary pressure

at this depth. Item 5 gives the depth of the gas-oil contact, and item 6 the gas-oil capillary

pressure at this depth. Item 7 includes an integer which selects the type of initialization of live

black oil. A positive integer, as in E3.prop, causes the dissolved gas concentration in under-

saturated oil to be calculated from Rs versus depth table, which is entered by use of keyword

rsvd. Item 8 is zero in the Norne case. The result of this is that the vaporized oil concentration

in under-saturated gas is set equal to the saturated Rv (vaporized oil-gas ratio) value at the

gas-oil contact. This is subject to an upper limit that is equal to the saturated Rv value at local

pressure. Item 9 is an integer that denes the accuracy of the initial uids in place calculation.

The integer in E3.prop is zero, which causes the simulator to set the uid saturation in each grid

block according to the conditions at the center of the block. A steady-state solution is produced,

but the uids in place will not be accurate if a uid-contact passes near the center of a large

grid block. An example from the le is shown in gure below.

110

A rsvd table (Rs versus depth) comprises ntequl tables of dissolved gas-oil ratio versus

depth. The rsvd table has two columns; depth and the corresponding value of Rs (the dissolved

gas-oil ratio), as shown in the gure below.

Threshold pressures for ow between adjacent equilibration regions are set with the thpres

keyword. The threshold pressure switch thpres is set in the runspec section. Item 1 denes

the equilibration region number the ow goes from (region I), while item 2 is the equilibration

region number the ow goes to (region J). Item 3 is the threshold pressure for ow from region

I to region J. The gure below shows how this is done.

tvdp keywords are used to specify the depth tables to be used for initializing the concentra-

tion of a tracer in each grid block. The keyword to be used is a concatenated name that consists

of several segments. The rst 4 characters must be the string tvdp, and character 5 the letter

F or S. F is used in the Norne case and means that the associated stock tank phase of the tracer

only exists in the free state. The last characters are the name of the tracer that is initialized.

Each table includes the depth values and the corresponding initial tracer concentration values.

All injected tracers are initialized to zero. An example can be seen in the gure below.

4.4.7 summary

The summary section denes which variables that is to be written to the summary les after

each time step of the simulation.

Keywords in the summary section

The summary section for the Norne Field consists of ve dierent include-les. The rst is

called summary.data and this le includes a number of keywords to enable dierent variables to

111

be written to summary les. The variables that may be written are oil, water, gas and liquid

ows for wells and groups including production and injection rates, production and injection

cumulatives. The summary.data le also consists of keywords used to write well data, region

data, group data, tracer data etc.

The extra.inc le consists of additional keywords for print-outs as well and group modes,

well list quantities, grid block quantities, region quantities etc.

Tracer data is written to the summary le by use of dierent keywords in the tracer.data le,

which is included under the summary section keyword. Field data and well data for producers

and injectors are written for tracers.

The gas.inc le gives output of for instance grid block and region oil, gas and water quantities.

The wpave.inc le consists of two keywords for output of well pressures. These are wbp5

and wbp9.

4.4.8 schedule

Operations to be simulated and the times at which output reports are required, are specied

in the schedule section. In addition, vertical ow performance curves and simulator tuning

parameters can be specied in this section.

Keywords in the schedule section

Denition of a well and its connection properties and controls are done by use of the keywords

welspecs, compdat, wconprod, wconinje and wconhist. The rst keyword is used to

introduce the well and the second to specify its completion data. The third keyword represents

production controls if the well is a producer, the fourth injection control if the well is an injector.

Measured ows and pressures for history matching producer are given in the fth item. The use

of these keywords is shown below.

These are included in the BC0407.SCH-le at the end of the BC0407.DATA le for both

history and prediction

Other schedule section keywords used are; gruptree, wpave, grupnet, vappars, net-

balan, dates and gecon.

gruptree is required when there is a grouping structure with more than three levels in

the hierarchy; eld-group-wells. The keyword sets up this tree structure for multi-level group

control. The keyword is followed by the name of the child group and the name of its parent

group, see illustration below.

wpave controls the calculation of well block average pressure. The keyword has 4 items

of data which are; Item 1: the weighting factor between the inner block and the outer ring of

112

neighbouring blocks, in the connection factor weighted average, see gure below. The value is

1.0 in the Norne case. This means that total weighting is given to the inner blocks that contain

well connections. Item 2: Weighting factor between the connection factors weighted average and

the pore volume weighted average. 0.0 is the given value in the Norne le, and gives a purely

pore volume weighted average. Item 3: Depth correction ag, which controls how grid block

pressures are corrected to the well's bottom hole reference depth. well is used here and means

that the density of the uid in the wellbore at well connections is used when hydrostatic head is

calculated. Item 4: The well connection ag that says that the grid blocks associated with all

well connections contribute to the average pressure.

grupnet denes the standard production network structure. A number of records are

connected to this keyword. An illustration of how it is done in the Norne le is shown below.

The rst item is the group name or group name root. The second is the xed pressure for the

group. Third is the number of the production VFP table for the pipeline from the group to its

parent group. If the value 9999 is entered, it means that there is no pressure loss in the network

branch between the group and its parent group. Item 4 is the articial lift quantity used in

the pressure loss calculations for the group's pipeline. Item 5 has the option of YES or NO.

YES indicates that a group production target is met so all wells may operate at same Threshold

pressure (THP). NO means that a group production target is met by the standard method of

113

group control and the wells may operate with dierent THP values.

Oil vaporization is controlled by use of the vappars keyword. Two parameters are connected

to the keyword. These are the propensity of oil to vaporize in the presence of undersaturated

gas, and the propensity of remaining oil to get heavier as lighter fractions vaporize. The second

parameter is set to 0.0 for the Norne reservoir, which indicates that the standard black oil model

behaviour is selected.

The netbalan keyword forces a network balancing calculation to be performed at the next

time step. As seen in the gure below, the rst item in the Norne le is 0.0. That means that

the network is balanced at the beginning of every time step. The next item is the convergence

tolerance for network nodal pressures. This is set to 0.2.

The keyword dates is used to inform on which date the dierent changes to denitions of

properties connected to the wells are performed.

Denitions of the economic limit data for groups and the eld can be found under the gecon

keyword.

The keyword drsdt controls the maximum rate the solution gas-oil ratio is allowed to

increase. In the Norne case drsdt is set to 0, which means that Rs cannot rise and free gas

does not dissolve in undersaturated oil.

A number of inputs for Vertical Flow Performance (VFP) tables are included in the sched-

ule section. The vfpprod keyword is used for VFP tables for production wells. The tables

consist of tablename, bottom hole datum depth for table, rate type, WFR type which is water-oil

ratio, water cut or water-gas ratio and GFR type which is gas-oil ratio, gas-liquid ratio or oil-gas

ratio. In this case, water cut and gas-oil ratio is used. In addition, the tables include ow rate

values, pressure values, water cut values and gas-oil ratio values. Several values are thereafter

included in the table, and detailed description can be found in the Eclipse Reference Manual.

These vfpprod tables are included for every well and a part of such a table is shown below.

Several les included in the data le consist of VFP tables for injectors which are done by

use of the vfpinj keyword.

VFP tables are also included for production and injection owlines in the same way as for

wells.

The tuning keyword sets simulator control parameters. Record 1 includes 8 items for time

stepping controls. Record 2 consist of time truncation and convergence controls, and has 9 items.

An example from the le can be seen below.

114

zippy2 turns on automatic time-step selection control. Use of this keyword adds another

constraint on the time-step selection that takes a smaller time-step if it is predicted that this is

more ecient.

The included le pitmultab_low_high_aug_2006.inc consists of a PI multiplier table dened

by use of the pimultab keyword. This table scale a well's connection factors in proportion to

the maximum water cut it has achieved so far. Column 1 is the maximum water cut values while

column 2 denes the corresponding values of the PI scaling factor.

115

Chapter 5

Development of a benchmark data base

The Center for Integrated Operations in the Petroleum Industry (IO Center) at NTNU includes

several research programs. Program 2, named "Reservoir management and production optimiza-

tion" are working with development of methods, technology and work processes for real-time

reservoir management and real-time production optimization. One of the program's objectives

is to develop a benchmark data base for research and trial activities. "The data base should

use a eld case and in particular promote comparative studies of alternative methods for history

matching and ultimately closed loop reservoir management" [NTNU, 2008].

StatoilHydro's Norne Field in the Norwegian Sea has been in production for approximately

11 years and will be used as the pilot study for the IO Center. The eld has high quality

4D seismic data and production data. StatoilHydro is positive toward cooperation with the

IO Center on the development of such a real eld case, and this master thesis might be the

foundation for further work. A proposal for the continuation of the development of a benchmark

case will be given in this chapter with discussions of model complexity and what data to include

in the test case.

At the moment, there exists no benchmark case consisting of real data. The most realistic

case present today is probably the Brugge Field, presented early 2008.

5.1 TNO Case Study - The Brugge Field

A synthetic eld called Brugge is constructed by the Netherlands Organisation for Applied Sci-

entic Research (TNO), to test the use of ooding optimization and history-matching methods.

TNO released a dataset for several participating organizations, with the intent that history

match and production strategies could be discussed from a common basis. This work might

provide a reference for future developments in this eld of research.

The TNO Case Study serves as a good guideline for how the Norne case could be presented,

and will therefore be used for this thesis' proposal. The most important dierence between the

Brugge Field and the Norne Field is that the Brugge Field is a synthetic oil eld, while Norne is

a real eld. There are several challenges accompanied with a real model; the correct answer is

not available, the model testing is more challenging and the model is very complex. On the other

116

hand, it might be more motivating and exciting to work with real data compared to synthetic

data.

5.2 Norne benchmark case

This section gives a proposal of how the Norne case could be presented by the IO Center, to

research institutions, universities and other interested organizations. Several cases are suggested,

included lists of required data for each case. The section also gives an overview of all existing

data from the Norne Field, and a list of the available data for the test case.

5.2.1 Available data

The main advantage of this case compared to other models, is the available real data from a

producing eld. The range of possible benchmark cases that can be made is inuenced by the

amount of released data.

One possibility is to release the data in dierent packages, which either is dependent or

independent of the previous packages. One package can be followed by a benchmark case that

utilizes the released data. The cases can be independent or extensions to an existing case when

new data is released. The dierent packages of data can be sorted by category. For instance;

types of data, time range of data, or both.

The following data will be released initially as a description of the Norne Field:

- Reservoir simulation model history matched until December 2003

- Detailed description of geology

- Detailed description of petrophysics

- All wells including logs

- Changes of saturation and pressure, from 2003 to 2006, interpreted from the 4D seismics

- Production data for each well from 2003 to 2006

These data will allow several dierent cases to be created. All of these cases will be fairly re-

alistic. A suggestion of a benchmark case is made in section 5.2.3. To make the cases completely

realistic all available data must be released.

5.2.2 Unavailable data

In a real eld there is a huge amount of data available. All this data cannot be released for a

test case. The amount of data is so large that it becomes unpractical and almost unmanageable

if the system for publishing is not good enough. A number of data that can be provided for a

synthetic eld cannot be provided for a real eld, because it is practically impossible to collect.

In addition, the uncertainties concerning real data are of importance when data is selected

117

for publishing. It is not necessary to utilize all the data to make meaningful cases. Another

important aspect is that the companies might want to keep some data as condential, especially

the newest data. An open distribution of fresh data might be dicult to accomplish.

Below is a list of data that is currently not available for this test case:

- Production/injection data after 1st of December 2006

- Water analysis data (used for scale evaluation)

- Tracer data

- Lab data

- Seismic data 3D and 4D data from 2001, 2003, 2004 and 2006

- Seismic processing sequence

- Reprocessed seismic data 2006 (for structural re-evaluation)

- Unprocessed seismic data

- Well data

- Production Logging (PLT) well E4

- Injection Logging (ILT) well F1

At a later stage some of this data may be released. This will enable a wider range of cases

and make the existing cases more realistic.

5.2.3 Description of benchmark case

A proposal for an initial benchmark case is to consider the time frame from 2003 to 2006 for

history matching. The actual model from 2003, containing all information and properties until

that time, can be given. In addition, production and injection data from 2003 to 2006, and 4D

seismic data for the same period could be provided. These data will be the basis for the history

match performed by participants.

A report could be made by each participant, describing the results and the methods used to

achieve their results. One of the goals will be to test dierent simulation methods to nd their

applicability to real problems.

Then, the participants can discuss the results in a workshop. At this stage, proposals for

improvements can be made. This includes presentation of new cases and new available data

needed for these cases.

118

Case 1

1. Download the Norne model from 2003 and import it into the reservoir simulator. The

production history for 2003-2006 will be given.

2. Participants history match the model, in the period 2003-2006

3. Discuss and compare results

A benchmark case like this could be published within the IO Center and its partners as a

joint study to enhance the collaboration. The case could also be provided to interested research

institutions and companies outside the IO Center to get wider research and possibly better

results. Society of Petroleum Engineers (SPE) has organized a series of comparative solution

projects through the years. The Norne benchmark case serves as a good case for a compara-

tive study. After participants have nished their work, a SPE paper could be published and

presented at a conference regarding a relevant topic. The SPE comparative solution project

paper could include description of the problems and presentation of participants and utilized

methods. Thereafter, the results of the history match from the dierent workshop delegates

could be introduced, compared and commented in the paper.

Multiple cases can be designed using data from the Norne Field as a basis. Examples of

other cases are given in the following.

Case 2

Case 2 is an extension of Case 1 where an optimal production strategy for the period 2006-2016

should be made.

1. Using the history matched results from Case 1, come up with an optimal production

strategy for the next period (10 years)

2. Receive additional production data (5 years)

3. Update the model and revise the production strategy for the nal period (5 years)


Case 3

This case is a geophysical-related case allowing the participants to use their own seismic pro-

cessing sequences to process the Norne seismics.

1. Download unprocessed seismics from 2003 and 2006

2. Perform seismic processing

3. Compare the newly processed 3D and 4D seismics to the existing processed data


119

Chapter 6

Discussion

Reservoir simulation models are used for calculating reservoir volumes, well planning, to improve

the understanding of complex ow behaviour and to predict future reservoir performance. Thus,

the models are essential tools for the development of oil and gas elds and provides the engineer

with a powerful insight into reservoir behaviour. Gradually, a higher degree of knowledge of

the eld is achieved through a continuous gathering of data. This results in regular updates of

existing reservoir simulation models to incorporate new well data. Frequently updated models

are needed to increase recovery of a eld. Seismic data is among other factors considered as an

important tool for this. 4D seismic surveys can give information about uid changes in the eld,

which might be important for predicting future production performance. Measurements of pro-

duction and injection rates are also needed for updating reservoir simulation models. Research

institutions and petroleum companies are continuously developing methods for maintenance of

reservoir models. Hence, they need realistic models to work with to achieve results which can

be used for real petroleum elds. The utility of a released reservoir model, as the Norne model,

will be discussed in the following.

The rst aspect discussed is connected to the geometric complexity of models. Model com-

plexity will depend on; number of phases present, number of dimensions, segmentation of the

reservoir, vertical and spatial variations in rock properties etc. Methods and algorithms are prin-

cipally developed using simple models before they eventually are tested on eld data. Dierent

methods can be tested on synthetic models with simplied geometries constructed for model

testing purposes, but they may not work in the same way for a real eld model with complex

geometry. Hence, access to real data for the testing of simulation models is vital.

Several research communities are mainly focused on the modelling and mathematical aspects

in research of reservoir simulation modelling. Detailed knowledge about real reservoir behaviour

is often poor and the knowledge will not improve when a synthetic model is used for testing.

Hence, access to a model with real data during research improves the understanding of relevant

problems, and makes the research more meaningful.

Research communities in Norway and around the world, take an interest in the establishment

of an open model with real data. Currently, there does not exist a realistic model. It is of great

importance to have a real model which is open for several research institutions, to compare

120

various methods used on the same set of data. Models with real datasets can contribute to good

discussions and comparisons of results from dierent algorithms, methods and simulators which

might improve future development of software, methods etc.

The various data from Norne could also be used by research communities within other parts

of the petroleum industry, for instance geophysics, drilling, geology etc. Universities could also

benet from easy access to real data. They could improve their education method by use of new

real data. Students nd it more motivating and exciting to work with real data than constructed

data in relation with education. Lectures in geophysics and petrophysics for instance, could be

improved with 4D seismics and petrophysical logs from a real eld as Norne.

The Norne Field is still producing and has both 4D seismic data and production data of high

quality available. Reservoir simulation models with real data from producing elds are more

motivating and challenging to work with compared to synthetic models. The Norne Field will

probably be in production several years ahead, and this makes the model even more interesting

for use in research by the fact that the data set will change and be updated gradually.

A benchmark case from a real eld needs to be updated to have real value. One of the

challenges might be to have synchronized data available at all times. To succeed in this, the

communication between the data-owners and the test case distributor, in this case StatoilHydro

and the IO Center, has to be good. In addition, it is important to have people assigned for

maintaining the information which already is available, and to prepare new data for publication.

A support team will be necessary, especially in the implementation phase when possible questions

and start-up challenges need to be sorted out.

For utilizing the results from a study on the Norne test case in a wider perspective, the

eld must be representative. Dierent geology gives dierent challenges in connection with for

instance history matching. The hydrocarbons on Norne are located in sandstone formations of

Lower and Middle Jurassic age of generally good reservoir quality. The hydrocarbons in the

North Sea are generally of Jurassic age. Thus, the Norne Field is considered to be a good

alternative, having properties similar to other elds. Norne is also producing both oil and gas,

and both gas and water have been injected. This is a production history shared by many other

elds.

Another aspect related to the work with a full eld model is the computation time. The

complexity of a full eld model requires a high computational speed to reduce the simulation

time. High speed computers permit multiple runs of a reservoir model to test dierent methods

of operation, to check the sensitivity of predicted reservoir behaviour to uncertainties in uid

and rock properties etc. The Norne simulation model is rather slow because of the eld's size and

complexity. It could therefore be possible to divide the reservoir into smaller sector models to

reduce the simulation time. For instance; to do simulations on the G-segment only and include

the boundary conditions representing the rest of the eld. The G-segment is best suited for such

a task because it is isolated from the rest of the eld on three sides.

The benet StatoilHydro will achieve in the development of the Norne Field, after releasing

the data, is dubious. However, the development of new methods for reservoir model updating

121

and history matching might benet StatoilHydro as well as other institutions and companies.

As the rst company releasing a data set from a eld, a tighter collaboration with research

institutions and universities could be gained.

The utility and potential of the Norne benchmark case is expected to be great. Studies as the

SPE comparative projects mentioned in section 5.2.3 could be made, where results of simulations

of the same cases with dierent simulators and methods are compared and commented. If this

is to be performed, the model must be presented to interested communities. The design and

publication of the model will demand commitment and time of several researchers. To ensure

awareness of the existence of the Norne model, publicity is essential.

122

Chapter 7

Conclusion

The utility and potential for reservoir simulation models used for research is great. In order to

develop new tools and methods for history matching and reservoir model updating, it is benecial

to have relevant models with real data available for testing. Release of the Norne benchmark

case will support this development by making a model with real seismic- and production data

available. The main advantages of this model compared to already existing synthetic models,

are the complexity and the unknown future behaviour of the reservoir, like in real reservoir

development.

It is important to have a real model which is open for several research institutions, to compare

various methods used on the same set of data. Models with real datasets can contribute to give

good discussions and comparisons of results from dierent algorithms and simulators, and might

improve future development of software and methods.

The Norne Field is considered to be a good alternative for a benchmark model, due to the

available high quality data, a representative geology and StatoilHydro's cooperation. Several

seismic surveys of good quality and regularly updated data from all wells are advantageous. The

sandstone reservoir is of Jurassic age, which contributes to make this eld attractive as it is

similar to a number of other elds.

To ensure easy access and utilization of the data set, qualied personnel providing follow-

up and support is necessary. This includes consistency in published data as well as answering

questions and solving start-up problems.

Publicity of the Norne model is essential to ensure awareness of the existence of the model

for potential users. This can be achieved by presenting the case in papers and on conferences.

A SPE Comparative Solution Project is an appropriate alternative for the Norne benchmark

model to attract attention.

123

Appendix A

Nomenclature

ACBL - Acoustic Cement Bond Log

ACL - Acoustic Log

CAL - Caliper

CBL - Cement Bond Log

CDN - Compensated Density Neutron

CDR - Compensated Dual Resisivity

CNL - Compensated Neutron Log

DAC - Digital Array Acoustilog Log

DIFL - Dual Induction Focus Log

DIPL - Diplog

DLL - Dual Laterolog

DST - Drill Stem Test

ESP - Event Simularities Predictions

FMT - Formation Multi Test

FSP - Fault Seal Probability

GIR - Gas Injection Rate

GOC - Gas-Oil Contact

GOR - Gas-Oil Ratio

GPR - Gas Production rate

GR - Gamma Ray Log

HP - Pressure (HP quartz gauge)

ILT - Injection Logging

IRAP - Interactive Reservoir Analysis Package

LWD - Logging While Drilling

MAC - Multiple Array Acoustic Log

MD/RKB - Measured Depth relative to Rotary Kelly Bushing

MLL - Microlaterolog

MWD - Measuring While Drilling

NA - Not Available

1

NNW-SSE - north/northwest - south/southeast

o.e. - oil equivalents (oil, gas and condensate)

OPR - Oil Production Rate

OWC - Oil-Water Contact

PLT - Production logging

QC - Quality Control

RI - Resistivity Index

RMS - Reservoir Modeling System

ROV - Remotely Operated Vehicles

SGR - Smear Gouge Ratio

SL - Spectralog

SRME - surface related multiple elimination

SUSP.AT TD - Suspended at Total Depth

SWC - Sidewall Corun

SW-NE - southwest - northeast

THP - Threshold Pressure

TVD/MSL - True Vertical Depth / Mean Sea Level

VDL - Variable Density Log

VFP - Vertical Flow Performance

VSP - Vertical Seismic Prole

WIR - Water Injection Rate

WPR - Water Production Rate

ZDL - Compensated Z-density log

2

Appendix B

Figures

B.1 Well plots

Figure B.1: Oil Production Rate B-1H

3

Figure B.2: Watercut B-1H

Figure B.3: Gas-Oil Ratio B-1H

4



5



6



7



8


Figure B.13: Oil Production Rate D-1H

9

Figure B.14: Watercut D-1H

Figure B.15: Gas-Oil Ratio D-1H

10



11



12



13



14


Figure B.25: Oil Production Rate E-1H

15

Figure B.26: Watercut E-1H

Figure B.27: Gas-Oil Ratio E-1H

16



17



18



19



20


Figure B.37: Oil Production Rate K-3H

21

Figure B.38: Watercut K-3H

Figure B.39: Gas-Oil Ratio K-3H

22

Figure B.40: Water Injection Rate C-1H

Figure B.41: Gas Injection Rate C-1H

23



24



25


Figure B.47: Water Injection Rate F-1H

26



27


28

B.2 Seismic results

B.2.1 3D seismic

Figure B.51: 3D Seismic, line number 1100 showing the oil-water contact in 2001

29


30


31


32

Figure B.55: 3D Seismic, trace number 1600showing the oil-water contact in 2001


33



34

B.2.2 4D seismic

Figure B.59: 4D Seismic, line number 1100, 2001-2003

35

Figure B.60: 4D Seismic, line number 1100, 2001-2004

36

Figure B.61: 4D Seismic, trace number 1600,2001-2003

Figure B.62: 4D Seismic, trace number 1600,2001-2004

37

Appendix C

Tables

C.1 Production Data

Table C.1: Production data for well K-3 HK-3H

GPR OPR WPR

Date Sm3/day Sm3/day Sm3/day

06.11.97 0.00 0.00 0.00

15.1006 488809.63 780.12 33.25

01.11.06 898066.06 1816.45 50.24

09.11.06 747746.62 1890.05 37.60

11.11.06 666183.06 2010.88 80.17

17.11.06 542707.62 1701.59 133.30

01.12.06 542707.62 1701.59 133.30

38

TableC.2:Productiondata

fortemplate

B

B-1H

B-2H

B-3H

B-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

06.11.97

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

09.12.97

0.00

0.00

0.00

230825.03

2079.51

0.00

0.00

0.00

0.00

0.00

0.00

0.00

24.12.97

0.00

0.00

0.00

594956.81

5359.97

0.00

0.00

0.00

0.00

0.00

0.00

0.00

11.01.98

0.00

0.00

0.00

576611.31

5194.69

0.00

0.00

0.00

0.00

0.00

0.00

0.00

11.02.98

0.00

0.00

0.00

41775.30

376.35

0.00

0.00

0.00

0.00

0.00

0.00

0.00

07.03.98

0.00

0.00

0.00

396505.31

3572.12

0.00

0.00

0.00

0.00

0.00

0.00

0.00

30.03.98

0.00

0.00

0.00

565401.38

5093.70

0.00

0.00

0.00

0.00

0.00

0.00

0.00

31.03.98

0.00

0.00

0.00

685349.00

6174.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

02.04.98

0.00

0.00

0.00

632415.38

5697.44

0.00

0.00

0.00

0.00

0.00

0.00

0.00

27.04.98

0.00

0.00

0.00

617071.75

5559.20

0.00

0.00

0.00

0.00

221340.11

1994.06

0.00

06.05.98

0.00

0.00

0.00

578485.81

5211.58

0.00

0.00

0.00

0.00

560240.38

5047.21

0.00

27.05.98

0.00

0.00

0.00

598227.69

5389.40

0.00

0.00

0.00

0.00

580659.69

5231.20

0.00

28.05.98

0.00

0.00

0.00

569177.88

5127.72

0.00

0.00

0.00

0.00

551593.81

4969.30

0.00

02.06.98

0.00

0.00

0.00

624988.31

4955.66

0.00

0.00

0.00

0.00

529675.19

4771.85

0.00

17.06.98

0.00

0.00

0.00

653673.12

5199.31

0.00

0.00

0.00

0.00

564045.62

4821.12

0.00

24.06.98

0.00

0.00

0.00

599244.69

4871.90

0.00

0.00

0.00

0.00

604074.12

5034.00

0.00

25.06.98

0.00

0.00

0.00

610801.94

4099.33

0.00

0.00

0.00

0.00

529866.31

4139.57

0.00

03.07.98

0.00

0.00

0.00

580178.19

4147.97

0.00

0.00

0.00

0.00

435373.34

3813.46

0.00

21.07.98

0.00

0.00

0.00

751902.19

4722.04

0.00

0.00

0.00

0.00

556095.50

4637.59

0.00

04.08.98

0.00

0.00

0.00

765123.06

4349.36

0.00

0.00

0.00

0.00

551281.56

4319.49

0.00

31.08.98

0.00

0.00

0.00

767577.69

4365.90

0.00

0.00

0.00

0.00

539039.69

4391.90

0.00

01.09.98

0.00

0.00

0.00

774446.63

4432.80

0.00

0.00

0.00

0.00

540425.12

4430.90

0.00

02.09.98

0.00

0.00

0.00

846252.62

4625.82

0.00

0.00

0.00

0.00

666010.25

4645.04

0.00

22.09.98

0.00

0.00

0.00

847408.12

4251.06

0.00

0.00

0.00

0.00

709767.94

4525.78

0.00

01.10.98

0.00

0.00

0.00

669178.88

3243.73

0.00

0.00

0.00

0.00

612173.81

4025.47

0.00

02.10.98

0.00

0.00

0.00

642497.06

2997.27

0.00

0.00

0.00

0.00

506745.75

3197.36

0.00

15.10.98

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

17.10.98

0.00

0.00

0.00

645240.75

3527.09

0.00

0.00

0.00

0.00

565074.88

3488.73

0.00

01.11.98

0.00

0.00

0.00

877927.62

4491.49

0.00

0.00

0.00

0.00

689605.00

4185.25

0.00

02.12.98

0.00

0.00

0.00

786130.19

3964.64

0.00

0.00

0.00

0.00

648718.88

4015.17

0.00

25.12.98

0.00

0.00

0.00

866839.44

4098.16

0.00

0.00

0.00

0.00

780509.38

4522.79

0.00

01.01.99

0.00

0.00

0.00

758060.38

3508.57

3.05

0.00

0.00

0.00

726884.56

4132.80

4.13

ContinuedonNextPage...

39

TableC.2

Continued

B-1H

B-2H

B-3H

B-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

04.01.99

0.00

0.00

0.00

964257.75

3858.87

3.87

0.00

0.00

0.00

912091.38

4478.42

4.49

19.01.99

0.00

0.00

0.00

1000842.80

4000.70

4.00

0.00

0.00

0.00

873846.75

4214.30

45748.00

21.01.99

0.00

0.00

0.00

886646.19

4074.73

4.08

0.00

0.00

0.00

766384.31

4167.01

4.16

01.02.99

0.00

0.00

0.00

764845.25

4093.26

4.09

0.00

0.00

0.00

743778.25

4067.14

4.06

25.02.99

0.00

0.00

0.00

898909.00

4206.04

4.20

0.00

0.00

0.00

819662.25

4168.44

4.18

01.03.99

0.00

0.00

0.00

933702.75

4044.18

4.05

0.00

0.00

0.00

910354.81

4375.88

4.38

05.03.99

0.00

0.00

0.00

996512.56

4014.41

4.01

0.00

0.00

0.00

786219.44

3751.60

3.76

23.03.99

0.00

0.00

0.00

1363575.50

4321.27

4.30

0.00

0.00

0.00

930726.88

3526.67

3.53

26.03.99

0.00

0.00

0.00

1527587.00

4833.35

4.80

0.00

0.00

0.00

1008905.50

3809.30

3.85

28.03.99

0.00

0.00

0.00

1449902.50

4630.52

4.63

0.00

0.00

0.00

981292.12

3739.05

27454.00

01.04.99

832512.56

4334.31

0.00

1127240.90

3956.35

3.35

0.00

0.00

0.00

366267.84

982.04

0.78

02.05.99

1182172.10

6468.63

0.00

808585.88

3682.30

0.00

0.00

0.00

0.00

237951.27

290.90

0.00

04.05.99

1128108.90

6461.40

0.00

827572.19

3950.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

05.05.99

911792.25

5656.98

0.00

812486.00

3811.69

0.00

0.00

0.00

0.00

24538.11

29.38

0.00

18.05.99

880870.81

5729.57

0.00

802295.25

3852.03

0.00

0.00

0.00

0.00

0.00

0.00

0.00

21.05.99

895569.62

5900.50

0.00

834734.00

4059.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

22.05.99

866862.62

5900.56

0.00

850327.56

4206.16

0.00

0.00

0.00

0.00

8731.42

39609.00

0.00

01.06.99

799017.44

6016.45

0.29

724814.44

4343.88

0.19

0.00

0.00

0.00

2901.75

3.48

0.00

22.06.99

889792.31

6031.72

6.06

608386.12

4064.32

4.04

0.00

0.00

0.00

0.00

0.00

0.00

01.07.99

762131.12

5126.54

5.14

495742.59

3284.32

3.29

406293.31

2208.36

2.21

0.00

0.00

0.00

15.07.99

738025.62

4960.40

3.32

476168.13

3172.97

2.08

1019269.80

4869.35

3.03

0.00

0.00

0.00

02.08.99

689150.94

4796.48

0.00

463941.44

3229.00

0.00

1310257.10

5309.52

0.00

0.00

0.00

0.00

06.08.99

708665.44

4763.18

0.00

467525.28

3115.28

0.00

1305322.40

4853.28

0.00

0.00

0.00

0.00

01.09.99

812776.00

5091.60

0.00

535931.94

3133.50

0.00

1841222.00

4790.90

0.00

0.00

0.00

0.00

03.09.99

776090.31

4932.80

0.00

513178.56

3044.35

0.00

1748689.00

4616.95

0.00

0.00

0.00

0.00

05.09.99

792888.00

5042.57

0.00

549488.19

3259.54

0.00

1198985.40

3207.91

0.00

0.00

0.00

0.00

22.09.99

1018050.40

5691.70

0.00

730180.88

3810.20

0.00

162135.91

376.60

0.00

0.00

0.00

0.00

22.09.99

694939.88

4334.98

0.00

453425.31

2583.29

0.00

361612.97

917.96

0.00

0.00

0.00

0.00

02.10.99

878357.19

5383.75

0.00

601012.75

3438.65

0.00

1051269.20

2576.45

0.00

0.00

0.00

0.00

03.10.99

824582.38

5259.10

0.00

567386.88

3377.50

0.00

916374.81

2241.70

0.00

0.00

0.00

0.00

04.10.99

808302.25

5053.93

0.00

590477.00

3457.20

0.00

715491.62

1713.81

0.00

754.57

0.84

0.00

14.10.99

812994.31

5018.70

0.00

569794.12

3283.10

0.00

596978.50

1413.80

0.00

0.00

0.00

0.00


40

TableC.2

Continued

B-1H

B-2H

B-3H

B-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

17.10.99

542344.50

3920.91

0.00

413845.81

2784.63

0.00

930589.19

2634.45

0.00

0.00

0.00

0.00

01.11.99

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

09.11.99

463561.09

2985.90

0.00

0.00

0.00

0.00

478295.00

1247.00

0.00

0.00

0.00

0.00

10.11.99

714173.62

5301.47

0.00

389977.84

3045.73

0.00

684155.06

1867.83

0.00

0.00

0.00

0.00

13.11.99

607312.31

3987.51

0.00

479657.56

3362.07

0.00

739114.69

1942.03

0.00

0.00

0.00

0.00

01.12.99

793403.44

4391.85

0.00

570082.50

3375.61

0.00

952746.81

2302.84

0.00

183903.91

1093.87

0.00

02.01.00

676135.50

3496.67

0.00

603156.19

3240.76

0.00

876584.75

1994.62

0.00

69542.08

439.53

0.00

01.02.00

779567.12

4215.86

0.00

535312.19

3087.61

0.00

1305934.80

3020.95

0.00

1975.31

15.05

0.00

02.03.00

916505.13

4799.90

0.00

662147.38

3684.50

0.00

1367550.10

3082.40

0.00

0.00

0.00

0.00

03.03.00

907458.81

4724.70

0.00

655962.13

3628.70

0.00

1383855.50

3100.90

0.00

0.00

0.00

0.00

04.03.00

939920.31

4109.66

43.79

467931.69

2895.98

0.00

953288.50

3281.77

0.00

0.00

0.00

0.00

03.04.00

644069.44

2344.70

17.29

292312.56

2398.15

0.00

528018.56

2248.82

0.00

0.00

0.00

0.00

01.05.00

1297567.40

3869.19

0.00

582140.31

4753.76

0.00

964280.19

3722.26

0.00

0.00

0.00

0.00

26.05.00

1401807.50

4196.07

0.00

595919.19

4894.53

0.00

789047.75

3068.70

0.00

0.00

0.00

0.00

02.06.00

1196874.40

3319.59

0.00

507061.44

3885.95

0.00

877212.56

3154.06

0.00

0.00

0.00

0.00

11.06.00

1236979.40

3328.63

0.00

492781.31

3659.29

0.00

959251.00

3349.94

0.00

12791.10

80.82

0.00

01.07.00

756725.88

2000.00

0.00

534889.00

3879.20

0.00

1228432.80

4202.40

0.00

0.00

0.00

0.00

01.07.00

1248073.40

3601.85

0.00

646937.62

4303.46

0.00

1128281.90

3869.20

0.00

8460.78

55.16

0.00

02.08.00

1276784.50

3896.80

0.00

743321.12

4863.50

0.00

1179417.00

4115.60

0.00

0.00

0.00

0.00

03.08.00

1230309.90

3653.60

0.00

644194.81

4101.00

0.00

466570.41

1584.10

0.00

0.00

0.00

0.00

03.08.00

1256988.80

3969.01

0.00

656936.62

4440.11

0.00

1060828.10

3848.64

0.00

0.00

0.00

0.00

20.08.00

792101.56

2719.97

0.00

595767.06

4429.33

0.00

971751.25

3839.10

0.00

0.00

0.00

0.00

27.08.00

654554.69

2112.20

0.00

671079.69

4642.30

0.00

922202.31

3402.40

0.00

0.00

0.00

0.00

28.08.00

966614.31

3248.76

0.00

564704.06

4078.94

0.00

970926.06

3738.84

0.00

0.00

0.00

0.00

01.09.00

1150705.50

3640.95

0.00

616288.25

4178.41

0.00

1057624.90

3824.96

0.00

0.00

0.00

0.00

10.09.00

823141.88

2678.30

0.00

479973.19

3347.90

0.00

995457.69

3703.20

0.00

0.00

0.00

0.00

11.09.00

914841.75

2821.66

0.00

599078.44

3983.34

0.00

925280.69

3266.87

0.00

0.00

0.00

0.00

21.09.00

294040.81

872.70

0.00

641988.31

4084.80

0.00

0.00

0.00

0.00

0.00

0.00

0.00

22.09.00

955534.06

3044.84

0.00

637199.06

4265.06

0.00

781849.88

2912.13

0.00

0.00

0.00

0.00

01.10.00

1100164.10

3359.67

0.00

667246.31

4365.56

0.00

974620.50

3407.09

0.00

0.00

0.00

0.00

03.11.00

1168285.20

3367.89

0.00

632814.19

3887.94

0.00

941468.63

3113.77

0.00

0.00

0.00

0.00

02.12.00

1172255.50

3271.23

0.00

601120.13

3587.40

0.00

914639.81

2922.02

0.00

0.00

0.00

0.00


41

TableC.2

Continued

B-1H

B-2H

B-3H

B-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

03.01.01

410465.31

1151.50

0.00

734562.19

3513.27

0.00

1210480.10

4577.86

0.00

1803.01

13.83

0.00

02.02.01

0.00

0.00

0.00

1463985.90

4508.99

0.00

1798026.60

6639.96

0.00

0.00

0.00

0.00

02.03.01

5632.88

9.23

0.00

1448686.20

4642.44

0.00

1728932.20

6636.67

0.00

0.00

0.00

0.00

02.04.01

0.00

0.00

0.00

1367320.10

4878.41

0.00

1642860.40

7033.55

0.00

0.00

0.00

0.00

02.05.01

0.00

0.00

0.00

1293441.50

4573.21

0.00

1529666.30

6496.46

0.00

0.00

0.00

0.00

01.06.01

0.00

0.00

0.00

1437754.70

4806.80

0.00

1671972.00

6707.80

0.00

0.00

0.00

0.00

07.06.01

0.00

0.00

0.00

687236.62

2960.00

0.00

874989.62

4522.40

0.00

0.00

0.00

0.00

07.06.01

0.00

0.00

0.00

1167318.50

4691.28

0.00

1226366.20

6262.63

0.00

0.00

0.00

0.00

18.06.01

0.00

0.00

0.00

989348.13

3482.70

0.00

952338.81

4814.70

0.00

0.00

0.00

0.00

19.06.01

0.00

0.00

0.00

1129859.40

4617.70

0.00

1020702.90

6012.46

0.00

0.00

0.00

0.00

02.07.01

0.00

0.00

0.00

519554.19

2361.80

0.00

670744.62

4379.00

0.00

0.00

0.00

0.00

03.07.01

0.00

0.00

0.00

521505.59

2326.50

0.00

671111.69

4299.80

0.00

0.00

0.00

0.00

04.07.01

0.00

0.00

0.00

951927.25

4158.67

0.00

925181.44

5831.58

0.00

0.00

0.00

0.00

16.07.01

0.00

0.00

0.00

1218610.00

5074.00

0.00

1069669.40

6396.40

0.00

0.00

0.00

0.00

17.07.01

172776.64

303.65

0.00

899352.12

4002.93

0.00

895544.06

5761.59

0.00

0.00

0.00

0.00

30.07.01

1619707.40

2749.10

0.00

590302.25

2968.60

0.00

692322.25

5000.20

0.00

0.00

0.00

0.00

B-4BH

B-4BH

B-4BH

01.08.01

1148734.80

2086.16

0.00

455138.34

2447.40

0.00

634162.25

4895.83

0.00

219342.89

1412.10

0.00

17.08.01

0.00

0.00

0.00

108231.83

716.63

0.00

500281.25

2881.63

58.80

495085.44

4673.84

0.00

02.09.01

0.00

0.00

0.00

124386.71

812.82

0.00

904621.06

5158.84

105.28

560346.69

5225.44

0.00

10.09.01

0.00

0.00

0.00

75868.20

506.10

0.00

510336.88

2935.68

79.50

295694.38

2718.81

78.35

02.10.01

0.00

0.00

0.00

479292.91

2508.47

0.00

1454487.90

5166.92

216.32

657803.69

4418.68

586.60

02.11.01

0.00

0.00

0.00

867709.25

4395.19

0.00

1553630.70

4041.59

245.05

579098.75

3721.16

605.77

04.12.01

0.00

0.00

0.00

857267.94

4484.25

0.00

2235931.20

4038.84

343.15

578138.81

3676.99

691.31

30.12.01

0.00

0.00

0.00

644976.62

4503.47

0.00

2538493.00

4477.13

285.80

496602.50

3494.30

985.57

01.01.02

407007.12

3813.62

0.00

557718.75

3987.68

0.00

369102.41

624.12

49.52

508793.81

2980.87

1041.68

03.02.02

514041.66

4264.44

0.00

780531.38

5051.01

0.00

0.00

0.00

0.00

555339.56

2710.51

740.87

12.02.02

471329.09

3456.80

0.00

650171.38

3668.00

0.00

0.00

0.00

0.00

453829.91

1924.00

409.40

13.02.02

292380.88

2212.69

0.00

712097.50

4328.23

0.00

1032597.00

1753.23

111.31

511888.56

2354.04

775.17

01.03.02

974510.25

4677.90

0.00

548051.56

3773.36

0.00

679724.25

1775.10

155.46

446872.25

2209.20

939.50

02.04.02

1016818.60

4998.05

0.00

657799.63

5235.61

0.00

737295.31

2302.31

222.07

262383.31

1436.39

907.53

01.05.02

1245479.50

5772.46

0.00

653824.69

5139.17

0.00

84755.08

517.33

221.08

284511.88

2028.97

1257.43


42

TableC.2

Continued

B-1H

B-2H

B-3H

B-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

02.06.02

899633.06

4750.55

0.00

331747.69

2739.97

0.00

252141.55

1815.98

843.36

299919.97

2251.14

1625.68

02.07.02

701949.31

4609.19

0.00

0.00

0.00

0.00

274697.94

1745.90

724.73

336232.72

2285.14

2166.96

08.07.02

702140.56

4856.43

0.00

0.00

0.00

0.00

187933.20

1250.80

575.53

325597.84

2345.67

2460.80

11.07.02

705373.25

4791.08

0.00

0.00

0.00

0.00

167210.30

1092.20

505.67

326670.38

2311.38

2439.98

15.07.02

688480.06

4727.19

0.00

543214.19

4248.67

0.00

232195.31

1530.64

712.57

273345.69

1953.17

2139.66

02.08.02

641386.50

4169.82

0.00

287675.91

2058.51

0.00

221494.98

1421.29

624.81

264519.44

1802.90

1842.52

14.08.02

837771.69

5178.64

197.43

537107.69

4201.45

0.00

0.00

0.00

0.00

231077.80

1547.89

1770.75

01.09.02

781703.81

4115.70

453.10

621218.38

5054.70

0.00

0.00

0.00

0.00

212850.20

1120.70

1665.60

02.09.02

754475.81

4357.55

492.39

583708.19

4949.05

0.00

16559.96

118.56

40.65

200388.20

1099.39

1669.21

15.09.02

670542.69

4720.19

534.13

552924.31

4996.89

0.00

0.00

0.00

0.00

178308.59

1034.02

1442.41

01.10.02

770046.56

4425.93

595.78

619863.38

5154.10

0.00

0.00

0.00

0.00

138782.27

775.48

955.05

08.10.02

898759.13

4626.83

771.37

724691.31

5443.34

0.00

36620.60

242.64

106.41

0.00

0.00

0.00

14.10.02

677003.44

3727.52

747.79

699776.56

4867.27

0.00

48832.46

287.25

69.12

125909.85

575.03

615.96

02.11.02

703606.00

3466.62

542.35

545085.06

3733.70

0.00

0.00

0.00

0.00

240192.59

1096.26

1172.42

17.11.02

787295.62

3728.39

585.45

697687.56

4952.95

0.00

0.00

0.00

0.00

263216.53

1209.85

1296.47

02.12.02

821582.75

3736.66

812.53

698558.44

4198.66

0.00

0.00

0.00

0.00

74291.39

358.33

441.93

24.12.02

976798.00

3789.08

957.67

1142726.60

4832.21

0.00

0.00

0.00

0.00

0.00

0.00

0.00

01.01.03

735757.69

3748.10

929.40

1159193.00

5368.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

02.01.03

723364.25

3676.88

802.58

1157897.80

5351.83

0.00

0.00

0.00

0.00

0.00

0.00

0.00

12.01.03

703897.81

3595.63

660.74

1156339.10

5370.01

0.00

0.00

0.00

0.00

0.00

0.00

0.00

20.01.03

723526.06

3319.48

843.20

1151784.40

4819.76

0.00

15126.53

78.74

25.88

0.00

0.00

0.00

03.02.03

563403.94

2815.87

964.95

1201537.90

5469.75

0.00

0.00

0.00

0.00

0.00

0.00

0.00

14.02.03

704110.06

3176.23

1127.18

1149445.80

4716.95

0.00

12740.53

66.47

22.93

0.00

0.00

0.00

01.03.03

604770.38

3498.20

1219.60

667949.62

3490.20

0.00

0.00

0.00

0.00

0.00

0.00

0.00

06.03.03

579427.00

3143.00

1092.00

858168.00

4232.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

07.03.03

609909.19

3267.64

1290.60

810775.56

4534.80

0.00

798715.75

4282.36

0.00

0.00

0.00

0.00

03.04.03

512950.59

3340.03

1403.47

634786.69

5166.20

0.00

744964.12

4408.27

0.00

448.83

2.47

3.57

04.12.03

349612.62

1992.39

1292.58

623210.56

5297.87

0.00

709287.50

3997.71

249.81

302.13

1.55

2.32

03.06.03

0.00

0.00

0.00

650826.00

6252.00

0.00

498913.00

4167.50

2001.50

0.00

0.00

0.00

04.06.03

0.00

0.00

0.00

627271.31

5924.68

0.00

485884.81

3503.39

1450.04

0.00

0.00

0.00

02.07.03

0.00

0.00

0.00

520606.78

5598.00

0.00

336408.34

1497.11

417.67

0.00

0.00

0.00

10.07.03

2135.91

10.55

13.55

640259.94

6589.59

0.00

326767.72

1466.91

461.27

0.00

0.00

0.00


43

TableC.2

Continued

B-1H

B-2H

B-3H

B-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

02.08.03

0.00

0.00

0.00

627391.25

6721.67

0.00

357808.13

1697.44

523.11

0.00

0.00

0.00

11.08.03

0.00

0.00

0.00

655643.00

6740.50

0.00

390277.00

1779.00

545.00

0.00

0.00

0.00

12.08.03

0.00

0.00

0.00

508046.09

5371.60

0.00

239040.66

1404.50

353.65

0.00

0.00

0.00

01.09.03

0.00

0.00

0.00

642925.19

6010.30

0.00

259806.70

1278.30

295.70

0.00

0.00

0.00

02.09.03

0.00

0.00

0.00

740241.06

6491.99

0.00

270783.94

1250.81

275.30

0.00

0.00

0.00

10.09.03

0.00

0.00

0.00

741964.94

6483.70

0.00

244711.86

1125.50

257.85

0.00

0.00

0.00

12.09.03

0.00

0.00

0.00

673277.50

5929.50

0.00

248273.09

1150.80

274.30

0.00

0.00

0.00

13.09.03

0.00

0.00

0.00

703291.50

6041.73

0.00

264858.09

1198.00

290.43

0.00

0.00

0.00

16.09.03

231765.73

1049.51

0.00

766403.06

6301.23

0.00

202096.69

875.57

167.75

0.00

0.00

0.00

01.10.03

395602.25

1237.68

0.00

802390.31

6762.85

0.00

263641.06

1085.60

239.42

0.00

0.00

0.00

24.10.03

598497.75

1359.37

0.00

765072.50

6793.17

0.00

290941.97

1180.36

267.36

0.00

0.00

0.00

02.11.03

605635.25

1408.07

0.00

726591.56

6608.03

0.00

181377.22

749.77

194.72

0.00

0.00

0.00

20.11.03

636829.25

1442.59

0.00

760755.69

6734.98

0.00

191938.81

777.72

179.99

0.00

0.00

0.00

04.12.03

622569.75

1410.26

0.00

730454.62

6463.10

0.00

192854.38

908.84

208.64

0.00

0.00

0.00

09.12.03

691770.37

1496.80

0.00

807150.88

6822.00

0.00

199535.00

899.50

215.80

0.00

0.00

0.00

10.12.03

632356.56

1435.96

0.00

654375.69

5788.11

0.00

158891.48

751.90

158.37

0.00

0.00

0.00

18.12.03

669732.81

1431.35

0.00

789527.44

6590.96

0.00

220836.98

981.91

216.19

0.00

0.00

0.00

01.01.04

674918.00

1340.31

43.36

797008.75

6173.83

93.11

244121.88

1021.46

207.90

0.00

0.00

0.00

19.01.04

560905.31

1094.60

332.80

612679.62

5021.70

217.30

212885.59

969.40

174.90

0.00

0.00

0.00

20.01.04

668308.00

1188.92

400.48

786119.50

5874.92

281.77

294144.56

1219.62

244.22

0.00

0.00

0.00

02.02.04

617262.25

1138.99

418.18

864377.81

5616.88

511.73

290615.88

1444.02

327.55

0.00

0.00

0.00

01.03.04

507597.25

1053.22

421.22

832930.38

5310.10

746.55

162122.97

1119.06

294.20

0.00

0.00

0.00

01.04.04

435386.28

867.88

411.69

429334.25

3069.49

611.35

282607.19

1730.60

381.12

0.00

0.00

0.00

01.05.04

309477.25

580.84

371.44

461091.91

3727.14

855.03

320703.25

1882.37

433.85

0.00

0.00

0.00

02.06.04

613348.69

509.76

384.43

400990.91

2681.62

964.10

309920.03

1940.03

428.55

0.00

0.00

0.00

02.07.04

504273.06

422.50

350.45

394592.84

2516.30

1070.80

308828.56

1948.75

472.55

0.00

0.00

0.00

B-4DH

B-4DH

B-4DH

04.07.04

276569.81

216.00

164.97

274334.69

1845.75

715.65

287467.34

1903.22

456.98

418837.06

1479.48

0.00

25.07.04

836169.63

560.49

424.84

284747.75

1788.47

720.84

289216.06

1798.73

451.10

866436.50

2348.86

0.00

01.08.04

641055.19

419.67

330.61

291540.78

1834.70

757.95

259138.30

1619.00

417.31

759369.50

2056.49

0.00

16.08.04

0.00

0.00

0.00

338907.09

2288.20

894.80

252355.59

1688.20

411.10

648688.62

1892.40

0.00

04.09.04

30691.72

23.04

16.90

115003.77

896.26

448.75

167780.22

1267.12

331.02

287106.56

966.21

0.00


44

TableC.2

Continued

B-1H

B-2H

B-3H

B-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

20.09.04

0.00

0.00

0.00

327852.09

2276.71

764.27

469231.97

3416.17

860.64

1483094.50

2225.69

0.00

01.10.04

124535.12

197.68

99.66

309232.72

2173.17

768.79

431317.38

3275.12

1039.74

1511658.00

2262.71

0.00

01.11.04

189181.86

298.99

159.14

204679.27

1667.13

735.53

333573.12

2882.18

1124.56

1253123.60

1703.75

0.00

04.12.04

127598.02

193.46

102.51

58419.94

561.37

436.27

342012.75

2917.83

1144.75

1097193.40

1550.82

224.20

05.01.05

121996.63

295.39

240.56

141410.58

811.78

526.93

317469.78

2149.55

1547.03

960114.81

1395.04

298.88

15.01.05

138778.61

342.78

338.40

140657.25

826.63

669.63

264931.31

1828.09

1601.95

146825.30

216.19

54.58

29.01.05

197652.69

455.98

453.78

178229.11

981.68

795.25

245949.48

1577.73

1392.92

879442.25

1222.68

320.77

02.02.05

214585.09

501.64

516.46

155552.47

863.69

726.52

294317.62

1923.76

1756.14

747931.19

1048.01

285.60

05.03.05

95281.07

213.43

229.44

153787.45

821.21

696.92

312298.00

1961.83

1809.69

797292.69

1073.36

295.36

24.03.05

197008.00

436.10

500.30

165797.20

871.40

816.30

311008.91

1925.00

1956.60

848332.50

1125.70

341.60

25.03.05

72027.11

157.05

165.90

169138.94

875.44

781.04

334710.37

2040.06

1976.36

864541.88

1129.73

326.50

03.04.05

54870.37

136.52

118.40

177228.63

1246.70

1029.88

297130.72

2014.62

2481.39

728539.19

1090.63

590.96

27.04.05

0.00

0.00

0.00

199348.92

1367.00

1213.47

317268.59

2129.10

2977.23

739888.00

1080.46

630.83

03.05.05

21218.06

52.56

55.52

197343.92

1391.06

1270.89

296830.59

2091.71

3226.09

709041.88

1062.02

639.58

02.06.05

0.00

0.00

0.00

125296.70

939.30

815.70

277095.69

2077.20

3044.80

638202.69

1041.00

767.80

03.06.05

0.00

0.00

0.00

204793.58

1413.32

1314.36

285359.56

1981.44

3286.60

618406.50

927.30

732.09

27.06.05

0.00

0.00

0.00

203524.92

1349.94

1305.70

219996.42

1456.16

2618.66

586237.06

846.28

695.54

01.07.05

0.00

0.00

0.00

234161.39

1517.08

1404.52

304389.66

1955.84

3460.22

530835.06

922.77

908.23

11.07.05

0.00

0.00

0.00

233161.02

1554.78

1350.02

297077.59

1967.57

3265.95

533914.31

955.67

881.60

18.07.05

0.00

0.00

0.00

207426.34

1365.75

1506.35

253419.84

1653.77

2884.82

504607.50

890.69

865.85

30.07.05

0.00

0.00

0.00

180118.94

1122.50

1800.23

263326.69

1629.93

3084.33

528658.62

884.23

929.80

02.08.05

2523.45

16.70

34.40

196966.91

1258.20

1746.60

288923.84

1833.15

3002.70

474972.34

878.85

884.15

04.08.05

46051.90

299.50

608.20

191120.80

1209.00

1676.50

280442.59

1761.90

2883.00

474255.41

869.00

873.50

05.08.05

31115.74

198.03

447.05

141978.61

1127.96

1826.05

250770.67

1572.27

2734.08

450988.28

819.88

885.44

02.09.05

16708.96

50.88

79.55

132232.62

1017.20

1687.04

274630.09

1588.30

3287.07

361107.53

644.17

715.15

17.09.05

19331.27

42.22

38.18

159929.23

1292.61

1942.81

305733.47

1981.56

3905.34

407846.59

806.32

800.68

05.10.05

38510.79

87.37

76.70

158862.64

1255.86

2108.06

281619.25

1843.65

3756.75

334579.66

735.02

805.75

09.11.05

0.00

0.00

0.00

143640.38

1289.47

1896.69

253625.64

1873.83

3329.20

240977.41

672.37

594.14

02.12.05

0.00

0.00

0.00

264142.19

1634.20

2133.00

385361.31

2437.80

3803.20

0.00

0.00

0.00

03.12.05

0.00

0.00

0.00

243599.56

1448.08

2239.52

328822.62

1999.84

3684.01

38369.55

205.36

240.73

01.01.06

0.00

0.00

0.00

221884.06

1233.95

2523.90

287626.41

1635.60

3997.25

211774.30

541.30

702.60

B-1BH

B-1BH

B-1BH


45

TableC.2

Continued

B-1H

B-2H

B-3H

B-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

03.01.06

136041.88

1500.35

0.00

193222.92

1186.32

2201.09

142088.62

874.27

2025.75

67092.99

650.32

761.56

20.01.06

417466.53

4245.39

0.00

156971.48

920.81

1725.27

206444.84

1228.89

2764.24

87493.42

719.51

822.16

04.02.06

598881.75

5463.42

0.00

244739.69

1365.58

2802.18

233826.64

1333.81

3293.39

101080.73

717.82

875.93

26.02.06

552450.00

5154.52

0.00

227808.89

1283.36

2691.32

187242.95

1077.58

2842.32

102141.82

742.06

926.64

04.03.06

610125.88

5996.16

0.00

249719.47

1448.38

2719.51

256283.20

1518.45

3586.84

104540.11

804.35

950.19

06.04.06

656747.62

6121.43

0.00

230537.06

1301.85

2780.02

258694.41

1492.95

4023.63

104930.90

762.17

966.42

01.05.06

608231.50

5951.28

0.00

219491.92

1266.60

2914.02

253296.97

1494.18

4319.93

94289.90

718.27

944.72

08.05.06

586376.00

5531.21

532.55

247377.14

1409.02

3180.95

182666.03

1083.02

3943.42

21511.94

156.11

243.12

05.06.06

456823.09

4062.06

2304.67

227918.08

1249.91

2496.34

24898.61

192.42

927.13

26037.03

181.27

333.76

02.07.06

412151.56

3769.62

2219.66

235780.44

1381.58

3060.42

0.00

0.00

0.00

33564.82

247.63

502.28

02.08.06

478591.53

4115.01

2376.10

248495.75

1285.93

2747.86

0.00

0.00

0.00

34613.51

226.02

441.54

16.08.06

539491.31

4385.10

2682.60

224255.80

1040.70

2483.10

0.00

0.00

0.00

36918.20

216.20

471.90

17.08.06

485091.06

3855.41

2951.91

223587.84

1212.76

2747.68

0.00

0.00

0.00

27476.59

186.84

387.89

01.09.06

408392.97

3466.41

3496.65

153565.42

1339.06

2759.29

0.00

0.00

0.00

18989.44

209.13

394.48

14.09.06

430592.75

3292.05

3370.42

149126.58

1045.99

2238.39

1.29

0.01

0.05

23525.30

194.78

373.17

01.10.06

467306.72

3402.48

2287.43

186820.61

1138.97

1539.52

0.00

0.00

0.00

21139.62

164.19

203.00

10.10.06

474211.31

3502.00

2441.08

139009.58

875.20

1265.76

0.00

0.00

0.00

34540.98

274.66

366.32

15.10.06

472619.34

3415.28

2898.64

147205.48

884.19

1806.47

0.00

0.00

0.00

25267.33

188.69

351.30

01.11.06

224395.47

1641.99

2985.51

177861.36

1034.29

1688.50

0.00

0.00

0.00

5882.08

43.40

78.93

09.11.06

241203.00

1767.90

3793.10

161710.75

944.85

2041.60

0.00

0.00

0.00

5092.20

37.70

92.65

11.11.06

239171.78

1755.25

3849.45

160463.33

941.32

2105.77

0.00

0.00

0.00

7859.07

58.17

147.20

17.11.06

254435.89

1484.50

3216.09

194830.64

738.83

1614.04

1283.96

8.58

75.54

9667.83

44.07

108.44

01.12.06

254435.89

1484.50

3216.09

194830.64

738.83

1614.04

1283.96

8.58

75.54

9667.83

44.07

108.44

46


fortemplate

D

D-1H

D-2H

D-3H

D-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

06.11.97

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

07.11.97

482594.69

4347.70

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

22.11.97

634722.75

5601.95

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

09.12.97

651415.00

5433.42

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

24.12.97

693727.75

5481.02

0.00

17973.92

161.93

0.00

0.00

0.00

0.00

0.00

0.00

0.00

11.01.98

703808.31

5169.75

0.00

681178.94

5923.12

0.00

0.00

0.00

0.00

0.00

0.00

0.00

11.02.98

53044.25

370.62

0.00

59855.40

465.39

0.00

0.00

0.00

0.00

0.00

0.00

0.00

07.03.98

563920.38

3487.88

0.00

643627.25

3719.52

0.00

0.00

0.00

0.00

0.00

0.00

0.00

30.03.98

772098.50

4638.90

0.00

1048260.30

5699.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

31.03.98

906735.00

5427.25

0.00

1057381.40

5702.45

0.00

0.00

0.00

0.00

0.00

0.00

0.00

02.04.98

848627.19

4933.31

0.00

1112753.50

5633.91

0.00

0.00

0.00

0.00

0.00

0.00

0.00

27.04.98

880581.44

4935.89

0.00

1206619.90

5681.21

0.00

0.00

0.00

0.00

0.00

0.00

0.00

06.05.98

867679.62

4680.11

0.00

1211440.40

5290.28

0.00

0.00

0.00

0.00

0.00

0.00

0.00

27.05.98

912405.63

4782.00

0.00

1294097.60

5350.40

0.00

0.00

0.00

0.00

0.00

0.00

0.00

28.05.98

859087.88

4473.52

0.00

1210434.20

4944.62

0.00

0.00

0.00

0.00

0.00

0.00

0.00

02.06.98

901975.50

4465.23

0.00

1260391.40

5120.55

0.00

0.00

0.00

0.00

0.00

0.00

0.00

17.06.98

793937.75

3930.38

0.00

1019898.10

4133.27

0.00

0.00

0.00

0.00

245820.20

2208.52

0.00

24.06.98

727607.50

3602.00

0.00

1076314.60

4254.20

0.00

0.00

0.00

0.00

602013.00

5423.50

0.00

25.06.98

861252.94

3201.69

0.00

1001757.80

3539.79

0.00

0.00

0.00

0.00

513925.72

4468.93

0.00

03.07.98

832414.25

3293.67

0.00

935036.56

3505.77

0.00

0.00

0.00

0.00

533783.56

4371.02

0.00

21.07.98

995027.25

3475.58

0.00

1108152.80

3597.58

0.00

0.00

0.00

0.00

719991.25

5324.64

0.00

04.08.98

1011028.90

3194.72

0.00

1099742.60

3115.47

0.00

0.00

0.00

0.00

698047.12

4836.60

0.00

31.08.98

1093687.20

3330.30

0.00

732314.31

1908.60

0.00

0.00

0.00

0.00

679744.13

4918.00

0.00

01.09.98

1082835.00

3318.10

0.00

983293.19

2578.90

0.00

0.00

0.00

0.00

724080.19

5271.80

0.00

02.09.98

1231525.10

3739.60

0.00

783170.38

2044.38

0.00

0.00

0.00

0.00

802162.31

5231.84

0.00

22.09.98

1194599.90

3627.76

0.00

457735.16

1196.18

0.00

0.00

0.00

0.00

811804.81

4907.19

0.00

01.10.98

1098482.80

3457.70

0.00

505660.44

1367.17

0.00

0.00

0.00

0.00

702531.06

4158.43

0.00

02.10.98

717291.81

2191.86

0.00

875452.81

2306.14

0.00

0.00

0.00

0.00

537129.12

3098.66

0.00

15.10.98

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

17.10.98

594478.25

2117.87

0.00

694604.75

2125.07

0.00

0.00

0.00

0.00

611066.81

3991.46

0.00

01.11.98

923285.19

2949.87

0.00

1282534.10

3386.90

0.00

0.00

0.00

0.00

778479.88

4878.56

0.00

02.12.98

830792.94

2552.19

0.00

1043797.70

2362.53

0.00

0.00

0.00

0.00

826323.13

4118.65

0.00


47

TableC.3

Continued

D-1H

D-2H

D-3H

D-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

25.12.98

859366.87

2472.57

0.00

239297.81

507.17

0.00

0.00

0.00

0.00

1175661.00

5099.59

0.00

01.01.99

963635.69

2716.87

2.73

218359.27

453.07

0.43

0.00

0.00

0.00

1054461.80

4479.50

39572.00

04.01.99

1113224.60

2721.38

2.73

193607.20

354.42

0.34

0.00

0.00

0.00

1287846.50

4731.39

4.73

19.01.99

1230078.20

3052.75

3.10

42229.15

64.60

0.05

0.00

0.00

0.00

1492276.80

4732.85

27485.00

21.01.99

1005560.50

2930.66

2.94

809949.62

1431.36

1.42

0.00

0.00

0.00

1537928.50

4871.52

4.88

01.02.99

773145.94

2627.24

2.64

1469614.00

2912.32

2.92

0.00

0.00

0.00

1413092.50

5205.60

5.21

25.02.99

856332.19

2540.66

2.56

0.00

0.00

0.00

0.00

0.00

0.00

1604926.60

5167.80

5.18

01.03.99

938827.50

2616.35

2.63

24305.73

41.83

0.05

0.00

0.00

0.00

1444791.30

4992.77

5.00

05.03.99

911585.31

2533.59

2.53

1239603.20

2348.80

2.35

0.00

0.00

0.00

774935.75

4092.79

4.08

23.03.99

1259303.00

2774.60

2.77

347957.06

543.53

0.53

0.00

0.00

0.00

784556.88

3225.80

3.23

26.03.99

1688736.40

3722.40

39632.00

0.00

0.00

0.00

0.00

0.00

0.00

526486.62

2203.10

39480.00

28.03.99

1811886.90

4026.13

4.03

0.00

0.00

0.00

0.00

0.00

0.00

539231.06

2274.95

2.28

01.04.99

1674755.20

4077.29

3.43

0.00

0.00

0.00

0.00

0.00

0.00

798303.75

3729.93

28157.00

02.05.99

1099421.10

3292.20

0.00

660556.62

1192.73

39479.00

0.00

0.00

0.00

1175284.80

5626.60

0.00

04.05.99

993199.00

3111.00

0.00

901381.00

1714.40

39630.00

0.00

0.00

0.00

1110580.80

5565.90

0.00

05.05.99

897740.75

2758.78

0.00

1230978.40

2304.73

2.33

0.00

0.00

0.00

752820.56

5063.86

0.00

18.05.99

840859.31

2649.87

0.00

1451744.90

2777.80

39662.00

0.00

0.00

0.00

638978.94

4771.90

0.00

20.05.99

840859.31

2649.87

0.00

1451744.90

2777.80

39662.00

0.00

0.00

0.00

638978.94

4771.90

0.00

21.05.99

887690.62

2832.90

0.00

1519669.80

2944.80

2.90

0.00

0.00

0.00

647011.69

4894.40

0.00

22.05.99

882073.62

2863.54

0.00

1478532.00

2914.53

2.94

0.00

0.00

0.00

639979.94

4923.99

0.00

01.06.99

1097075.10

3220.32

0.15

1461584.60

2405.22

0.13

0.00

0.00

0.00

611856.56

4989.88

0.24

22.06.99

1056810.60

3038.51

3.04

1484433.60

2596.23

2.61

0.00

0.00

0.00

685015.69

5009.13

5.03

01.07.99

904267.00

2608.34

2.61

1177572.40

2039.49

2.04

0.00

0.00

0.00

615845.50

4458.84

4.46

15.07.99

1029620.30

3209.46

1.99

1287626.80

2036.23

1.34

0.00

0.00

0.00

681263.69

4772.81

2.94

02.08.99

932779.62

3556.08

0.00

1437135.80

1972.10

0.00

0.00

0.00

0.00

817235.62

5527.52

0.00

06.08.99

979376.94

3819.45

0.00

844006.69

1111.68

0.00

0.00

0.00

0.00

777454.81

5025.44

0.00

01.09.99

677535.81

3961.50

0.00

302341.09

265.15

0.00

0.00

0.00

0.00

951216.12

5417.15

0.00

03.09.99

651112.69

3862.75

0.00

292375.69

260.15

0.00

0.00

0.00

0.00

904708.38

5227.40

0.00

05.09.99

716343.69

4250.44

0.00

135238.31

122.65

0.00

0.00

0.00

0.00

914210.38

5291.20

0.00

22.09.99

954310.63

4979.70

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1207182.00

6135.60

0.00

02.10.99

784123.00

4693.90

0.00

0.00

0.00

0.00

0.00

0.00

0.00

944661.00

5090.85

0.00

03.10.99

667063.50

4412.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1045038.10

5655.30

0.00


48

TableC.3

Continued

D-1H

D-2H

D-3H

D-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

04.10.99

673731.81

4378.51

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1067017.50

5675.01

0.00

14.10.99

654769.25

4191.70

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1038870.90

5441.07

0.00

17.10.99

466904.56

3488.69

0.00

0.00

0.00

0.00

0.00

0.00

0.00

712007.56

4352.60

0.00

01.11.99

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

09.11.99

250872.30

1560.80

0.00

24778.40

39474.00

0.00

0.00

0.00

0.00

0.10

0.00

0.00

10.11.99

568419.75

4002.07

0.00

1427.97

2.03

0.00

0.00

0.00

0.00

621302.31

4745.90

0.00

13.11.99

643736.88

4079.09

0.00

0.00

0.00

0.00

0.00

0.00

0.00

717861.12

4875.28

0.00

01.12.99

792752.19

4524.09

0.00

54398.39

44.65

0.00

0.00

0.00

0.00

933317.88

4736.11

0.00

02.01.00

731703.56

3899.26

0.00

25313.98

19.50

0.00

0.00

0.00

0.00

785027.94

3532.89

0.00

01.02.00

689955.00

3892.10

0.00

110663.96

166.87

0.00

0.00

0.00

0.00

408562.38

1962.04

0.00

02.03.00

791919.38

4299.10

0.00

0.00

0.00

0.00

0.00

0.00

0.00

334606.00

1551.60

0.00

03.03.00

779049.81

4204.50

0.00

0.00

0.00

0.00

0.00

0.00

0.00

457145.00

2107.40

0.00

04.03.00

674112.69

3513.18

89.47

5562.47

5.82

0.00

0.00

0.00

0.00

1213773.80

3374.53

0.00

03.04.00

589174.69

3158.44

219.70

17368.89

24.44

0.00

0.00

0.00

0.00

763444.62

2145.57

45.04

01.05.00

1115472.20

5211.26

274.88

0.00

0.00

0.00

0.00

0.00

0.00

647711.25

1708.16

128.57

26.05.00

1140830.10

5124.50

387.58

0.00

0.00

0.00

0.00

0.00

0.00

574813.69

1524.12

114.70

02.06.00

919706.75

4479.09

0.00

0.00

0.00

0.00

0.00

0.00

0.00

531740.75

1321.34

99.45

11.06.00

1090498.20

4296.81

383.33

0.00

0.00

0.00

0.00

0.00

0.00

466980.84

1124.08

84.61

01.07.00

643231.50

2975.10

0.00

0.00

0.00

0.00

0.00

0.00

0.00

433562.09

1015.60

76.40

01.07.00

1069984.90

3047.24

68.13

0.00

0.00

0.00

0.00

0.00

0.00

526221.12

1190.89

103.10

02.08.00

1302930.80

3247.60

0.00

0.00

0.00

0.00

0.00

0.00

0.00

329428.81

726.00

67.40

03.08.00

523362.31

1269.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

332502.59

713.00

66.20

03.08.00

1377980.00

3569.14

0.00

0.00

0.00

0.00

0.00

0.00

0.00

363633.47

831.59

77.25

20.08.00

340077.94

910.07

0.00

0.00

0.00

0.00

0.00

0.00

0.00

115166.35

285.43

26.52

27.08.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

D-3AH

D-3AH

D-3AH

28.08.00

1119448.50

3070.66

0.00

0.00

0.00

0.00

203425.30

2295.96

0.00

277917.72

707.62

65.74

01.09.00

1436409.90

3712.31

0.00

0.00

0.00

0.00

484669.56

5257.77

0.00

0.00

0.00

0.00

10.09.00

1277103.20

3393.60

0.00

0.00

0.00

0.00

353468.81

3944.90

0.00

0.00

0.00

0.00

11.09.00

1306434.00

3312.26

0.00

0.00

0.00

0.00

492365.69

5231.59

0.00

0.00

0.00

0.00

21.09.00

0.00

0.00

0.00

0.00

0.00

0.00

473796.69

4823.40

0.00

0.00

0.00

0.00

22.09.00

870804.81

2312.79

71.97

0.00

0.00

0.00

462894.62

4954.32

0.00

0.00

0.00

0.00


49

TableC.3

Continued

D-1H

D-2H

D-3H

D-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

01.10.00

1454048.00

3627.53

270.32

0.00

0.00

0.00

474837.00

4973.80

0.00

0.00

0.00

0.00

03.11.00

1412481.60

3330.27

832.56

0.00

0.00

0.00

408755.19

4017.74

0.00

0.00

0.00

0.00

02.12.00

1513092.90

3475.81

868.95

0.00

0.00

0.00

292502.38

2787.77

0.00

0.00

0.00

0.00

03.01.01

917179.44

2382.79

970.09

396970.13

650.84

0.00

565763.69

3519.58

0.00

0.00

0.00

0.00

02.02.01

82387.59

291.79

291.79

698859.06

1125.61

0.00

1044330.20

4014.18

0.00

0.00

0.00

0.00

02.03.01

351841.81

1361.48

1361.48

657366.88

2197.96

0.00

1002522.40

3997.78

0.00

0.00

0.00

0.00

02.04.01

379457.22

1625.33

1625.33

586535.62

2197.40

0.00

975848.88

4340.57

0.00

0.00

0.00

0.00

02.05.01

434130.69

1836.72

1836.72

433528.94

1610.64

0.00

891285.81

3923.81

0.00

131223.16

918.37

15.89

01.06.01

478911.81

1921.40

1921.40

416898.50

1463.50

0.00

970886.12

4045.40

0.00

97768.90

880.00

0.00

01.06.01

460479.81

1918.86

1918.86

409979.06

1494.90

0.00

967311.62

4186.68

0.00

92166.36

861.64

0.00

07.06.01

294359.69

1521.40

1521.40

226384.20

1023.80

0.00

574790.31

3085.40

0.00

46732.20

541.90

0.00

07.06.01

421611.38

1774.57

2143.36

404837.44

1424.04

0.00

1128074.60

4182.33

0.00

141670.08

1186.63

0.00

18.06.01

466319.91

1343.10

2191.40

431720.41

1052.10

0.00

1743743.50

3899.70

0.00

207614.20

1264.90

0.00

19.06.01

481867.91

1614.27

2633.80

531679.44

1507.66

0.00

1622475.90

4241.69

0.00

253294.03

1753.01

0.00

02.07.01

201589.20

749.80

1078.90

320070.50

982.10

0.00

1154705.80

3334.70

0.00

197558.09

1554.30

0.00

03.07.01

203577.09

743.10

1069.30

320207.31

964.20

0.00

1165109.20

3302.10

0.00

198684.91

1534.10

0.00

04.07.01

261820.83

941.08

1354.26

382126.69

1133.64

0.00

1490515.80

4158.93

0.00

256410.36

1947.67

0.00

16.07.01

304210.50

1036.30

1491.30

425298.91

1195.30

0.00

1747836.80

4623.40

0.00

306163.00

2206.30

0.00

30.07.01

262820.81

1081.40

1556.15

335909.16

1140.25

0.00

1396948.80

4463.05

0.00

267573.34

2328.80

0.00

01.08.01

186157.83

822.58

1183.68

300722.75

1094.72

0.00

1210586.60

4167.68

0.00

184404.09

1716.46

88.30

11.08.01

0.00

0.00

0.00

330768.81

1188.68

0.00

1270754.00

4311.63

0.00

167141.09

1546.02

116.38

17.08.01

0.00

0.00

0.00

1435722.00

3568.09

0.00

1454326.20

7244.51

0.00

39079.18

357.54

95.04

02.09.01

0.00

0.00

0.00

1067190.50

2634.34

0.00

1194870.60

5883.16

0.00

26792.61

233.72

62.13

10.09.01

0.00

0.00

0.00

544238.69

1389.18

0.00

872633.00

4424.16

0.00

274.28

2.63

0.70

02.10.01

0.00

0.00

0.00

1402291.00

2467.31

0.00

1365567.60

5691.22

0.00

0.00

0.00

0.00

02.11.01

0.00

0.00

0.00

58981.44

91.05

0.00

623887.81

3223.48

0.00

192336.19

1353.70

66.15

04.12.01

0.00

0.00

0.00

0.00

0.00

0.00

795259.50

4302.52

0.00

375731.03

2436.49

270.72

30.12.01

0.00

0.00

0.00

0.00

0.00

0.00

1496359.40

4931.80

0.00

201952.44

1064.80

501.07

01.01.02

1900.86

4.88

7.00

52249.55

440.95

0.00

1592966.40

4301.49

0.00

227639.08

1236.68

692.13

03.02.02

0.00

0.00

0.00

294379.19

2323.66

0.00

1823807.50

4098.56

0.00

189060.00

933.53

389.60

12.02.02

0.00

0.00

0.00

290606.00

2029.80

0.00

1704181.10

3378.00

0.00

165892.91

699.20

240.40

13.02.02

0.00

0.00

0.00

350490.09

2527.48

0.00

821799.94

1730.14

0.00

30168.41

126.12

47.83


50

TableC.3

Continued

D-1H

D-2H

D-3H

D-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

01.03.02

0.00

0.00

0.00

133669.62

1006.28

0.00

445377.72

1295.86

0.00

0.10

0.00

0.00

02.04.02

0.00

0.00

0.00

903626.75

2366.46

0.00

1302201.10

3153.98

0.00

0.00

0.00

0.00

01.05.02

0.00

0.00

0.00

1791966.90

3770.35

0.00

1288236.10

2415.27

0.00

8057.31

43.27

23.81

02.06.02

0.00

0.00

0.00

1687394.10

2924.09

0.00

1393787.40

2838.95

10.76

0.00

0.00

0.00

02.07.02

0.00

0.00

0.00

1511715.90

2374.70

0.00

2160150.00

3802.27

40.90

0.00

0.00

0.00

08.07.02

0.00

0.00

0.00

2123688.00

3399.07

0.00

1914850.60

3526.37

42.17

0.00

0.00

0.00

11.07.02

0.00

0.00

0.00

2240421.80

3522.30

0.00

1792896.60

3240.15

38.95

0.00

0.00

0.00

15.07.02

0.00

0.00

0.00

1642265.80

2608.55

0.00

1982295.10

3712.72

53.91

0.00

0.00

0.00

02.08.02

0.00

0.00

0.00

1541120.80

2349.72

0.00

1414883.20

3617.55

130.33

0.00

0.00

0.00

14.08.02

4891.85

13.38

21.23

1471683.50

2366.76

0.00

1360278.10

4165.72

214.70

0.00

0.00

0.00

01.09.02

0.00

0.00

0.00

1920950.90

3070.30

0.00

1320879.50

4926.10

339.30

0.00

0.00

0.00

02.09.02

0.00

0.00

0.00

1561787.00

2636.71

0.00

1251140.20

4863.84

341.93

0.00

0.00

0.00

15.09.02

0.00

0.00

0.00

1697935.80

2918.81

26.57

1048468.50

4988.23

428.95

0.00

0.00

0.00

01.10.02

0.00

0.00

0.00

1810586.40

2798.00

0.00

608154.50

4864.23

771.87

20461.68

108.90

47.02

08.10.02

0.00

0.00

0.00

918516.56

1362.53

0.00

657396.62

4720.07

929.86

0.00

0.00

0.00

14.10.02

0.00

0.00

0.00

809332.44

1230.87

0.00

971862.31

4471.81

900.79

0.00

0.00

0.00

02.11.02

0.00

0.00

0.00

600903.19

917.94

0.00

1046266.40

4163.01

742.11

0.00

0.00

0.00

17.11.02

0.00

0.00

0.00

1162317.40

1648.47

0.00

1087158.00

4478.87

968.06

0.00

0.00

0.00

02.12.02

0.00

0.00

0.00

1367101.60

1872.42

0.00

333380.47

2093.82

953.90

0.00

0.00

0.00

24.12.02

0.00

0.00

0.00

568636.00

674.51

0.00

467139.00

2510.06

1307.55

0.00

0.00

0.00

01.01.03

0.00

0.00

0.00

2123520.80

2596.20

0.00

468194.59

2650.10

1096.30

0.00

0.00

0.00

02.01.03

0.00

0.00

0.00

2765573.80

3374.29

0.00

482664.62

2726.01

992.13

0.00

0.00

0.00

12.01.03

0.00

0.00

0.00

2760706.20

3385.10

0.00

480798.94

2729.13

836.17

0.00

0.00

0.00

20.01.03

0.00

0.00

0.00

1262419.80

1390.52

0.00

514424.97

2625.66

1118.00

0.00

0.00

0.00

03.02.03

0.00

0.00

0.00

1607920.00

1972.35

0.00

435812.56

2847.32

1120.54

0.00

0.00

0.00

14.02.03

0.00

0.00

0.00

0.00

0.00

0.00

474425.47

2792.61

1144.79

0.00

0.00

0.00

01.03.03

0.00

0.00

0.00

2585765.00

3590.60

0.00

371074.41

2798.60

1127.20

0.00

0.00

0.00

06.03.03

0.00

0.00

0.00

2491754.00

3244.00

0.00

373298.00

2641.00

1060.00

0.00

0.00

0.00

07.03.03

0.00

0.00

0.00

2547394.50

3157.16

0.00

338249.19

2361.40

1074.68

0.00

0.00

0.00

03.04.03

0.00

0.00

0.00

1009213.10

1438.87

0.00

113557.03

935.30

454.70

0.00

0.00

0.00

04.05.03

0.00

0.00

0.00

2338925.20

3343.65

0.00

273687.69

2194.87

1166.87

0.00

0.00

0.00

03.06.03

0.00

0.00

0.00

2636706.00

4222.00

0.00

310204.00

2591.50

1245.00

0.00

0.00

0.00


51

TableC.3

Continued

D-1H

D-2H

D-3H

D-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

D-4AH

D-4AH

D-4AH

04.06.03

0.00

0.00

0.00

2275841.20

3575.32

0.00

288653.81

2363.57

997.82

154279.11

901.36

12.86

02.07.03

0.00

0.00

0.00

1973411.40

3536.78

0.00

242084.44

2262.44

1047.00

123890.22

831.89

0.00

10.07.03

0.00

0.00

0.00

2113501.50

3481.54

16.82

268195.31

2409.50

1668.77

126742.41

1093.46

0.00

02.08.03

0.00

0.00

0.00

1682888.60

2826.67

23.67

248651.22

2336.33

1796.33

114252.22

1138.33

0.00

11.08.03

0.00

0.00

0.00

2076117.50

3364.00

39596.00

261266.00

2357.00

1806.50

117106.00

1120.00

0.00

12.08.03

0.00

0.00

0.00

2112974.80

3781.95

31.60

231389.59

2203.15

1661.95

99693.05

1002.65

0.00

01.09.03

0.00

0.00

0.00

2581112.00

4308.80

40.30

237501.41

2114.50

1956.80

97096.70

907.70

0.00

02.09.03

0.00

0.00

0.00

2715142.00

4254.00

37.83

250948.39

2096.63

1845.49

102304.19

897.45

0.00

10.09.03

0.00

0.00

0.00

2835423.80

4424.50

40.95

252325.06

2099.95

1925.10

102779.25

898.15

0.00

12.09.03

0.00

0.00

0.00

2876642.00

4524.00

43.60

255075.59

2139.50

2040.00

102647.00

904.00

0.00

13.09.03

0.00

0.00

0.00

1885786.50

3007.90

29.30

257662.13

2114.60

2046.30

96039.40

828.77

0.00

16.09.03

0.00

0.00

0.00

1600349.90

2644.41

19.83

254587.27

1996.04

1523.25

107588.20

885.13

0.00

01.10.03

0.00

0.00

0.00

2307540.50

3883.62

37.06

306385.31

2127.42

1950.15

154112.58

971.07

0.00

24.10.03

0.00

0.00

0.00

2634214.50

4597.68

47.99

359989.78

2223.19

2121.04

198447.34

934.40

0.00

D-1CH

D-1CH

D-1CH

02.11.03

437029.00

2982.40

0.00

2309563.50

4121.29

48.92

254222.58

1603.80

1672.05

124303.70

596.13

0.00

20.11.03

672624.69

3696.79

6.05

2684299.50

4590.67

48.76

317122.19

1904.08

1763.71

83689.78

393.78

0.00

04.12.03

947049.19

3915.99

20.67

2291909.00

3911.70

40.59

222930.47

1297.00

1139.49

70835.95

333.40

0.00

09.12.03

1112175.20

4402.00

24.20

1197705.20

1955.30

39620.00

125621.60

703.00

654.40

33100.50

148.40

0.00

10.12.03

822476.69

3521.35

12.41

2345687.20

4008.97

39.31

106722.11

623.11

515.82

101327.12

478.10

0.00

18.12.03

943249.69

4199.77

0.00

2544623.80

4099.11

41.51

155572.28

854.67

720.50

97130.94

430.54

0.00

01.01.04

926781.06

3880.09

0.00

2561958.80

3884.84

36.43

201037.47

1075.77

892.26

119375.28

442.57

11.14

19.01.04

639189.19

2910.60

0.00

1442956.00

2379.70

19.80

223852.41

1411.40

1257.00

285079.59

486.80

148.00

20.01.04

933163.63

3873.12

0.00

2734560.50

4113.09

37.84

318283.59

1826.82

1776.63

252684.11

393.42

132.49

02.02.04

1080526.40

3869.54

0.00

2269730.20

2918.28

0.00

181173.55

1131.62

1026.50

201120.75

317.81

108.71

01.03.04

1139855.10

3893.78

0.00

2644206.20

3445.47

0.00

208525.55

1436.60

1337.17

186986.73

321.69

110.34

01.04.04

1138319.00

4178.97

0.00

2706039.00

3393.29

0.00

203386.56

1516.58

1290.65

197368.52

368.94

115.86

01.05.04

1059078.90

4071.25

0.00

2492086.20

3340.75

0.00

181701.97

1422.04

1310.01

197928.97

386.64

131.00

02.06.04

771335.81

4268.49

0.00

1816846.10

3936.73

0.00

214866.66

1536.44

1417.94

700348.25

749.12

100.56

02.07.04

793594.62

4426.25

0.00

1920207.40

4192.10

0.00

217640.14

1567.85

1589.70

731175.50

788.15

116.25

04.07.04

694045.38

4051.38

0.00

1683521.40

3767.83

0.00

256148.52

1699.72

1506.10

632108.87

698.02

102.81


52

TableC.3

Continued

D-1H

D-2H

D-3H

D-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

25.07.04

637050.19

3786.51

0.00

1847040.90

3797.23

0.00

346727.78

1875.87

1451.64

668214.50

678.33

105.47

01.08.04

584582.38

3472.31

0.00

1536201.60

3213.01

0.00

336780.84

1825.66

1453.10

638557.19

645.49

103.46

16.08.04

532935.88

3409.10

0.00

1711845.00

3788.40

0.00

345951.41

2014.50

1514.50

608592.31

665.00

100.40

17.08.04

205245.48

1374.42

0.00

677522.19

1571.61

0.00

130747.65

794.45

655.63

16185.24

18.41

3.07

04.09.04

248525.97

1823.21

0.00

762001.13

1968.26

0.00

111584.48

780.04

790.22

79899.63

109.43

17.83

20.09.04

493800.81

3406.65

0.00

1693418.30

4042.25

0.00

114410.80

715.33

1946.16

532089.75

621.68

86.63

01.10.04

641540.25

3288.58

0.00

1653677.50

3948.53

0.00

105677.02

893.76

1277.84

633997.56

742.95

108.53

01.11.04

652898.94

3531.68

0.00

826961.12

3736.68

303.67

98877.38

892.11

1301.00

161780.19

197.86

28.95

04.12.04

760600.31

4062.07

0.00

477828.50

3395.09

479.99

118225.40

1061.13

1553.67

60945.88

72.22

10.79

05.01.05

311542.75

2523.97

275.85

671557.69

3601.54

824.82

104257.21

1084.33

1765.76

1077862.60

985.66

100.38

15.01.05

312912.44

2586.51

341.66

579814.69

3168.85

883.49

102376.41

1085.40

2152.02

1050713.10

979.59

121.36

29.01.05

328074.31

2548.47

338.43

610631.56

3131.43

877.00

70156.37

703.67

1397.75

1087147.80

951.50

118.47

02.02.05

327815.78

2564.24

353.13

611836.31

3164.61

919.80

85557.95

858.65

1778.46

1093903.60

965.14

124.54

05.03.05

324320.06

2439.00

339.39

697951.00

3471.34

1019.02

99854.86

966.41

2004.04

1067940.90

905.93

118.14

24.03.05

325777.59

2413.30

370.20

609301.19

2985.50

965.60

48464.40

460.60

1059.20

1057507.50

883.60

127.00

25.03.05

326989.81

2385.38

348.40

658505.75

3177.68

979.53

47073.01

440.67

965.22

1078502.00

888.04

121.65

03.04.05

383386.84

2669.86

436.57

406354.59

2710.91

1134.84

185615.59

925.84

1286.97

1209124.40

915.27

149.78

27.04.05

378846.69

2571.64

454.24

386835.38

2513.91

1136.86

196873.14

955.40

1433.47

1230805.80

908.13

160.46

03.05.05

373406.12

2605.97

473.52

438420.41

2930.39

1365.15

208875.50

1041.94

1609.11

1201868.80

910.01

165.62

02.06.05

370234.59

2747.20

474.70

483768.19

3438.10

1519.70

145236.20

771.60

1131.10

1311365.20

1057.70

182.80

03.06.05

383537.47

2619.91

484.61

554019.62

3612.39

1711.43

0.00

0.00

0.00

1293048.40

960.76

177.54

27.06.05

373436.62

2454.20

472.84

537210.38

3382.26

1667.08

0.00

0.00

0.00

956781.62

682.20

131.30

01.07.05

417571.12

2675.84

493.19

415408.94

3091.47

2038.16

0.00

0.00

0.00

1090090.40

759.33

139.94

11.07.05

422361.97

2787.95

481.68

420196.31

3221.23

1990.57

0.00

0.00

0.00

1082292.80

776.52

134.15

18.07.05

407382.19

2652.72

482.75

374775.44

2830.36

1837.83

0.00

0.00

0.00

1038511.00

734.78

133.75

30.07.05

378027.50

2331.50

459.30

351255.59

2514.17

1773.40

0.00

0.00

0.00

939997.75

630.00

124.17

02.08.05

378808.75

2395.85

408.60

362173.69

2659.80

1622.00

0.00

0.00

0.00

1023053.50

703.50

120.05

04.08.05

428700.81

2684.20

457.10

423154.81

3077.20

1874.50

0.00

0.00

0.00

1095555.50

745.60

127.00

05.08.05

415669.31

2581.15

472.92

389968.50

2811.27

1839.96

0.00

0.00

0.00

1054125.00

711.66

130.36

02.09.05

194184.45

1481.15

478.16

309780.78

2003.04

1848.25

0.00

0.00

0.00

955209.81

615.66

116.15

17.09.05

233014.03

1895.28

531.22

372436.03

2501.75

2065.20

0.00

0.00

0.00

1126142.60

774.05

126.68

05.10.05

221121.48

1807.80

520.89

377347.62

2426.42

2153.78

0.00

0.00

0.00

1086901.80

734.79

123.67


53

TableC.3

Continued

D-1H

D-2H

D-3H

D-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

09.11.05

90123.32

828.89

187.06

211264.06

1576.65

1395.07

0.00

0.00

0.00

918657.88

411.24

0.00

02.12.05

90291.20

884.10

162.30

399897.31

3148.90

2435.20

0.00

0.00

0.00

487242.31

210.70

0.00

03.12.05

67036.39

624.43

123.76

219792.47

1649.34

1329.26

0.00

0.00

0.00

299479.06

113.55

0.00

01.01.06

34333.25

302.90

85.35

0.00

0.00

0.00

0.00

0.00

0.00

205725.41

74.05

0.00

03.01.06

18019.06

205.88

73.89

0.00

0.00

0.00

0.00

0.00

0.00

205305.86

62.08

0.00

20.01.06

94015.22

1058.61

370.75

258272.27

1905.61

2131.46

0.00

0.00

0.00

3409.49

1.00

0.00

04.02.06

118809.68

1283.60

500.86

355002.75

2521.64

3069.99

0.00

0.00

0.00

0.00

0.00

0.00

D-3BH

D-3BH

D-3BH

26.02.06

107840.24

1176.24

514.70

0.00

0.00

0.00

315889.59

2178.54

0.00

0.00

0.00

0.00

04.03.06

191220.95

1346.29

538.20

208939.83

1524.41

1785.77

388384.00

2767.27

0.00

0.00

0.00

0.00

06.04.06

150486.86

1034.14

474.76

327022.12

2350.28

3049.30

412957.25

3005.16

0.00

0.00

0.00

0.00

01.05.06

167123.11

1170.88

571.88

315520.09

2320.12

3235.43

376695.50

2867.47

0.00

0.00

0.00

0.00

08.05.06

159126.78

1122.21

565.59

307970.41

2233.95

3018.38

462904.25

3440.33

0.00

24377.50

7.07

0.00

05.06.06

56325.19

595.43

482.29

249027.67

1749.39

1943.50

633437.56

4390.59

0.00

323100.25

105.11

0.00

02.07.06

54229.98

462.34

300.67

243900.59

1764.48

1813.00

677678.31

4521.71

0.00

52154.34

18.27

0.00

02.08.06

80086.99

598.91

331.29

207667.91

1242.02

1199.85

728584.06

4573.87

0.00

0.00

0.00

0.00

16.08.06

85429.80

603.60

353.50

388872.69

2164.70

2173.20

763006.63

4521.40

0.00

0.00

0.00

0.00

17.08.06

73773.20

564.46

321.97

341549.47

2059.07

2012.88

668847.44

4277.76

75.36

0.00

0.00

0.00

01.09.06

62213.80

588.55

319.45

294167.12

2192.25

2039.60

536077.56

4253.34

178.62

0.00

0.00

0.00

14.09.06

63084.23

539.31

297.53

285477.69

1920.42

1816.37

549247.94

3932.43

167.81

0.00

0.00

0.00

01.10.06

45977.22

373.18

127.71

310911.88

1989.74

1337.52

529248.44

3601.72

232.09

0.00

0.00

0.00

10.10.06

72403.46

596.46

207.90

309078.38

2006.00

1398.32

504331.09

3484.26

232.52

0.00

0.00

0.00

15.10.06

48203.38

383.66

159.20

160316.78

1042.80

891.68

475859.75

3212.82

260.56

0.00

0.00

0.00

01.11.06

12019.08

93.82

35.64

289382.91

1807.71

1345.11

445838.88

2968.48

211.19

0.00

0.00

0.00

09.11.06

60496.10

480.70

210.50

293290.66

1836.90

1610.10

459368.06

3062.50

257.00

0.00

0.00

0.00

11.11.06

60105.18

479.68

214.75

293359.31

1841.03

1649.37

454273.81

3034.60

260.32

0.00

0.00

0.00

17.11.06

89226.15

563.66

249.26

351398.16

1742.51

1542.68

529939.25

2796.33

236.97

0.00

0.00

0.00

01.12.06

89226.15

563.66

249.26

351398.16

1742.51

1542.68

529939.25

2796.33

236.97

0.00

0.00

0.00

54


fortemplate

E

E-1H

E-2H

E-3H

E-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

06.11.97

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

22.09.98

0.00

0.00

0.00

0.00

0.00

0.00

276690.50

2448.63

0.00

0.00

0.00

0.00

01.10.98

0.00

0.00

0.00

0.00

0.00

0.00

551892.63

4845.37

0.00

0.00

0.00

0.00

02.10.98

0.00

0.00

0.00

0.00

0.00

0.00

428231.34

3554.56

0.00

0.00

0.00

0.00

15.10.98

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

17.10.98

0.00

0.00

0.00

0.00

0.00

0.00

387419.41

3764.12

0.00

0.00

0.00

0.00

01.11.98

0.00

0.00

0.00

0.00

0.00

0.00

553991.38

4639.44

118.26

0.00

0.00

0.00

02.12.98

0.00

0.00

0.00

0.00

0.00

0.00

323734.78

2606.31

192.12

0.00

0.00

0.00

25.12.98

0.00

0.00

0.00

0.00

0.00

0.00

397652.13

3024.04

234.63

0.00

0.00

0.00

01.01.99

0.00

0.00

0.00

0.00

0.00

0.00

396036.47

2971.23

230.53

0.00

0.00

0.00

04.01.99

0.00

0.00

0.00

0.00

0.00

0.00

464336.50

2992.77

232.20

0.00

0.00

0.00

19.01.99

0.00

0.00

0.00

0.00

0.00

0.00

426692.66

2839.95

401.40

0.00

0.00

0.00

21.01.99

0.00

0.00

0.00

0.00

0.00

0.00

318231.37

2560.06

561.97

0.00

0.00

0.00

01.02.99

0.00

0.00

0.00

0.00

0.00

0.00

278028.88

2614.05

540.94

0.00

0.00

0.00

25.02.99

0.00

0.00

0.00

0.00

0.00

0.00

334300.88

2749.56

563.16

0.00

0.00

0.00

01.03.99

0.00

0.00

0.00

0.00

0.00

0.00

353661.25

2754.88

564.28

0.00

0.00

0.00

05.03.99

0.00

0.00

0.00

0.00

0.00

0.00

369519.84

2869.77

587.78

0.00

0.00

0.00

23.03.99

0.00

0.00

0.00

0.00

0.00

0.00

603272.38

3698.37

757.50

0.00

0.00

0.00

26.03.99

0.00

0.00

0.00

0.00

0.00

0.00

616873.12

3766.15

771.40

0.00

0.00

0.00

28.03.99

0.00

0.00

0.00

0.00

0.00

0.00

587979.19

3623.35

742.10

0.00

0.00

0.00

01.04.99

0.00

0.00

0.00

0.00

0.00

0.00

515051.56

3405.53

734.84

0.00

0.00

0.00

02.05.99

0.00

0.00

0.00

0.00

0.00

0.00

302976.09

2321.77

693.53

0.00

0.00

0.00

04.05.99

0.00

0.00

0.00

0.00

0.00

0.00

302253.41

2423.70

724.00

0.00

0.00

0.00

05.05.99

0.00

0.00

0.00

0.00

0.00

0.00

310856.25

2443.66

729.93

0.00

0.00

0.00

17.05.99

0.00

0.00

0.00

0.00

0.00

0.00

310856.25

2443.66

729.93

0.00

0.00

0.00

18.05.99

0.00

0.00

0.00

0.00

0.00

0.00

291579.75

2351.90

702.53

0.00

0.00

0.00

20.05.99

0.00

0.00

0.00

0.00

0.00

0.00

291579.75

2351.90

702.53

0.00

0.00

0.00

21.05.99

0.00

0.00

0.00

0.00

0.00

0.00

309191.19

2526.00

754.50

0.00

0.00

0.00

22.05.99

0.00

0.00

0.00

0.00

0.00

0.00

277158.16

2304.91

688.48

0.00

0.00

0.00

01.06.99

0.00

0.00

0.00

0.00

0.00

0.00

236400.11

1908.24

635.11

0.00

0.00

0.00

22.06.99

0.00

0.00

0.00

0.00

0.00

0.00

200601.39

1635.84

527.97

0.00

0.00

0.00

01.07.99

0.00

0.00

0.00

0.00

0.00

0.00

169396.05

1363.72

440.13

0.00

0.00

0.00


55

TableC.4

Continued

E-1H

E-2H

E-3H

E-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

15.07.99

0.00

0.00

0.00

0.00

0.00

0.00

129747.39

1028.68

331.99

0.00

0.00

0.00

02.08.99

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

06.08.99

0.00

0.00

0.00

0.00

0.00

0.00

305675.22

2531.57

451.84

0.00

0.00

0.00

01.09.99

0.00

0.00

0.00

0.00

0.00

0.00

443703.69

3413.45

699.15

0.00

0.00

0.00

03.09.99

0.00

0.00

0.00

0.00

0.00

0.00

325509.16

2541.80

520.60

0.00

0.00

0.00

05.09.99

446933.97

2837.91

1.07

0.00

0.00

0.00

378901.69

2888.42

621.37

0.00

0.00

0.00

22.09.99

1056555.10

5625.70

0.00

0.00

0.00

0.00

472926.69

3137.00

688.60

0.00

0.00

0.00

22.09.99

569723.19

3380.69

0.00

0.00

0.00

0.00

357853.12

2629.00

577.10

0.00

0.00

0.00

02.10.99

998946.25

4976.25

0.00

0.00

0.00

0.00

537025.69

3698.15

924.65

0.00

0.00

0.00

03.10.99

1002940.20

4477.70

0.00

0.00

0.00

0.00

513245.00

3471.80

979.20

0.00

0.00

0.00

04.10.99

1070956.90

4527.96

0.00

0.00

0.00

0.00

457018.31

3101.83

874.87

0.00

0.00

0.00

14.10.99

1465503.90

5390.57

0.00

0.00

0.00

0.00

472646.69

3403.80

960.00

0.00

0.00

0.00

17.10.99

721408.94

3163.71

0.00

0.00

0.00

0.00

282177.44

2377.99

670.72

0.00

0.00

0.00

01.11.99

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

09.11.99

104432.30

439.80

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

10.11.99

952504.56

4593.17

0.00

0.00

0.00

0.00

227842.23

2384.30

881.90

0.00

0.00

0.00

13.11.99

879391.44

3771.47

0.00

383079.84

2427.06

0.00

151161.22

1386.21

433.31

0.00

0.00

0.00

01.12.99

1016480.70

3920.08

0.00

1026513.30

4901.34

0.00

174031.31

1343.59

466.47

0.00

0.00

0.00

02.01.00

892350.38

3133.95

0.00

1188943.80

5075.85

0.00

257822.23

1877.26

666.11

0.00

0.00

0.00

01.02.00

897787.94

3394.87

0.00

1336635.40

5993.18

0.00

301356.34

2338.58

864.96

0.00

0.00

0.00

02.03.00

1120215.50

4070.80

0.00

1632235.90

6210.30

0.00

383758.31

2847.20

1053.10

0.00

0.00

0.00

03.03.00

1106391.90

3997.10

0.00

1613696.90

6103.90

0.00

373344.50

2753.80

1018.50

0.00

0.00

0.00

04.03.00

753167.25

3042.90

0.00

1161092.50

4876.85

0.00

267497.28

2211.79

1033.96

0.00

0.00

0.00

03.04.00

392090.91

2039.94

0.00

692522.37

3000.22

0.00

297430.41

2368.30

1220.00

0.00

0.00

0.00

01.05.00

968111.88

4711.26

0.00

1407637.00

5132.04

0.00

0.00

0.00

0.00

0.00

0.00

0.00

26.05.00

964677.12

4714.63

0.00

1302393.40

4823.48

0.00

0.00

0.00

0.00

0.00

0.00

0.00

E-4AH

E-4AH

E-4AH

02.06.00

845181.06

3839.04

0.00

1082742.40

3684.31

0.00

0.00

0.00

0.00

358975.38

3507.30

0.00

11.06.00

810008.38

3576.22

0.00

1223934.60

4051.04

0.00

0.00

0.00

0.00

528617.00

5150.13

0.00

01.07.00

1084929.20

4683.50

0.00

516633.09

1672.70

0.00

0.00

0.00

0.00

559420.38

5338.30

0.00

01.07.00

945227.12

4464.00

0.00

1045283.90

4963.50

0.00

0.00

0.00

0.00

405790.22

3621.75

0.00

02.08.00

1098835.40

5477.80

0.00

897352.12

5368.00

0.00

0.00

0.00

0.00

351710.50

3068.30

0.00


56

TableC.4

Continued

E-1H

E-2H

E-3H

E-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

03.08.00

428256.59

2077.20

0.00

934808.00

5441.00

0.00

0.00

0.00

0.00

357021.69

3030.50

0.00

03.08.00

950113.12

4914.42

0.00

840125.25

5189.77

0.00

0.00

0.00

0.00

328589.31

2960.55

0.00

20.08.00

748702.25

4219.92

0.00

644030.00

4332.50

0.00

0.00

0.00

0.00

155760.11

1516.15

0.00

27.08.00

598294.12

3153.40

0.00

843576.13

5335.40

0.00

0.00

0.00

0.00

374305.00

3452.40

0.00

28.08.00

866001.69

4767.80

0.00

755897.75

4988.16

0.00

0.00

0.00

0.00

302785.91

2916.58

0.00

01.09.00

989493.00

5112.95

0.00

857799.94

5317.98

0.00

0.00

0.00

0.00

321754.09

2910.08

0.00

10.09.00

726209.19

3859.40

0.00

748491.69

4773.40

0.00

0.00

0.00

0.00

274586.69

2553.80

0.00

11.09.00

924157.75

4670.85

0.00

871024.63

5291.67

0.00

0.00

0.00

0.00

320451.16

2838.26

0.00

21.09.00

585996.69

2840.80

0.00

885045.69

5148.60

0.00

0.00

0.00

0.00

394386.19

3345.80

0.00

22.09.00

771726.00

4006.84

0.00

840635.81

5147.84

0.00

0.00

0.00

0.00

342683.09

3042.81

0.00

01.10.00

1082396.00

5393.73

0.00

878972.81

5260.90

0.00

0.00

0.00

0.00

355504.12

3103.15

0.00

03.11.00

1139591.10

5337.19

0.00

928629.94

5209.23

0.00

0.00

0.00

0.00

421906.38

3447.17

0.00

E-3AH

E-3AH

E-3AH

02.12.00

1171074.50

5336.09

0.00

832146.00

4552.95

0.00

289568.75

2124.45

0.00

374580.34

2937.19

0.00

03.01.01

952685.12

5108.89

0.00

684360.38

4334.01

0.00

472697.84

2505.03

97.30

72958.87

863.82

0.00

02.02.01

545467.69

4986.88

0.00

949276.69

5792.53

0.00

626599.56

1609.05

178.78

141254.55

1485.13

0.00

02.03.01

525600.19

5102.55

0.00

1007137.80

6372.33

0.00

437216.94

1163.29

129.26

76672.81

723.86

0.00

02.04.01

563402.31

6026.20

0.00

1130216.50

7989.05

0.00

12390.43

34.54

3.84

0.00

0.00

0.00

02.05.01

526108.81

5582.41

0.00

1100436.50

7714.70

0.00

0.00

0.00

0.00

0.00

0.00

0.00

01.06.01

577366.50

5790.90

0.00

1197067.40

7928.70

0.00

0.00

0.00

0.00

0.00

0.00

0.00

01.06.01

571990.69

5959.16

0.00

1191492.20

8197.62

0.00

0.00

0.00

0.00

0.00

0.00

0.00

07.06.01

368202.81

4757.70

0.00

753717.88

6431.50

0.00

0.00

0.00

0.00

0.00

0.00

0.00

07.06.01

535039.06

5749.61

0.00

862120.88

7411.27

0.00

0.00

0.00

0.00

0.00

0.00

0.00

18.06.01

564091.62

4467.90

0.00

595935.00

5499.20

0.00

0.00

0.00

0.00

0.00

0.00

0.00

19.06.01

605184.38

5573.13

0.00

595551.56

6393.10

0.00

0.00

0.00

0.00

1936.53

19.86

0.00

02.07.01

356026.81

3641.50

0.00

399733.91

4501.10

0.00

0.00

0.00

0.00

0.00

0.00

0.00

03.07.01

309453.41

3106.20

0.00

389994.19

4309.60

0.00

0.00

0.00

0.00

0.00

0.00

0.00

04.07.01

558783.00

5521.44

0.00

587915.62

6390.78

0.00

0.00

0.00

0.00

0.00

0.00

0.00

16.07.01

650971.88

6098.60

0.00

691465.19

7131.60

0.00

0.00

0.00

0.00

0.00

0.00

0.00

17.07.01

567477.62

5733.31

0.00

587100.88

6523.98

0.00

0.00

0.00

0.00

0.00

0.00

0.00

30.07.01

511880.50

5792.00

0.00

543758.38

6773.60

0.00

0.00

0.00

0.00

0.00

0.00

0.00

01.08.01

443454.66

5375.23

0.00

464718.44

6196.44

0.00

0.00

0.00

0.00

0.00

0.00

0.00


57

TableC.4

Continued

E-1H

E-2H

E-3H

E-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

11.08.01

431158.72

5184.98

0.00

454440.16

6012.62

0.00

0.00

0.00

0.00

0.00

0.00

0.00

17.08.01

664880.50

6582.46

0.00

539559.00

6327.83

0.00

0.00

0.00

0.00

0.00

0.00

0.00

02.09.01

650849.62

6376.21

0.00

635395.31

7349.32

0.00

0.00

0.00

0.00

0.00

0.00

0.00

10.09.01

382950.87

3804.00

0.00

300753.53

3460.91

0.00

0.00

0.00

0.00

0.00

0.00

0.00

02.10.01

939109.13

6534.92

0.00

770420.75

7235.75

0.00

0.00

0.00

0.00

0.00

0.00

0.00

02.11.01

1000333.80

6074.51

0.00

778546.31

7245.75

0.00

0.00

0.00

0.00

0.00

0.00

0.00

04.12.01

1032539.10

5597.91

0.00

789615.31

7245.41

0.00

0.00

0.00

0.00

0.00

0.00

0.00

30.12.01

1131600.60

6419.33

0.00

716207.25

7222.90

0.00

0.00

0.00

0.00

0.00

0.00

0.00

01.01.02

1009485.90

5837.58

0.00

632172.12

6492.56

14.45

10256.99

111.85

0.00

0.00

0.00

0.00

03.02.02

1185736.10

6114.93

0.00

799331.94

7468.90

98.14

137414.94

1449.09

0.00

0.00

0.00

0.00

12.02.02

1160830.40

5321.00

0.00

680729.31

5547.30

57.60

102805.40

942.50

0.00

0.00

0.00

0.00

13.02.02

1342238.80

6595.93

0.00

687481.12

6060.22

101.78

134655.94

1273.51

0.00

0.00

0.00

0.00

01.03.02

1085633.60

5888.03

0.00

641179.75

6302.30

325.15

44842.14

440.49

0.00

0.00

0.00

0.00

02.04.02

810620.94

6611.19

39.61

646873.25

6297.70

659.89

47377.13

542.92

0.00

0.00

0.00

0.00

01.05.02

830925.44

6662.90

37.96

586152.12

5363.15

757.72

56695.87

360.07

39715.00

0.00

0.00

0.00

02.06.02

663832.31

5852.09

202.59

430383.13

4110.86

728.11

106666.20

484.87

79.08

0.00

0.00

0.00

02.07.02

902885.94

7324.40

283.71

623375.38

5156.53

1049.03

141090.06

583.64

93.16

0.00

0.00

0.00

08.07.02

867645.94

7353.63

315.53

602517.06

5208.77

1173.70

135581.23

586.03

103.60

0.00

0.00

0.00

11.07.02

870809.50

7248.80

312.98

603056.56

5120.40

1161.00

135685.52

576.03

102.43

0.00

0.00

0.00

15.07.02

799131.63

6727.04

311.04

418972.88

3593.48

849.65

117831.62

505.44

93.49

0.00

0.00

0.00

02.08.02

659129.50

5350.68

366.94

436702.91

3582.53

790.62

101424.73

415.28

71.85

195311.05

1620.85

0.00

14.08.02

616719.19

5371.49

388.30

498333.28

4337.07

936.22

88729.01

386.57

65.51

402255.00

3500.10

0.00

01.09.02

664898.69

5951.20

376.40

520775.19

4661.20

879.70

91039.90

407.40

60.30

335687.69

3004.60

0.00

02.09.02

643413.81

5931.78

416.36

492188.12

4605.49

888.85

46495.15

217.14

31.56

233285.61

2132.55

0.00

15.09.02

538897.19

5088.53

435.15

490055.53

4887.26

946.25

8622.05

41.21

4.46

0.00

0.00

0.00

01.10.02

414240.25

3668.27

316.27

303458.06

2818.42

618.17

116289.06

536.48

71.62

0.00

0.00

0.00

08.10.02

13724.02

109.19

11.93

355421.72

2934.94

819.11

106020.53

438.26

73.04

275283.72

2236.46

0.00

14.10.02

591065.44

4324.44

378.21

373414.66

2872.18

659.91

102100.35

393.59

53.93

223677.52

1711.86

0.00

02.11.02

575675.94

4599.45

326.23

374566.38

2772.57

498.23

105206.52

375.69

11.97

0.00

0.00

0.00

17.11.02

698152.63

5937.65

517.39

489602.38

3653.05

709.59

68461.66

229.11

0.00

0.00

0.00

0.00

02.12.02

447692.22

3937.20

559.55

462406.34

3683.85

1011.61

29438.60

104.77

0.00

190287.44

1547.64

0.00

24.12.02

570413.88

4280.34

704.44

459719.50

3209.25

1081.45

141773.78

439.81

0.00

311890.41

2176.68

0.00


58

TableC.4

Continued

E-1H

E-2H

E-3H

E-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

01.01.03

583533.62

4794.60

686.20

462824.41

3536.60

1149.90

133964.50

455.00

0.00

189108.00

1445.00

0.00

02.01.03

587020.31

4813.40

605.97

483137.88

3686.80

1051.13

54845.69

182.20

0.00

188147.84

1434.64

0.00

12.01.03

579832.19

4777.51

506.60

490081.09

3756.34

903.33

46227.63

154.60

0.00

181098.02

1387.78

0.00

20.01.03

663065.88

4916.28

728.51

492836.16

3393.23

1134.58

135410.97

413.83

0.00

73699.37

502.50

0.00

03.02.03

750221.06

5635.21

1392.46

508024.72

3819.04

1175.35

85304.91

278.62

0.00

0.00

0.00

0.00

14.02.03

831435.75

5621.02

1447.19

522479.56

3528.98

1130.72

148865.33

447.46

0.00

104573.89

714.63

0.00

01.03.03

671285.00

5825.00

1472.20

526504.81

4569.40

1438.40

0.00

0.00

0.00

0.00

0.00

0.00

06.03.03

643721.00

5238.00

1320.00

504875.00

4108.00

1290.00

0.00

0.00

0.00

0.00

0.00

0.00

07.03.03

617486.19

4956.68

1417.12

453176.16

3641.20

1293.60

81064.68

287.68

0.00

40084.44

329.80

0.00

03.04.03

388144.91

3756.07

1436.73

267126.72

2461.00

861.57

174007.97

271.97

2.73

89091.00

871.03

0.00

04.05.03

480042.12

4382.77

1918.71

366842.16

3226.45

1344.42

263155.41

231.94

69.74

29456.03

280.42

0.00

03.06.03

379995.00

3650.50

1248.00

391855.00

3764.50

1070.00

533291.50

488.00

113.50

0.00

0.00

0.00

04.06.03

349170.31

3288.75

1031.93

359699.69

3395.18

904.18

343220.53

315.68

58.96

44144.29

456.82

0.00

02.07.03

280717.78

3021.44

1078.67

264349.78

2845.00

971.78

290694.56

293.56

73.33

83438.00

907.89

0.00

10.07.03

347854.53

3376.46

1669.05

348736.38

3523.68

1675.23

119295.59

112.77

30.86

101225.41

960.14

0.00

02.08.03

305487.44

3044.11

1623.11

337860.00

3543.11

1810.67

178803.11

172.44

49.44

161208.22

1606.22

0.00

11.08.03

299385.50

2863.00

1519.50

323560.50

3257.00

1657.00

585177.00

533.50

155.50

168447.00

1610.50

0.00

12.08.03

285242.00

2888.85

1517.55

297659.66

3160.35

1583.35

287483.66

284.80

82.50

200424.45

1714.65

0.00

01.09.03

396261.59

3528.00

2364.20

340732.69

3353.00

1901.70

0.00

0.00

0.00

0.00

0.00

0.00

02.09.03

348018.47

2907.64

1846.46

340400.97

3142.24

1692.34

255509.17

216.13

67.94

20406.41

142.43

0.00

10.09.03

368347.69

3065.55

2035.05

338226.94

3111.20

1747.25

515783.25

429.30

138.20

0.00

0.00

0.00

12.09.03

369927.09

3102.80

2142.40

313435.69

2905.70

1698.20

509058.50

427.00

143.00

0.00

0.00

0.00

13.09.03

376465.44

3089.43

2164.90

350889.88

3179.83

1886.97

117976.70

100.57

33.47

0.00

0.00

0.00

16.09.03

323365.88

2531.90

1408.07

302858.44

2626.59

1218.71

0.00

0.00

0.00

92983.67

665.47

0.00

01.10.03

319276.19

2573.87

1541.06

296069.59

2578.55

1495.88

452790.03

363.29

119.73

308436.47

2424.87

4.47

24.10.03

307033.41

2468.87

1564.32

298098.84

2674.58

1694.60

622671.62

505.17

183.06

278589.38

2305.61

5.98

02.11.03

294259.00

2423.91

1751.47

282658.16

2596.20

1877.62

360008.72

307.61

117.13

131085.20

1087.91

3.42

20.11.03

365328.06

2690.74

2359.63

390771.47

3178.92

2267.55

446731.03

370.52

132.63

0.00

0.00

0.00

04.12.03

391587.38

2769.81

2773.70

414866.94

3201.96

2416.97

317069.16

273.09

103.96

28321.44

236.46

0.73

09.12.03

353428.59

2389.70

2509.10

375747.09

2771.60

2193.30

0.00

0.00

0.00

156515.41

1233.00

3.40

10.12.03

289096.12

2046.74

1935.32

298904.78

2311.22

1624.23

463403.16

373.90

127.67

29651.61

144.21

34.81

18.12.03

387102.06

2585.20

2590.18

436265.56

3178.24

2305.95

131705.75

101.33

38.24

0.00

0.00

0.00


59

TableC.4

Continued

E-1H

E-2H

E-3H

E-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

01.01.04

420834.50

2652.17

2457.03

451537.22

3059.45

1829.63

238048.37

167.60

58.78

1010.52

4.21

0.81

19.01.04

389772.50

2662.30

2188.60

358134.59

2552.50

737.30

0.00

0.00

0.00

0.00

0.00

0.00

20.01.04

222175.45

1406.70

1292.13

408347.06

2653.53

848.61

308455.06

217.71

71.76

0.00

0.00

0.00

02.02.04

348904.56

2202.15

2062.02

354212.44

2354.55

882.96

31712.85

25.07

10.37

0.00

0.00

0.00

01.03.04

344083.69

2165.87

2112.98

268002.50

1880.23

796.03

0.00

0.00

0.00

6270.63

45.66

24.65

01.04.04

262297.03

2127.60

1982.65

272220.56

1511.45

577.75

0.00

0.00

0.00

72243.49

434.71

332.46

01.05.04

259193.05

2227.90

2234.13

264047.06

1545.77

722.66

0.00

0.00

0.00

10801.48

156.15

170.42

02.06.04

326771.81

2224.49

2316.87

302595.13

2242.08

1499.22

0.00

0.00

0.00

26626.04

321.47

371.74

02.07.04

350342.50

2383.50

2792.15

339793.00

2396.00

1759.20

0.00

0.00

0.00

61799.50

544.70

888.25

04.07.04

310161.53

2278.39

2536.11

292135.09

2113.37

1528.86

59422.67

314.70

120.94

18705.52

166.06

286.82

25.07.04

294397.84

2113.57

2326.86

307359.06

2042.96

1556.97

63684.84

301.81

119.86

60049.67

495.94

860.06

01.08.04

294650.62

2113.10

2398.44

303536.72

2017.80

1583.95

17144.81

78.69

32.85

31206.81

274.27

482.86

16.08.04

292475.69

2260.30

2418.10

279381.09

1998.70

1479.90

0.00

0.00

0.00

92654.60

828.60

1403.50

17.08.04

115939.04

933.21

1092.76

107674.51

800.79

647.61

0.00

0.00

0.00

3313.94

30.79

54.76

04.09.04

131189.34

1172.72

1227.00

126164.96

1046.82

759.22

89527.61

90.89

36.63

15143.24

150.92

227.61

20.09.04

291582.47

2426.39

2396.78

281671.75

2169.53

1482.11

278044.97

236.89

85.94

48909.61

469.79

709.40

01.10.04

256788.48

2228.24

2797.51

233760.92

2020.55

2081.81

116720.04

100.76

37.87

31898.55

311.58

644.14

01.11.04

167982.03

1544.40

2094.00

175835.77

1682.92

1985.03

201110.75

265.38

81.22

13892.54

141.80

303.16

04.12.04

192617.38

1663.90

2926.31

177520.98

1615.79

2384.88

87005.38

82.77

26.33

14605.53

151.24

327.53

05.01.05

235931.05

2232.59

2805.06

187650.38

1772.71

2338.38

235355.34

323.18

74.49

5262.13

49.16

109.57

15.01.05

220096.28

2120.58

3260.11

179629.91

1730.39

2779.52

0.00

0.00

0.00

33197.51

352.74

831.38

29.01.05

259775.97

2347.55

3627.85

196092.44

1771.62

2854.17

0.00

0.00

0.00

0.00

0.00

0.00

02.02.05

245095.27

2234.16

3584.52

182761.14

1665.27

2784.83

0.00

0.00

0.00

0.00

0.00

0.00

05.03.05

236158.38

2069.26

3350.55

182807.28

1602.04

2708.13

0.00

0.00

0.00

55681.54

542.02

1351.94

24.03.05

231489.91

1998.00

3569.40

184734.70

1594.50

2968.20

0.00

0.00

0.00

49951.00

479.50

1318.20

25.03.05

211206.42

1797.95

3040.41

187039.73

1589.80

2818.66

0.00

0.00

0.00

47702.45

450.91

1178.86

03.04.05

258594.02

2075.17

3402.45

194371.81

1405.77

3141.91

0.00

0.00

0.00

14117.07

145.97

294.40

27.04.05

264626.00

2069.89

3664.60

192287.17

1355.97

3275.39

0.00

0.00

0.00

0.00

0.00

0.00

E-3CH

E-3CH

E-3CH

03.05.05

228757.31

1841.40

3351.16

12416.21

120.71

669.08

422259.44

4158.51

0.00

6633.91

41.04

113.12

02.06.05

228131.80

1950.70

3378.20

44476.30

446.60

2314.30

738251.62

7622.70

0.00

0.00

0.00

0.00

03.06.05

231659.77

1821.47

3377.56

46021.83

424.30

2355.44

447377.44

4369.24

0.00

0.00

0.00

0.00


60

TableC.4

Continued

E-1H

E-2H

E-3H

E-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

27.06.05

215842.44

1633.26

3151.32

42281.30

375.38

2166.06

546964.44

5098.40

0.00

0.00

0.00

0.00

01.07.05

184233.14

1694.40

3284.19

22991.78

200.09

1095.54

584454.25

5241.56

239.92

29907.09

300.96

722.94

11.07.05

186007.56

1809.55

3269.40

0.00

0.00

0.00

494012.62

4372.00

1159.95

3993.85

1.88

48.25

18.07.05

27283.65

264.30

518.63

0.00

0.00

0.00

497887.16

4437.53

1553.19

9914.92

4.52

120.32

30.07.05

0.00

0.00

0.00

0.00

0.00

0.00

500060.50

4252.47

1714.90

0.00

0.00

0.00

02.08.05

0.00

0.00

0.00

0.00

0.00

0.00

351842.50

3066.65

2325.55

0.00

0.00

0.00

04.08.05

0.00

0.00

0.00

0.00

0.00

0.00

341781.91

2950.00

2234.80

0.00

0.00

0.00

E-2AH

E-2AH

E-2AH

05.08.05

73132.55

664.36

1498.03

131966.23

998.15

0.00

309634.25

2651.16

2514.94

0.00

0.00

0.00

02.09.05

162647.56

1422.75

3100.19

366891.94

2665.14

0.00

199127.67

1631.87

2293.73

0.00

0.00

0.00

17.09.05

196747.45

1833.91

3512.78

0.00

0.00

0.00

228541.23

2185.41

3090.09

0.00

0.00

0.00

05.10.05

201488.34

1829.35

3652.29

7828.18

60.73

605.61

148191.28

1374.55

2656.60

0.00

0.00

0.00

09.11.05

187263.22

1454.10

3428.53

149.73

45658.00

12.62

166412.84

1293.48

3110.21

0.00

0.00

0.00

02.12.05

178949.91

1623.70

3446.80

0.00

0.00

0.00

175746.41

1572.50

3437.40

0.00

0.00

0.00

03.12.05

202993.94

1691.26

3879.70

0.00

0.00

0.00

171647.89

1407.42

3323.37

0.00

0.00

0.00

01.01.06

144995.95

1055.25

2723.80

0.00

0.00

0.00

168646.70

1201.80

3246.90

0.00

0.00

0.00

03.01.06

105784.38

911.60

2617.21

0.00

0.00

0.00

130660.21

1184.97

3514.19

0.00

0.00

0.00

20.01.06

82327.70

712.80

2045.03

0.00

0.00

0.00

64309.48

576.20

1721.64

0.00

0.00

0.00

04.02.06

90679.02

657.41

2013.57

0.00

0.00

0.00

111665.76

813.34

2612.65

0.00

0.00

0.00

26.02.06

100982.24

754.90

2322.38

0.00

0.00

0.00

69950.82

519.92

1702.40

0.00

0.00

0.00

04.03.06

173132.94

1360.94

3896.20

0.00

0.00

0.00

102172.10

821.93

2916.66

0.00

0.00

0.00

06.04.06

118155.93

861.14

2630.62

0.00

0.00

0.00

67099.84

502.85

1913.94

0.00

0.00

0.00

01.05.06

76240.16

593.47

1892.03

0.00

0.00

0.00

56946.70

445.97

1777.97

0.00

0.00

0.00

08.05.06

68851.99

509.50

1710.04

0.00

0.00

0.00

42404.17

344.82

1376.58

0.00

0.00

0.00

05.06.06

99853.78

648.49

2464.00

339.10

2.83

28.57

99903.84

836.23

3290.55

0.00

0.00

0.00

02.07.06

129481.31

909.43

4040.71

0.00

0.00

0.00

111123.13

883.79

4012.36

0.00

0.00

0.00

02.08.06

165585.70

1133.99

5302.07

0.00

0.00

0.00

115002.05

861.01

3978.07

0.00

0.00

0.00

16.08.06

147440.09

953.70

4725.00

0.00

0.00

0.00

123941.00

875.70

4280.40

0.00

0.00

0.00

17.08.06

159392.92

1116.68

5385.76

0.00

0.00

0.00

113293.36

865.48

4121.13

0.00

0.00

0.00

01.09.06

134723.59

1168.40

5376.88

0.00

0.00

0.00

95227.45

901.80

4091.19

0.00

0.00

0.00

14.09.06

131118.77

1025.94

4786.62

0.00

0.00

0.00

94168.09

804.99

3710.25

0.00

0.00

0.00

01.10.06

136434.53

1012.57

4644.44

0.00

0.00

0.00

105548.69

856.78

3881.71

0.00

0.00

0.00


61

TableC.4

Continued

E-1H

E-2H

E-3H

E-4H

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

GPR

OPR

WPR

Date

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

Sm

3/day

10.10.06

145581.95

1097.86

5229.34

0.00

0.00

0.00

105143.30

866.08

4070.14

0.00

0.00

0.00

15.10.06

136827.00

1008.42

5846.41

11351.11

94.58

956.42

18171.01

150.63

803.32

0.00

0.00

0.00

01.11.06

138741.30

1007.65

5119.11

8424.59

75.36

1325.90

25993.69

206.01

1026.23

0.00

0.00

0.00

09.11.06

140465.59

1022.40

6126.30

9593.20

86.15

1772.60

0.00

0.00

0.00

0.00

0.00

0.00

11.11.06

142370.22

1038.02

6355.03

9412.17

84.82

1785.17

0.00

0.00

0.00

0.00

0.00

0.00

17.11.06

160625.98

924.29

5588.44

8732.02

63.57

1322.01

24240.42

150.39

898.59

0.00

0.00

0.00

01.12.06

160625.98

924.29

5588.44

8732.02

63.57

1322.01

24240.42

150.39

898.59

0.00

0.00

0.00

62

C.2 Injection Data

Table C.5: Injection data for template C

C-1H C-2H C-3H C-4H

GIR WIR GIR WIR GIR WIR GIR WIR

Date Sm3/day Sm3/day Sm3/day Sm3/day Sm3/day Sm3/day Sm3/day Sm3/day

22.11.97 0 0 0 0 0 0 392180.97 0

09.12.97 0 0 0 0 0 0 480352.94 0

24.12.97 0 0 0 0 0 0 1129535.4 0

11.01.98 0 0 0 0 0 0 1749032.8 0

11.02.98 0 0 0 0 0 0 137940.77 0

07.03.98 0 0 0 0 0 0 1418039.8 0

30.03.98 0 0 0 0 0 0 2370770.8 0

31.03.98 0 0 0 0 0 0 2503454 0

02.04.98 0 0 0 0 0 0 2351508.3 0

27.04.98 0 0 0 0 0 0 2680355.8 0

06.05.98 0 0 0 0 0 0 2982927 0

27.05.98 0 0 0 0 0 0 3179814.5 0

28.05.98 0 0 0 0 0 0 2904366.2 0

02.06.98 0 0 0 0 0 0 3063275.8 0

17.06.98 0 0 0 0 0 0 3234733.2 0

24.06.98 0 0 0 0 0 0 3733812 0

25.06.98 0 0 0 0 0 0 2968319 0

03.07.98 0 0 0 0 0 0 2988119.8 0

21.07.98 0 4916.93 0 0 0 0 3929878.5 0

04.08.98 0 6957.5 0 0 0 0 3768740.2 0

31.08.98 0 6422 0 0 0 0 3404638 0

01.09.98 0 7096.5 0 0 0 0 3768639 0

02.09.98 0 5573.58 0 0 0 0 4072016.5 0

22.09.98 0 7681.28 0 0 0 0 3952048.3 0

01.10.98 645345.12 0 0 0 0 0 1649276.2 0

02.10.98 959477.5 0 0 0 0 0 2434335.3 0

15.10.98 0 0 0 0 0 0 0 0

17.10.98 543718.81 0 0 0 0 0 1991812.5 0

01.11.98 1018088.1 0 0 0 0 0 3677762 0

02.12.98 1770183.5 0 0 0 0 0 2331130.5 0

25.12.98 4017466.5 0 0 0 0 0 0 0

01.01.99 830100.75 0 0 0 0 0 2901544.5 0

04.01.99 0 7389.18 0 0 0 0 4232329 0

19.01.99 713342.12 0 0 0 0 0 2345625.2 0

21.01.99 734190.44 0 0 3301.10 0 0 3221026 0

01.02.99 2410918.8 0 0 6975.62 0 0 2683441.3 0

25.02.99 4218303 0 0 6197.36 0 0 0 9255.84

01.03.99 4201928.5 0 0 5403.3 0 0 0 8434.38

05.03.99 1545428 0 0 6061.89 0 0 3333218.5 0

23.03.99 0 6314.10 0 6577.90 0 0 4794070.5 0

Continued on Next Page. . .

63

Table C.5 Continued

C-1H C-2H C-3H C-4H



26.03.99 0 6974.8 0 6423.70 0 0 5002349 0

28.03.99 0 6975.02 0 7185.35 0 0 4971927.5 0

01.04.99 0 6940.32 0 7278.19 0 0 4929680 0

02.05.99 0 7019.83 0 7824.73 0 0 5051295.5 0

04.05.99 0 7001.3 0 7803.10 0 0 4893810 0

05.05.99 0 6552.42 0 6797.47 0 0 4534522.5 0

18.05.99 0 5987.5 0 6349.63 0 0 4493671 0

21.05.99 0 5835.5 0 5161.5 0 5517.2002 4757178 0

22.05.99 0 7127.4 0 6587.36 0 7286.85 4660279 0

01.06.99 0 7922.98 0 7019.39 0 7465.24 4587238 0

22.06.99 0 7812.18 0 7464.69 0 7813.57 4583384 0

01.07.99 0 3275.35 0 6324.93 0 7443.69 3993498.5 0

15.07.99 0 8227.76 0 6342.17 0 8159.59 4972193.5 0

02.08.99 0 7308.55 0 6554.35 0 7274.63 5290969 0

06.08.99 0 8576.48 0 7635.47 0 8452.73 4928244 0

01.09.99 0 8211.85 0 7163.10 0 7945.60 5212404.5 0

03.09.99 0 6979.55 0 3646.75 0 6800.85 4866850 0

05.09.99 0 7300.64 0 0 0 7975.97 4783540 0

22.09.99 0 6898 0 0 0 6897 5258671 0

22.09.99 0 5498.67 0 1520.49 0 3992.06 3450398.5 0

02.10.99 0 5935.55 0 2624.8 0 5975.4 5441272 0

03.10.99 0 8308 0 7123.70 0 7422.70 5066667.5 0

04.10.99 0 8944.33 0 7173.3 0 6610.20 5018511 0

14.10.99 0 8331.03 0 6617.5 0 6811.9 5205779 0

17.10.99 0 7742.96 0 6847.43 1040260.4 0 2698217.5 0

01.11.99 0 0 0 0 0 0 0 0

09.11.99 0 0 0 503 960645.13 0 0 4050.9

10.11.99 2203967.8 0 0 5902.93 1626331.4 0 0 11654.67

13.11.99 2140149 0 0 4997.32 2145644 0 0 10163.78

01.12.99 3221508.2 0 0 8307.46 2878989 0 0 10231.76

02.01.00 2737946.8 0 0 9333.82 2982803 0 0 11506.91

01.02.00 1581380.6 0 0 8309.30 4292487.5 0 0 9149.07

02.03.00 1712194.5 0 0 0 5129735.5 0 0 0

03.03.00 1710670.5 0 0 0 5212674.5 0 0 0

04.03.00 1530587.1 0 0 10394.76 4519536 0 0 5553.27

03.04.00 1159818.8 0 0 4425.56 2267097.5 0 0 9099.67

01.05.00 2145800.8 0 0 3708.02 4424429 0 0 13836.64

26.05.00 2802328 0 0 3734.60 3514136.8 0 0 13560.53

02.06.00 2742347.8 0 0 4235.96 3135476.8 0 0 13405.58

11.06.00 2783176.3 0 0 3595.94 3335178.3 0 0 13706.95

01.07.00 534133.31 0 0 2810.9 542491.38 0 0 10001

01.07.00 2150957 0 0 8609.13 4426746.5 0 0 6864.78

02.08.00 1516594.3 0 0 10847.2 5239526 0 0 4798.70


64

Table C.5 Continued

C-1H C-2H C-3H C-4H



03.08.00 1096764.9 0 0 10825.6 3517711 0 0 4813.4

03.08.00 1530052.1 0 0 9764.4 4887768 0 0 4309.78

20.08.00 785977.56 0 0 9449.85 3265412.2 0 0 4098.63

27.08.00 686006.63 0 0 10998.8 3051748.5 0 0 4265.70

28.08.00 1295424.1 0 0 9800.62 4319262.5 0 0 4613.66

01.09.00 1377052.8 0 0 10411.36 4659273 0 0 4564.25

10.09.00 1416529.9 0 0 10560.2 3854904 0 0 4699.8

11.09.00 1474827 0 0 10388.982 4465016.5 0 0 4649.37

21.09.00 1040727.3 0 0 9958.20 1934893.8 0 0 4456.38

22.09.00 1691579.1 0 0 10983.7 3571745.8 0 0 2451.83

01.10.00 2346355.5 0 0 9737.3838 4080953.5 0 0 4693.96

03.11.00 2163371.2 0 0 7440.457 4448847 0 0 4631.9

02.12.00 2355701 0 0 9260.8516 4349460 0 0 1157.60

03.01.01 3121111.2 0 0 8699.2812 2857948.8 0 0 3156.04

02.02.01 1975302 0 0 8379.5684 2195615.3 0 0 10325.32

02.03.01 1006735.3 0 0 8788.8516 1430236.9 0 0 11198.88

02.04.01 1169868.6 0 0 8979.27 1086744.9 0 0 6451.14

02.05.01 1572526 0 0 9401.40 1536748.4 0 0 8563.60

01.06.01 3272052 0 0 7020.3 3161095 0 0 11859.5

01.06.01 2121885 0 0 8527.08 2272923.5 0 0 13857.42

07.06.01 156046.2 0 0 8842.20 151124.59 0 0 14126.6

07.06.01 721401.75 0 0 7037.29 1480433.3 0 0 13741.41

18.06.01 0 0 0 6873.4 0 10358.4 2594061.3 0

19.06.01 0 7165.14 0 3083.74 0 7442.31 452048 0

02.07.01 0 9651.20 0 3486.2 0 10120 18399.30 0

03.07.01 0 9596.90 0 3498.4 0 10061.4 1067570 0

04.07.01 0 9492.22 0 3495.79 0 9906.68 1203464.8 0

16.07.01 0 9407.40 0 3665.9 0 9818 1232594.8 0

17.07.01 0 8670.69 0 3655.74 0 9067.54 1062123.5 0

30.07.01 0 9595.3 0 3866.05 0 9992.45 0 0

01.08.01 0 8055.37 0 3995.08 0 10252.87 1338065.8 0

11.08.01 0 8986.23 0 3586.05 0 9359.52 2327192 0

17.08.01 0 10254.36 0 5315.03 2112211.5 0 2663022 0

02.09.01 0 12405.31 0 4908.62 31915.64 0 111969.84 0

10.09.01 0 7120.05 0 7277.52 0 7468.22 828965.13 0

02.10.01 0 8065.97 0 8074.90 0 7160.02 2692290 0

02.11.01 0 8471.13 0 7566.11 0 6346.33 1350798.1 0

04.12.01 0 8102.87 0 7245.54 0 5960.99 1258392.2 0

30.12.01 0 10270.33 0 9156.83 1067075.2 0 154488.03 0

01.01.02 0 8580.53 0 7653.51 2176936.2 0 1976094 0

03.02.02 0 10287.13 0 9182.25 2195476.2 0 2142572 0

12.02.02 0 7378.70 0 6571.70 2081026.9 0 2048718.2 0

13.02.02 0 10133.27 0 8940.08 2168295.2 0 2130426.2 0


65

Table C.5 Continued

C-1H C-2H C-3H C-4H



01.03.02 0 10052.89 0 8970.07 1655834.1 0 1349806.9 0

02.04.02 0 11152.22 0 10001.74 2142392.5 0 1915483.2 0

01.05.02 0 11224.67 0 10034.15 1902102.2 0 1752265 0

02.06.02 0 9139.08 0 8239.28 2075962.1 0 1915570.8 0

02.07.02 0 10828.4 0 9714.47 1471863.9 0 1431919.5 0

08.07.02 0 7499.07 0 6757.9 3848521 0 0 10642.57

11.07.02 0 11063.8 0 9922.58 2640222.3 0 1314270.5 0

15.07.02 0 5718.5 0 5174.71 3124091.5 0 0 8809.62

02.08.02 0 4944.59 0 4528.731 2248776.5 0 0 6437.11

14.08.02 1704809.9 0 0 9695.43 1711804.5 0 0 11462.37

01.09.02 1293452.9 0 0 10133.8 2187915 0 0 11408.6

02.09.02 0 9714.99 0 8724.5 2544224.8 0 2513681.2 0

15.09.02 0 10969.87 0 10089.037 2129208.2 0 2075431.5 0

01.10.02 0 10819.17 0 9776.95 0 0 2413175.8 0

08.10.02 0 8101.14 0 7168.89 0 0 0 8640.8

14.10.02 0 7885.09 0 7756.33 0 5892.94 0 2913.9

02.11.02 0 364.73 0 4675.51 0 4325.59 0 9704

17.11.02 0 7870.01 0 7111.78 0 5725.49 0 0

02.12.02 0 5148.05 0 4877.76 0 3620.63 0 0

24.12.02 0 12904.8 0 9021.65 1136918.6 0 0 0

01.01.03 0 12082.4 0 10934.5 2755485.2 0 0 0

02.01.03 1326148 0 0 12545.46 1956115.8 0 0 0

12.01.03 0 10621.54 0 12462.75 2934102 0 0 0

20.01.03 1342655 0 0 12715.417 3280170 0 0 0

03.02.03 1161399 0 0 10799.669 2987142.8 0 0 0

14.02.03 0 11446.17 0 10863.58 1691833 0 0 0

01.03.03 0 11135.6 0 10301.6 1430485.6 0 0 0

06.03.03 0 11982 0 10670 1737825 0 0 0

07.03.03 0 11558.36 0 10314.84 2581447.8 0 0 0

03.04.03 0 10294.27 0 10846.57 1591625.9 0 0 0

04.05.03 0 8565.84 0 8288.23 1578755.8 0 0 36.581001

03.06.03 0 11901.5 0 10935 1456442 0 0 0

04.06.03 0 10706.04 0 10361.04 1789821.1 0 0 0

02.07.03 0 3713 0 15661.89 680164.75 0 0 0

10.07.03 1389590.4 0 0 11001.05 0 10376.23 0 0

02.08.03 2060609.5 0 0 10745.89 0 10165.33 0 0

11.08.03 1098633 0 0 16307.5 0 5052 0 0

12.08.03 0 11743.9 0 10711.35 2070783.8 0 0 0

01.09.03 0 9925.40 0 8643.40 1622912.2 0 0 0

02.09.03 987983.69 0 0 12930.2 1639903.6 0 0 0

10.09.03 1119372.2 0 0 12811.2 2636495 0 0 0

12.09.03 1151451.8 0 0 12756.8 2678413 0 0 0

13.09.03 1191180.6 0 0 12859.77 2229838.8 0 0 0


66

Table C.5 Continued

C-1H C-2H C-3H C-4H



16.09.03 1488170.8 0 0 11062.47 2036849.1 0 0 8.467

10.10.03 0 12324.87 0 11344.04 3087495.8 0 0 0

24.10.03 0 11930.48 0 10899.21 3097415 0 0 0

02.11.03 0 11002.62 0 9962.38 2614016 0 0 0

20.11.03 0 11874.28 0 10775.1 3673105.8 0 0 0

04.12.03 0 12123.17 0 11004.2 3414282 0 0 0

09.12.03 0 11985.5 0 10871.3 2661792.5 0 0 0

10.12.03 0 11743.99 0 10597.03 3084212 0 0 0

18.12.03 284868.94 0 0 11870.58 502809.81 0 0 0

01.01.04 1117235.4 0 0 9278.03 0 0 0 0

19.01.04 218515 0 0 1419.9 0 541.20001 0 0

C-4AH C-4AH

20.01.04 2003787.8 0 0 5827.08 0 2321.43 0 6034.07

02.02.04 2197874.2 0 0 7776.3 0 8913.75 0 5314.40

01.03.04 2127892.2 0 0 9665.52 0 9045.15 0 5053.64

01.04.04 2330681 0 0 9612.32 0 8789.75 0 5301.38

01.05.04 2226928.8 0 0 9836.88 0 9244.53 0 4619.97

02.06.04 2987511.8 0 0 10844.3 0 4330.06 0 5252.03

02.07.04 2911072.5 0 0 9845.95 0 8764.45 0 4438.8

04.07.04 2490669.2 0 0 10257.03 0 7697.33 0 4377.68

25.07.04 1080894.2 0 0 11255.96 1794042.9 0 0 4510.4

01.08.04 1519714.9 0 0 11915.71 709887.06 0 0 6127.09

16.08.04 2765929.5 0 0 12552.1 419076 0 0 6501.7002

17.08.04 1210930.6 0 0 4587.98 206118.95 0 0 2493.60

04.09.04 1279385.4 0 0 5998.8 7547.5 0 0 2653.25

20.09.04 0 11057.06 0 9970.21 1936354.2 0 0 2777.48

01.10.04 0 9252.02 0 8338.86 1589347.5 0 0 2811.62

01.11.04 0 9976.78 0 8911.79 1291243.1 0 0 2841.08

04.12.04 0 10121.65 0 9064.14 1627788.9 0 0 4303.28

05.01.05 0 11130.36 0 9943.57 811387.94 0 0 4097.77

15.01.05 0 10985.53 0 9776.03 540756.44 0 0 3550.24

29.01.05 0 11604.75 0 10350.35 0 3669.93 322203.5 0

02.02.05 0 11240.53 0 9860.14 0 3835.35 388098.16 0

05.03.05 0 10259.29 0 9123.16 0 3265.48 308153.16 0

24.03.05 0 11519.5 0 10222.5 0 3970.60 285196.69 0

25.03.05 0 11406 0 10120.84 0 3967.10 327484.06 0

03.04.05 0 10238.30 0 9055.35 0 3463.97 51372.96 0

27.04.05 0 10579.23 0 9363.37 0 3460.8 339473.81 0

03.05.05 0 10434.55 0 9196.15 0 3681.8 322805.31 0

02.06.05 0 10284.2 0 9012.3 0 3862.5 0 0

03.06.05 0 9837.85 0 8664.99 0 3573.208 539396.88 0

27.06.05 0 901 0 1044.96 0 234.56 0 5319.24

01.07.05 0 7905.21 0 7854.18 0 3042.06 0 5182.31


67

Table C.5 Continued

C-1H C-2H C-3H C-4H



11.07.05 0 3295.7 0 2940.83 0 1143.82 0 1922.12

18.07.05 0 9178.55 0 8191.41 0 3199.10 0 5317.15

30.07.05 0 9453.5 0 8406.87 0 3400.60 0 5457.70

02.08.05 0 7394.8 0 6546.35 0 2389.15 0 3959.60

04.08.05 0 0 0 94.1 0 0 0 0

05.08.05 0 7914.77 0 7081.53 0 2654.03 0 4634.09

02.09.05 0 8262.94 0 7354.76 0 2823.29 0 4813.65

17.09.05 0 8183.72 0 7271.21 0 2900.36 0 4741.11

05.10.05 0 9054.87 0 8011.48 0 3171.82 0 5200.27

09.11.05 0 5727.31 0 6068.78 0 2156.74 0 3304.54

02.12.05 0 8771.20 0 7795.20 0 2797.9 0 5074

03.12.05 0 8680.3 0 7705.60 0 2734.99 0 3147.70

01.01.06 0 8270.75 0 7351.85 0 2646.60 0 4778.10

03.01.06 0 7535.05 0 6692.4 0 2347.09 0 4341.79

20.01.06 0 7975.20 0 7099.14 0 2606.13 0 4598.42

04.02.06 0 7160.96 0 6631.95 0 2623.55 0 4278.62

26.02.06 0 0 0 6754.46 0 2569.62 0 4373.36

04.03.06 0 4648.41 0 7295.77 0 1308.54 0 3108.05

06.04.06 0 7527.97 0 6155.35 0 0.01 0 2225.49

01.06.06 0 0 0 0 0 0 0 0

08.06.06 0 739.04 0 545.71 0 0.03 0 107.66

05.06.06 0 0 0 0 0 0 0 0

17.08.06 145094.41 0 0 0 191404.94 0 15687.78 0

01.09.06 890105.75 0 0 0 855614 0 94195.26 0

14.09.06 699302.62 0 0 0 791935.31 0 74907.92 0

01.10.06 784659.81 0 0 0 938574.94 0 84609.3 0

10.10.06 808842.06 0 0 0 969108.38 0 88244.22 0

15.10.06 923574.5 0 0 0 385162.66 0 99504.55 0

01.11.06 592364.38 0 0 0 0 0 55925.73 0

09.11.06 431559.75 0 0 0 134390.75 0 11018.1 0

11.11.06 649396.19 0 0 0 1004323.3 0 73359.34 0

17.11.06 56404.18 0 0 0 143344.55 0 8632.40 0

01.12.06 0 0 0 0 0 0 0 0

24.01.07 0 12000 0 12000 0 8000 0 12000

68

Table C.6: Injection data for template F

F-1H F-2H F-3H F-4H



06.11.97 0 0 0 0 0 0 0 0

03.09.99 0 3580.65 0 0 0 0 0 0

05.09.99 0 7852.83 0 0 0 0 0 0

22.09.99 0 8565.30 0 0 0 0 0 0

22.09.99 0 8521.77 0 0 0 0 0 0

02.10.99 0 7005.15 0 0 0 0 0 0

03.10.99 0 12273.6 0 0 0 0 0 0

04.10.99 0 12101.16 0 0 0 0 0 0

14.10.99 0 11851.93 0 254.53 0 0 0 0

17.10.99 0 7080.73 0 2511.82 0 0 0 0

01.11.99 0 3837.40 0 1120.33 0 0 0 0

09.11.99 0 10739.5 0 2636.4 0 0 0 0

10.11.99 0 11943.77 0 2758.17 0 0 0 0

13.11.99 0 4941.02 0 1354.25 0 0 0 0

01.12.99 0 9262.04 0 2950.61 0 0 0 0

02.01.00 0 5840.72 0 3856.36 0 0 0 0

01.02.00 0 6632.60 0 4671.86 0 0 0 0

02.03.00 0 0 0 0 0 0 0 0

03.03.00 0 0 0 470.1 0 0 0 0

04.03.00 0 1522.54 0 6266.27 0 0 0 0

03.04.00 0 8842.09 0 2508.59 0 0 0 0

01.05.00 0 6141.53 0 6042.53 0 0 0 0

26.05.00 0 11916.93 0 6324.91 0 0 0 0

02.06.00 0 14672.9 0 3557.06 0 0 0 0

11.06.00 0 14849.73 0 3554.49 0 0 0 0

01.07.00 0 12862.4 0 2719.5 0 0 0 0

01.07.00 0 15098.67 0 3704.46 0 0 0 0

02.08.00 0 15541.4 0 3949.9 0 0 0 0

03.08.00 0 15511.1 0 3939.6 0 0 0 0

03.08.00 0 14171.10 0 3430.76 0 0 0 0

20.08.00 0 13952.08 0 3425.25 0 0 0 0

27.08.00 0 16101.3 0 3994.3 0 0 0 0

28.08.00 0 10474.54 0 6649.52 0 0 0 0

01.09.00 0 15049.43 0 3724.54 0 0 0 0

10.09.00 0 15976.2 0 3979.60 0 0 0 0

11.09.00 0 15887.93 0 3914.57 0 0 0 0

21.09.00 0 13382.3 0 2320.5 0 0 0 0

22.09.00 0 10967.77 0 7240.34 0 3359.02 0 0

01.10.00 0 9933.68 0 10326.5 0 5011.47 0 0

03.11.00 0 12468.90 0 2923.96 0 6241.46 0 0

02.1200 0 11884.03 0 1654.43 0 7183.8 0 0

03.01.01 0 13641.60 0 3276.84 0 7069.27 0 0


69

Table C.6 Continued

F-1H F-2H F-3H F-4H



02.02.01 0 14649.8 0 3472.09 0 7507.90 0 0

02.03.01 0 15233.40 0 3600.96 0 7894.81 0 0

02.04.01 0 14139.21 0 3250.34 0 7005.19 0 0

02.0501 0 14787.12 0 3461.9 0 7387.74 0 0

01.06.01 0 12876.6 0 2947.9 0 6182.9 0 0

01.06.01 0 15492.38 0 3634.38 0 7759.6 0 0

07.06.01 0 16017.4 0 3780.5 0 8094.4 0 0

07.06.01 0 15347.96 0 3622.07 0 7766.44 0 0

18.06.01 0 11756.4 0 2624.3 0 5615.20 0 0

19.06.01 0 11430.54 0 2651.73 0 5605.11 0 0

02.07.01 0 15371.2 0 3613.10 0 7726.10 0 0

03.07.01 0 15331.2 0 3604.10 0 7707.20 0 0

04.07.01 0 15090.67 0 3556.62 0 7617.51 0 0

16.07.01 0 14888.2 0 3512.8 0 7513.30 0 0

17.07.01 0 13925.55 0 3221.10 0 7039.20 0 0

30.07.01 0 14628.15 0 3443.7 0 7385.10 0 0

01.08.01 0 13769,00 0 3236 0 6941.81 0 0

11.08.01 0 13538.01 0 3201.73 0 6869.53 0 0

17.08.01 0 13657.69 0 3206.45 0 6873.38 0 0

02.09.01 0 14282.03 0 3355.64 0 7208.70 0 0

10.09.01 0 11262.15 0 2625.97 0 5601.37 0 1677.27

02.10.01 0 11538.03 0 2783.12 0 6282.13 0 2611.74

02.11.01 0 8540.19 0 2597.06 0 9102.73 0 5553.77

04.12.01 0 5497.64 0 4003.27 0 9605.65 0 2735.1

30.12.01 0 11840.67 0 4621.40 0 12087.87 0 0

01.01.02 0 8365.82 0 3769.53 0 8634.16 0 514.40

03.02.02 0 10039.78 0 3540.93 0 9884.78 0 4583.65

12.02.02 0 4016.90 0 1269.9 0 8891.70 0 688.6

13.02.02 0 10303.12 0 4618.12 0 10668.77 0 1127.72

01.03.02 0 10360.47 0 5512.13 0 9687.77 0 435.17

02.04.02 0 9916.17 0 5349.21 0 10335.98 0 457.94

01.05.02 0 9652.66 0 5358.03 0 10045.20 0 470.14

02.06.02 0 7563.64 0 4885.27 0 8920.3 0 560.52

02.07.02 0 10002.53 0 4963.51 0 10092.93 0 387.30

08.07.02 0 9974.77 0 4816.60 0 10065.27 0 541.93

11.07.02 0 10014.45 0 5133.60 0 10089.38 0 551.5

15.07.02 0 7869.75 0 2007.688 0 8050.46 0 214.68

02.08.02 0 6690.48 0 1381.15 0 5779.66 0 1339.4

14.08.02 0 10049.6 0 5191.20 0 10091.01 0 490.44

01.09.02 0 10199.5 0 5504.8 0 10210.9 0 570

02.09.02 0 9675.69 0 4875.70 0 5639.74 0 874.13

15.09.02 0 9520.88 0 2936.23 0 5991.16 0 2760.35

01.10.02 0 9740.62 0 5762.65 0 4300.03 0 2497.22


70

Table C.6 Continued

F-1H F-2H F-3H F-4H



08.10.02 0 10140.34 0 5053.10 0 3592.2 0 1659.66

14.10.02 0 9399.61 0 5080.57 0 3358.83 0 1728.43

02.11.02 0 10224.43 0 6106.92 0 3979.13 0 2128.67

17.11.02 0 10296.27 0 4929.26 0 3687.3 0 1445.31

02.12.02 0 10391.35 0 5169.95 0 3724.42 0 1767.33

24.12.02 0 9996.31 0 3868.8 0 4136.53 0 2949.91

01.01.03 0 11131.5 0 6410.20 0 4125.90 0 2373.60

02.01.03 0 10524.8 0 6122.11 0 3904.43 0 2283.73

12.01.03 0 10430.63 0 6116.04 0 3913.5 0 2463.60

20.01.03 0 10327.87 0 6211.91 0 3890.19 0 2538.53

03.02.03 0 9431.96 0 5504.75 0 3512.68 0 2147

14.02.03 0 10049.2 0 5948.47 0 3745.07 0 2381.26

01.03.03 0 10119.8 0 5462.8 0 3702.2 0 1893.2

06.03.03 0 10237.00 0 6103 0 3839 0 2418

07.03.03 0 9837.48 0 5947.88 0 2535.84 0 2498.64

03.04.03 0 9672.23 0 5770.4 0 3383.47 0 2344.07

04.05.03 0 7074.00 0 3689.1 0 2346.36 0 1529.68

03.06.03 0 11088.5 0 6565 0 4019 0 2532.5

04.06.03 0 6647.32 0 6412.75 0 3964.25 0 2990.29

02.07.03 0 11314.89 0 6735.78 0 4133.33 0 2619.67

10.07.03 0 11282.73 0 7109.73 0 4226.46 0 3139.96

02.08.03 0 11091.44 0 7034.11 0 4183.78 0 3157.56

11.08.03 0 11001.5 0 6893.5 0 4187 0 3021

12.08.03 0 10673.2 0 6723.95 0 4040.8 0 3002.95

01.09.03 0 10698.4 0 6471.5 0 3949.5 0 2587.4

02.09.03 0 10948.11 0 6806.34 0 4065.11 0 2908.11

10.09.03 0 10776.4 0 6708.75 0 4016.35 0 2884

12.09.03 0 10659.3 0 6599.4 0 3955.5 0 2792.60

13.09.03 0 10659.8 0 6622.37 0 3978.47 0 2858.7

16.09.03 0 8998.58 0 5574.45 0 6400.61 0 2329.06

01.10.03 0 9697.41 0 7019.78 0 4204.88 0 3249.8

24.10.03 0 9904.59 0 6765.5 0 4257.20 0 3307.36

02.11.03 0 7707.43 0 6553.43 0 4038.06 0 3244.81

20.11.03 0 6556.05 0 7026.03 0 4398.03 0 3691.03

04.12.03 0 0 0 8837.11 0 5469.9 0 3660.5

09.12.03 0 0 0 9093.6 0 5624.20 0 2976.3

10.12.03 0 7923.36 0 8028.41 0 4292.22 0 2322.29

18.12.03 0 11121.03 0 6983.13 0 4255.26 0 1908.64

01.01.04 0 11094.87 0 7084.45 0 4291.68 0 1804.02

19.01.04 0 10921.1 0 6846.5 0 4394.70 0 1990.2

20.01.04 0 10278.51 0 6175.08 0 4150.55 0 1840.45

02.02.04 0 10371.07 0 6764.76 0 4134.63 0 1829.52

01.03.04 0 10216.32 0 6710.72 0 4055.31 0 1829.51


71

Table C.6 Continued

F-1H F-2H F-3H F-4H



01.04.04 0 10136.57 0 6752.06 0 4121.38 0 1849.79

01.05.04 0 10009.55 0 6691.73 0 4121.70 0 1837.47

02.06.04 0 9981.06 0 6662.65 0 4153.25 0 1855.51

02.07.04 0 9493.05 0 6813.65 0 4233.10 0 1919.2

04.07.04 0 6645.15 0 6759.09 0 4184.45 0 2011.923

25.07.04 0 9118.49 0 5323.69 0 3471.61 0 1412.8571

01.08.04 0 9612.87 0 6537.58 0 4051.39 0 1801.271

16.08.04 0 9947.70 0 6841.70 0 4265.8 0 1897

17.08.04 0 3774.33 0 2493.42 0 1578.42 0 709.72

04.09.04 0 5282.78 0 3354.12 0 1986.71 0 859.49

20.09.04 0 10519.79 0 5972.67 0 3968.53 0 1761.06

01.10.04 0 8211.38 0 5744.24 0 3518.74 0 1534.46

01.11.04 0 9539.01 0 5406.91 0 3478.89 0 1395.41

04.12.04 0 10036.99 0 5846.83 0 3648.29 0 1555.88

05.01.05 0 10465.23 0 6540.83 0 3905.45 0 1733.44

15.01.05 0 9892.19 0 6018.92 0 3680.35 0 1580.49

29.01.05 0 9734.72 0 6024.07 0 3576.38 0 1627.62

02.02.05 0 10187.6 0 6411.39 0 3857.34 0 1708.24

05.03.05 0 10101.83 0 6370.70 0 3765.23 0 1707

24.03.05 0 10307.8 0 6570.9 0 3923.7 0 1773

25.03.05 0 10272.94 0 6553.19 0 3915.96 0 1769.63

03.04.05 0 9477.72 0 5830.37 0 3493.9 0 1557.13

27.04.05 0 9659.93 0 5954.86 0 3599.39 0 1567.53

03.05.05 0 10097.6 0 6422.04 0 3871.92 0 1335.64

02.06.05 0 10948.4 0 7195.8 0 4374.20 0 0

03.06.05 0 9992.87 0 6429.19 0 3838.85 0 1043.86

27.06.05 0 9089.24 0 5256.02 0 3248.82 0 1317.5

01.07.05 0 9912.40 0 6300.11 0 3713.62 0 1687.11

11.07.05 0 10510.9 0 6782.92 0 4024.67 0 1834.73

18.07.05 0 10604.6 0 6962.92 0 4213.93 0 479.35

30.07.05 0 10972.13 0 7321.87 0 4496.87 0 0

02.08.05 0 11095.25 0 7294.3 0 4423.9 0 375.65

04.08.05 0 10511.8 0 6909.5 0 4197.5 0 1823.4

05.08.05 0 10273.37 0 6673.73 0 4092.01 0 18.44

02.09.05 0 9392.15 0 6135.3 0 3776.8 0 30.2

17.09.05 0 9302.58 0 6222.01 0 3809.03 0 0

05.10.05 0 10408.1 0 6950.76 0 4077.43 0 0

09.11.05 0 6777.86 0 3992.13 0 2518.35 0 0

02.12.05 0 9827.6 0 5962 0 3581.2 0 0

03.12.05 0 8748.70 0 5207.52 0 3178.18 0 0

01.01.06 0 4114,00 0 1008.2 0 1180.95 0 0

03.01.06 0 9892.34 0 6256.08 0 3780.72 0 0

20.01.06 0 9297.46 0 5741.27 0 3441.27 0 0


72

Table C.6 Continued

F-1H F-2H F-3H F-4H



04.02.06 0 6665.94 0 3126.98 0 2215.83 0 0

26.02.06 0 8151.46 0 4814.84 0 2999.96 0 0

04.03.06 0 9545.9 0 3470.21 0 6720.04 0 0

06.04.06 0 9345.09 0 3501.10 0 6755.58 0 8.85

01.05.06 0 7336.23 0 2421.7 0 5301 0 1703.55

08.05.06 0 8995.01 0 3433.23 0 6564.05 0 1760.34

05.06.06 0 8818.43 0 3464 0 6433.22 0 1491.15

02.07.06 0 7966.77 0 1776.83 0 5629.78 0 1822.58

02.08.06 0 8875.11 0 2579.96 0 6637.75 0 2170.16

16.08.06 0 8947.3 0 3616.2 0 6840.10 0 2263.7

17.08.06 0 8152.13 0 3084.87 0 6461.91 0 2129.99

01.09.06 0 7850.23 0 2665.45 0 6154.85 0 2026.22

14.09.06 0 8260.26 0 2946.67 0 6373.20 0 2157.93

01.10.06 0 8554.23 0 3676.27 0 6865.33 0 2251.33

10.10.06 0 9177.92 0 3246.7 0 7287.46 0 0

15.10.06 0 9166.41 0 3913.07 0 7378.05 0 0

01.11.06 0 10124.41 0 3499.71 0 7247 0 0

09.11.06 0 10695.2 0 4304.55 0 4118.75 0 0

11.11.06 0 10179.93 0 4378.95 0 0 0 0

17.11.06 0 9662.38 0 4574.64 0 0 0 0

01.12.06 0 13000 0 11000 0 0 0 3000

21.01.07 0 13000 0 11000 0 13000 0 3000

01.05.07 0 13000 0 11000 0 13000 0 0

73

Appendix D

Eclipse .DATA le

Listing D.1: File BC0407.DATA

−− water i n j e c t i o n ra t e o f F−1, F−2, and F−3 by 50

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

−− Ny model July 2004 bu i ld by marsp/oddhu

−− New gr id with s l op ing f a u l t s based on geomodel xxx

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

RUNSPEC

−−LICENSES−−'NETWORKS' /

−−/

DIMENS

46 112 22 /

−−NOSIM

−−−− Allow f o r multregt , e t c . Maximum number o f r e g i on s 20 .

−−GRIDOPTS

'YES' 0 /

OIL

WATER

GAS

DISGAS

VAPOIL

METRIC

−− use e i t h e r h y s t e r e s i s or not h y s t e r e s i s

−−NOHYSTHYST

START

06 'NOV' 1997 /

EQLDIMS

5 100 20 /

EQLOPTS

'THPRES' / no f i n e e q u i l i b r a t i o n i f swa t i n i t i s being used

REGDIMS

−− n t f i p nmfipr n r f r e g n t f r e g

74

22 3 1* 20 /

TRACERS

−− o i l water gas env

1* 10 1* 1* /

WELLDIMS

−−ML 40 36 15 15 /

130 36 15 84 /

−−WSEGDIMS

−− 3 30 3 /

−−mlLGR−− maxlgr maxcls mcoars mamalg mxlalg l s t a c k in t e rp

−− 4 2000 0 1 4 20 'INTERP' /

TABDIMS

−−nts fun ntpvt nss fun nppvt n t f i p nrpvt ntendp

107 2 33 60 16 60 /

−− WI_VFP_TABLES_080905 . INC = 10−20

VFPIDIMS

30 20 20 /

−− Table no .

−− DevNew .VFP = 1

−− E1h .VFP = 2

−− AlmostVertNew .VFP = 3

−− GasProd .VFP = 4

−− NEW_D2_GAS_0.00003 .VFP = 5

−− GAS_PD2.VFP = 6

−− pd2 .VFP = 8 ( f l ow l i n e south )

−− pe2 .VFP = 9 ( f l ow l i n e north )

−− PB1 .PIPE . Ecl = 31

−− PB2 .PIPE . Ecl = 32

−− PD1.PIPE . Ecl = 33

−− PD2.PIPE . Ecl = 34

−− PE1 .PIPE . Ecl = 35

−− PE2 .PIPE . Ecl = 36

−− B1BH. Ecl = 37

−− B2H. Ecl = 38

−− B3H. Ecl = 39

−− B4DH. Ecl= 40

−− D1CH. Ecl = 41

−− D2H. Ecl = 42

−− D3BH. Ecl = 43

−− E1H. Ecl = 45

−− E3CH. Ecl = 47

−− K3H. Ecl = 48

VFPPDIMS

19 10 10 10 0 50 /

FAULTDIM

10000 /

PIMTDIMS

1 51 /

NSTACK

30 /

UNIFIN

UNIFOUT

−−RPTRUNSPEC

OPTIONS

77* 1 /

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− Input o f g r id geometry

75

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−GRID

NEWTRAN

GRIDFILE

2 /

−− opt i ona l f o r po s tp ro c e s s i ng o f GRID

MAPAXES

0 . 100 . 0 . 0 . 100 . 0 . /

GRIDUNIT

METRES /

−− do not output GRID geometry f i l e

−−NOGGF−− r eque s t s output o f INIT f i l e

INIT

MESSAGES

8*10000 20000 10000 1000 1* /

PINCH

0.001 GAP 1* TOPBOT TOP/

NOECHO

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− Grid and f a u l t s

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

−−−− Simulat ion gr id , with s l oop ing f a u l t s :

−−−− f i l e in UTM coord inate system , f o r import ing to Decis ionSpace

INCLUDE

' . /INCLUDE/GRID/IRAP_1005 .GRDECL' /

−− '/ p r o j e c t /norne6/ r e s /INCLUDE/GRID/IRAP_0704 .GRDECL' /

−−INCLUDE

' . /INCLUDE/GRID/ACTNUM_0704. prop ' /

−−−− Faults

−−−−INCLUDE

' . /INCLUDE/FAULT/FAULT_JUN_05. INC ' /

−− Al t e ra t i on o f t r a n sm i s c i b i l i t y by use o f the 'MULTFLT' keyword

−−INCLUDE

' . /INCLUDE/FAULT/FAULTMULT_AUG−2006.INC ' /

−− '/ p r o j e c t /norne6/ r e s /INCLUDE/FAULT/FAULTMULT_JUN_05. INC ' /

−− Addit iona l f a u l t s

−−Nord f o r C−3 ( f o r l e n g e l s e av C_10)

EQUALS

MULTY 0.01 6 6 22 22 1 22 /

/

−− B−3 water

EQUALS

'MULTX' 0 .001 9 11 39 39 1 22 /

'MULTY' 0 .001 9 11 39 39 1 22 /

'MULTX' 0 .001 9 9 37 39 1 22 /

'MULTY' 0 .001 9 9 37 39 1 22 /

/

−− C−1HEQUALS

'MULTY' 0 .001 26 29 39 39 1 22 /

/

76

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− Input o f g r id parametres

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

−−INCLUDE

' . /INCLUDE/PETRO/PORO_0704 . prop ' /

−−INCLUDE

' . /INCLUDE/PETRO/NTG_0704 . prop ' /

−−INCLUDE

' . /INCLUDE/PETRO/PERM_0704 . prop ' /

−− G segment north

EQUALS

PERMX 220 32 32 94 94 2 2 /

PERMX 220 33 33 95 99 2 2 /

PERMX 220 34 34 95 97 2 2 /

PERMX 220 35 35 95 98 2 2 /

PERMX 220 36 36 95 99 2 2 /

PERMX 220 37 37 95 99 2 2 /

PERMX 220 38 38 95 100 2 2 /

PERMX 220 39 39 95 102 2 2 /

PERMX 220 40 40 95 102 2 2 /

PERMX 220 41 41 95 102 2 2 /

/

−− C−1HMULTIPLY

PERMX 4 21 29 39 49 16 18 /

PERMX 100 21 29 39 49 19 20 /

/

COPY

PERMX PERMY /

PERMX PERMZ /

/

−− Permz reduct ion i s based on input from PSK

−− based on same kv/kh f a c t o r

−− ******************************************

−− CHECK! ( esp . I l e & Tofte )

−− ******************************************

MULTIPLY

'PERMZ' 0 .2 1 46 1 112 1 1 / Garn 3

'PERMZ' 0 .04 1 46 1 112 2 2 / Garn 2

'PERMZ' 0 .25 1 46 1 112 3 3 / Garn 1

'PERMZ' 0 .0 1 46 1 112 4 4 / Not ( i n a c t i v e anyway )

'PERMZ' 0 .13 1 46 1 112 5 5 / I l e 2 .2

'PERMZ' 0 .13 1 46 1 112 6 6 / I l e 2 . 1 . 3

'PERMZ' 0 .13 1 46 1 112 7 7 / I l e 2 . 1 . 2

'PERMZ' 0 .13 1 46 1 112 8 8 / I l e 2 . 1 . 1

'PERMZ' 0 .09 1 46 1 112 9 9 / I l e 1 .3

'PERMZ' 0 .07 1 46 1 112 10 10 / I l e 1 .2

'PERMZ' 0 .19 1 46 1 112 11 11 / I l e 1 .1

'PERMZ' 0 .13 1 46 1 112 12 12 / Tofte 2 .2

'PERMZ' 0 .64 1 46 1 112 13 13 / Tofte 2 . 1 . 3

'PERMZ' 0 .64 1 46 1 112 14 14 / Tofte 2 . 1 . 2

'PERMZ' 0 .64 1 46 1 112 15 15 / Tofte 2 . 1 . 1

'PERMZ' 0 .64 1 46 1 112 16 16 / Tofte 1 . 2 . 2

'PERMZ' 0 .64 1 46 1 112 17 17 / Tofte 1 . 2 . 1

'PERMZ' 0 .016 1 46 1 112 18 18 / Tofte 1 .1

'PERMZ' 0 .004 1 46 1 112 19 19 / T i l j e 4

'PERMZ' 0 .004 1 46 1 112 20 20 / T i l j e 3

'PERMZ' 1 .0 1 46 1 112 21 21 / T i l j e 2

'PERMZ' 1 .0 1 46 1 112 22 22 / T i l j e 1

/

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− Bar r i e r s

−−

77

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

−− MULTZ mu l t i p l i e s the t r a n sm i s s i b i l i t y between b locks

−− ( I , J , K) and ( I , J , K+1) , thus the b a r r i e r s are at the

−− bottom of the given l ay e r .

−− Region b a r r i e r s

−−−−INCLUDE

' . /INCLUDE/PETRO/MULTZ_HM_1. INC ' /

−−−− Field−wide b a r r i e r s

−−EQUALS

'MULTZ' 1 .0 1 46 1 112 1 1 / Garn3 − Garn 2

'MULTZ' 0 .05 1 46 1 112 15 15 / Tofte 2 . 1 . 1 − Tofte 1 . 2 . 2

'MULTZ' 0 .001 1 46 1 112 18 18 / Tofte 1 .1 − T i l j e 4

'MULTZ' 0.00001 1 46 1 112 20 20 / T i l j e 3 − T i l j e 2

−− The Top T i l j e 2 b a r r i e r i s inc luded as MULTREGT = 0.0

/

−− Local b a r r i e r s

−−INCLUDE

' . /INCLUDE/PETRO/MULTZ_JUN_05_MOD. INC ' /

−− 20 f l ux r eg i on s generated by the s c r i p t Xfluxnum

−−INCLUDE

' . /INCLUDE/PETRO/FLUXNUM_0704. prop ' /

−− modify t r a n sm i s s i b i l i t e s between fluxnum using MULTREGT

−−INCLUDE

' . /INCLUDE/PETRO/MULTREGT_D_27. prop ' /

NOECHO

MINPV

500 /

EQUALS

'MULTZ' 0.00125 26 29 30 37 10 10 / be t t e r WCT match f o r B−2H'MULTZ' 0 .015 19 29 11 30 8 8 / be t t e r WCT match f o r D−1CH

'MULTZ' 1 6 12 16 22 8 11 / f o r be t t e r WCT match f o r K−3H'MULTZ' . 1 6 12 16 22 15 15 / f o r be t t e r WCT match f o r K−3H/

EDIT

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

−− mod i f i c a t i on r e l a t ed to HM of G−segment aug−2006MULTIPLY

'TRANX' 0 .1 30 46 72 112 2 2 /

'TRANX' 0 .1 30 46 72 112 3 3 /

'TRANY' 5 30 46 72 112 2 2 /

'TRANY' 10 30 46 72 112 3 3 /

−−'TRANX' 10 29 29 67 70 1 3 /

'TRANY' 10 30 41 67 67 1 3 /

−−'TRANX' 0 .05 34 34 76 95 1 3 /

'TRANY' 0 .001 30 41 67 67 1 3 / Open aga in s t the main f i e l d

−−'TRANY' 0 .5 30 30 90 93 1 3 / Inc r ea s e TRANY aga in s t the we l l

'TRANY' 0 .5 31 32 94 94 1 3 / Inc r ea s e TRANY aga in s t the we l l

−−−−'TRANY' 0 .5 31 31 87 93 1 3 /

−−−−'TRANY' 0 .5 30 30 85 89 1 1 /

78

'TRANY' 2 30 30 72 82 1 3 /

'TRANY' 0 .8 30 30 82 93 1 3 /

−−−−'TRANX' 10 34 34 92 95 1 3 / Inc r ea s e TRANX trough the f a u l t aga in s t the we l l

'TRANX' 0 34 34 90 91 1 3 /

'TRANX' 2 34 38 88 89 1 3/

−−'TRANX' 2 35 36 93 95 1 3 /

'TRANX' 0 .1 35 36 90 91 1 3 /

'TRANX' 10 35 38 95 98 1 3 /

'TRANX' 5 31 31 91 92 1 3 / Inc r ea s e TRANX aga in s t the we l l

−−−−'TRANX' 2 31 33 92 95 1 3 /

−−'TRANY' 2 30 31 79 86 3 3 /

'TRANY' 3 30 30 86 86 2 2 /

−−−−'TRANY' 0 .7 34 41 72 80 1 3 /

'TRANX' 2 31 31 87 94 1 3 /

−−'TRANY' 0.0004 37 41 71 71 1 3 /

'TRANY' 2 30 31 87 93 2 3 /

'TRANX' 5 34 34 88 90 1 3 /

−−'TRANY' 1 .5 33 35 94 96 2 3 /

−−

'TRANX' 2 30 41 68 70 1 3 / Inc r ea s e t rans around F−4H−−/

EQUALS

'TRANY' 20 31 31 85 85 1 3 / SET TRANY u l i k 0 trougth the f a u l t

'TRANY' 30 30 30 93 93 2 2 /

'TRANY' 30 32 32 84 84 1 3 /

'TRANY' 30 30 30 93 93 3 3 /

−−−−'TRANY' 30 31 32 95 95 2 3 /

'TRANY' 30 31 32 94 94 1 1 /

'TRANY' 20 33 33 96 96 2 3 /

'TRANY' 20 34 34 97 97 2 3 /

−−−−'TRANX' 0 33 33 71 81 1 3 / s e t the f a u l t t i gh t

'TRANX' 0 34 34 76 85 1 3 /

−−'TRANY' 0 33 33 71 81 1 3 / Set the f a u l t t i g t

'TRANY' 0 34 34 76 85 1 3 /

−−'TRANY' 0 33 36 71 71 1 3 /

'TRANX' 0 34 41 71 71 1 3 /

−−'TRANY' 0 33 33 71 72 1 3 / Decrease TRANY trougth the f a u l t

−−'TRANX' 0 34 34 73 75 1 3 / Set the f a u l t t i gh t

'TRANY' 0 34 34 71 75 1 3 /

−−/

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

PROPS

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− Input o f f l u i d p r op e r t i e s and r e l a t i v e pe rmeab i l i ty

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

NOECHO

−− Input o f PVT data f o r the model

79

−− Total 2 PVT reg i on s ( r eg ion 1 C,D,E segment , r eg ion 2 Gsegment )

−−INCLUDE

' . /INCLUDE/PVT/PVT−WET−GAS.DATA' /

TRACER

'SEA' 'WAT' /

'HTO' 'WAT' /

' S36 ' 'WAT' /

'2FB' 'WAT' /

'4FB' 'WAT' /

'DFB' 'WAT' /

'TFB' 'WAT' /

/

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− i n i t i a l i z a t i o n and relperm curves : s ee r epor t b lab la

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

−− r e l . perm and cap . p r e s su r e t ab l e s −−

−−INCLUDE

' . /INCLUDE/RELPERM/HYST/swof_mod4Gseg_aug−2006. inc ' /

−− '/ p r o j e c t /norne6/ r e s /INCLUDE/RELPERM/HYST/swof . inc ' /

−−Sgc=10 0.000000 or g−segment

−−INCLUDE

' . /INCLUDE/RELPERM/HYST/sgof_sgc10_mod4Gseg_aug−2006. inc ' /

−− '/ p r o j e c t /norne6/ r e s /INCLUDE/RELPERM/HYST/ sgof_sgc10 . inc ' /

−−INCLUDE

' . /INCLUDE/RELPERM/HYST/waghystr_mod4Gseg_aug−2006. inc ' /

−− '/ p r o j e c t /norne6/ r e s /INCLUDE/RELPERM/HYST/waghystr . inc ' /

−−RPTPROPS−− 1 1 1 5*0 0 /

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

REGIONS

−−INCLUDE

' . /INCLUDE/PETRO/FIPNUM_0704 . prop ' /

−−INCLUDE

' . /INCLUDE/PETRO/SATNUM_0704. prop ' /

EQUALS

'SATNUM' 102 30 41 76 112 1 1 /

'SATNUM' 103 30 41 76 112 2 2 /

'SATNUM' 104 30 41 76 112 3 3 /

/

−−INCLUDE

' . /INCLUDE/PETRO/IMBNUM_0704. prop ' /

EQUALS

'SATNUM' 102 30 41 76 112 1 1 /

'SATNUM' 103 30 41 76 112 2 2 /

'SATNUM' 104 30 41 76 112 3 3 /

/

−−INCLUDE

' . /INCLUDE/PETRO/PVTNUM_0704. prop ' /

EQUALS

'PVTNUM' 1 1 46 1 112 1 22 /

80

/

−−INCLUDE

' . /INCLUDE/PETRO/EQLNUM_0704. prop ' /

−− extra r eg i on s f o r g e o l o g i c a l format ions and numerical l a y e r s

INCLUDE

' . /INCLUDE/PETRO/EXTRA_REG. inc ' /

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

SOLUTION

RPTRST

BASIC=2 /

RPTSOL

FIP=3 /

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− equ i l i b r ium data : do not inc lude t h i s f i l e in case o f RESTART

−−−−INCLUDE

' . /INCLUDE/PETRO/E3 . prop ' /

−− r e s t a r t date : only used in case o f a RESTART, remember to use SKIPREST

−−RESTART−− 'BASE_30−NOV−2005 ' 360 / AT TIME 3282.0 DAYS ( 1−NOV−2006)

THPRES

1 2 0.588031 /

2 1 0.588031 /

1 3 0.787619 /

3 1 0.787619 /

1 4 7.00083 /

4 1 7.00083 /

/

−− i n i t i a l i s e i n j e c t e d t r a c e r s to zero

TVDPFSEA

1000 0 .0

5000 0 .0 /

TVDPFHTO

1000 0 .0

5000 0 .0 /

TVDPFS36

1000 0 .0

5000 0 .0 /

TVDPF2FB

1000 0 .0

5000 0 .0 /

TVDPF4FB

1000 0 .0

5000 0 .0 /

TVDPFDFB

1000 0 .0

5000 0 .0 /

TVDPFTFB

1000 0 .0

5000 0 .0 /

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

SUMMARY

−−INCLUDE

' . /INCLUDE/SUMMARY/summary . data ' /

−−INCLUDE

' . /INCLUDE/SUMMARY/ extra . inc ' /

−−INCLUDE

' . /INCLUDE/SUMMARY/ t r a c e r . data ' /

81

−−INCLUDE

' . /INCLUDE/SUMMARY/gas . inc ' /

−−INCLUDE

' . /INCLUDE/SUMMARY/wpave . inc ' /

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

SCHEDULE

−− use SKIPREST in case o f RESTART

−−SKIPREST

−− No in c r e a s e in the s o l u t i on gas−o i l r a t i o ? !

DRSDT

0 /

−− Use o f WRFT in order to r epor t we l l p e r s su r e data a f t e r f i r s t

−− opening o f the we l l . The we l l s are pe r f o ra t ed in the e n t i r e r e s e r v o i r

−− produce with a smal l r a t e and are squeesed a f t e r 1 day . This p r e s su r e

−− data can sen be copmared with the MDT pre s su r e po in t s c o l l e c t e d in the

−− we l l .

NOECHO

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−=======Production Wells========−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

−−INCLUDE

' . /INCLUDE/VFP/DevNew .VFP' /

−−INCLUDE

' . /INCLUDE/VFP/E1h .VFP' /

−−INCLUDE

' . /INCLUDE/VFP/NEW_D2_GAS_0.00003 .VFP' /

−−INCLUDE

' . /INCLUDE/VFP/GAS_PD2.VFP' /

−−INCLUDE

' . /INCLUDE/VFP/AlmostVertNew .VFP' /

−−INCLUDE

' . /INCLUDE/VFP/GasProd .VFP' /

−− 01 . 01 . 07 new VFP curves f o r producing we l l s , matched with the l a t e s t we l l t e s t s in Prosper . lmarr

−−INCLUDE

' . /INCLUDE/VFP/B1BH. Ecl ' /

−−INCLUDE

' . /INCLUDE/VFP/B2H. Ecl ' /

−−INCLUDE

' . /INCLUDE/VFP/B3H. Ecl ' /

−−INCLUDE

' . /INCLUDE/VFP/B4DH. Ecl ' /

−−INCLUDE

' . /INCLUDE/VFP/D1CH. Ecl ' /

−−INCLUDE

' . /INCLUDE/VFP/D2H. Ecl ' /

−−INCLUDE

' . /INCLUDE/VFP/D3BH. Ecl ' /

−−

82

INCLUDE

' . /INCLUDE/VFP/E1H. Ecl ' /

−−INCLUDE

' . /INCLUDE/VFP/E3CH. Ecl ' /

−−INCLUDE

' . /INCLUDE/VFP/K3H. Ecl ' /

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−=======Production F lowl ine s========−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− 16 . 5 . 02 new VFP curves f o r southgoing PD1,PD2,PB1 ,PB2 f l ow l i n e s −> pd2 .VFP

−−INCLUDE

' . /INCLUDE/VFP/pd2 .VFP' /

−−−− 16 . 5 . 02 new VFP curves f o r northgoing PE1 ,PE2 f l ow l i n e s −> pe2 .VFP

−−INCLUDE

' . /INCLUDE/VFP/pe2 .VFP' /

−− 24 . 11 . 06 new matched VLP curves f o r PB1 va l i d from 01 .07 . 06

−−INCLUDE

' . /INCLUDE/VFP/PB1 .PIPE . Ecl ' /

−−24.11.06 new matched VLP curves f o r PB2 va l i d from 01 .07 . 06

−−INCLUDE

' . /INCLUDE/VFP/PB2 .PIPE . Ecl ' /

−−24.11.06 new matched VLP curves f o r PD1 va l i d from 01 .07 . 06

−−INCLUDE

' . /INCLUDE/VFP/PD1.PIPE . Ecl ' /

−−24.11.06 new matched VLP curves f o r PD2 va l i d from 01 .07 . 06

−−INCLUDE

' . /INCLUDE/VFP/PD2.PIPE . Ecl ' /

−−24.11.06 new matched VLP curves f o r PE1 va l i d from 01 .07 . 06

−−INCLUDE

' . /INCLUDE/VFP/PE1 .PIPE . Ecl ' /

−−24.11.06 new matched VLP curves f o r PE2 va l i d from 01 .07 . 06

−−INCLUDE

' . /INCLUDE/VFP/PE2 .PIPE . Ecl ' /

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−=======INJECTION FLOWLINES 08 .09 .2005 ========−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− VFPINJ nr . 10 Water i n j e c t i o n f l ow l i n e WIC

−−INCLUDE

' . /INCLUDE/VFP/WIC.PIPE . Ecl ' /

−− VFPINJ nr . 11 Water i n j e c t i o n f l ow l i n e WIF

−−INCLUDE

' . /INCLUDE/VFP/WIF.PIPE . Ecl ' /

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−======= INJECTION Wells 08 .09 .2005 ========−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− VFPINJ nr . 12 Water i n j e c t i o n we l lbore Norne C−1H−−INCLUDE

' . /INCLUDE/VFP/C1H. Ecl ' /

83

−− VFPINJ nr . 13 Water i n j e c t i o n we l lbore Norne C−2H−−INCLUDE






−− VFPINJ nr . 16 Water i n j e c t i o n we l lbore Norne C−4AH−−INCLUDE

' . /INCLUDE/VFP/C4AH. Ecl ' /

−− VFPINJ nr . 17 Water i n j e c t i o n we l lbore Norne F−1H−−INCLUDE

' . /INCLUDE/VFP/F1H. Ecl ' /



−− VFPINJ nr . 19 Water i n j e c t i o n we l lbore Norne F−3 H

−−INCLUDE




TUNING

1 10 0 .1 0 .15 3 0 .3 0 .3 1 .20 /

5* 0 .1 0 .0001 0 .02 0 .02 /

−−2* 40 1* 15 /

/

−− only p o s s i b l e f o r ECL 2006.2+ ve r s i on

ZIPPY2

'SIM=4.2 ' 'MINSTEP=1E−6' /

/

−−WSEGITER

−−/

−− PI reduct ion in case o f water cut

−−INCLUDE

' . /INCLUDE/PI/pimultab_low−high_aug−2006. inc ' /

−− History and p r ed i c t i on −−−−INCLUDE

' . /INCLUDE/BC0407 .SCH' /

END

84

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Statoil. Geological and Petrophysical Report Norne Field PL 128 Wells 6608/10-D-1 AH and

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88

Thesis Signe and Mari

Documents

real model

model withreal data

model basedon

field case

norne reservoir rocks

geological model

real data fromthe norne

reservoir development