Post on 12-Jan-2016
description
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.4 Oil Production Rate B-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
B.5 Watercut B-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
B.6 Gas-Oil Ratio B-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
B.7 Oil Production Rate B-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
B.8 Watercut B-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
B.9 Gas-Oil Ratio B-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
B.10 Oil Production Rate B-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
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.16 Oil Production Rate D-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
B.17 Watercut D-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
VI
B.18 Gas-Oil Ratio D-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
B.19 Oil Production Rate D-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
B.20 Watercut D-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
B.21 Gas-Oil Ratio D-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
B.22 Oil Production Rate D-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
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.28 Oil Production Rate E-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
B.29 Watercut E-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
B.30 Gas-Oil Ratio E-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
B.31 Oil Production Rate E-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
B.32 Watercut E-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
B.33 Gas-Oil Ratio E-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
B.34 Oil Production Rate E-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
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.42 Water Injection Rate C-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
B.43 Water Injection Rate C-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
B.44 Gas Injection Rate C-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
B.45 Water Injection Rate C-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
B.46 Gas Injection Rate C-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
B.47 Water Injection Rate F-1H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
B.48 Water Injection Rate F-2H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
B.49 Water Injection Rate F-3H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
B.50 Water Injection Rate F-4H . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
B.51 3D Seismic, line number 1100 showing the oil-water contact in 2001 . . . . . . . . 29
B.52 3D Seismic, line number 1100 showing the oil-water contact in 2003 . . . . . . . . 30
B.53 3D Seismic, line number 1100 showing the oil-water contact in 2004 . . . . . . . . 31
B.54 3D Seismic, line number 1100 showing the oil-water contact in 2006 . . . . . . . . 32
B.55 3D Seismic, trace number 1600 showing the oil-water contact in 2001 . . . . . . . 33
B.56 3D Seismic, trace number 1600 showing the oil-water contact in 2003 . . . . . . . 33
B.57 3D Seismic, trace number 1600 showing the oil-water contact in 2004 . . . . . . . 34
VII
B.58 3D Seismic, trace number 1600 showing the oil-water contact in 2006 . . . . . . . 34
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
TVD [m] [fraction] [fraction] [fraction]
Garn 3 Gas 11.0 0.302 0.121 0.982Garn 2 Gas 10.3 0.252 0.149 0.893Garn 1 Total 12.2 0.198 0.304 0.869
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
TVD [m] [fraction] [fraction] [fraction]
Garn 3 Gas 9.9 0.325 0.112 0.998Garn 2 Gas 9.8 0.276 0.130 0.673Garn 1 Total 16.6 0.248 0.224 0.703
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
TVD [m] [fraction] [fraction] [fraction]
Garn 3 Gas 9.9 0.325 0.112 0.998Garn 2 Gas 9.8 0.262 0.144 0.751Garn 1 Total 16.6 0.239 0.249 0.859
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)
4. Discuss and compare results
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
4. Discuss and compare results
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
Figure B.4: Oil Production Rate B-2H
Figure B.5: Watercut B-2H
5
Figure B.6: Gas-Oil Ratio B-2H
Figure B.7: Oil Production Rate B-3H
6
Figure B.8: Watercut B-3H
Figure B.9: Gas-Oil Ratio B-3H
7
Figure B.10: Oil Production Rate B-4H
Figure B.11: Watercut B-4H
8
Figure B.12: Gas-Oil Ratio B-4H
Figure B.13: Oil Production Rate D-1H
9
Figure B.14: Watercut D-1H
Figure B.15: Gas-Oil Ratio D-1H
10
Figure B.16: Oil Production Rate D-2H
Figure B.17: Watercut D-2H
11
Figure B.18: Gas-Oil Ratio D-2H
Figure B.19: Oil Production Rate D-3H
12
Figure B.20: Watercut D-3H
Figure B.21: Gas-Oil Ratio D-3H
13
Figure B.22: Oil Production Rate D-4H
Figure B.23: Watercut D-4H
14
Figure B.24: Gas-Oil Ratio D-4H
Figure B.25: Oil Production Rate E-1H
15
Figure B.26: Watercut E-1H
Figure B.27: Gas-Oil Ratio E-1H
16
Figure B.28: Oil Production Rate E-2H
Figure B.29: Watercut E-2H
17
Figure B.30: Gas-Oil Ratio E-2H
Figure B.31: Oil Production Rate E-3H
18
Figure B.32: Watercut E-3H
Figure B.33: Gas-Oil Ratio E-3H
19
Figure B.34: Oil Production Rate E-4H
Figure B.35: Watercut E-4H
20
Figure B.36: Gas-Oil Ratio E-4H
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
Figure B.42: Water Injection Rate C-2H
Figure B.43: Water Injection Rate C-3H
24
Figure B.44: Gas Injection Rate C-3H
Figure B.45: Water Injection Rate C-4H
25
Figure B.46: Gas Injection Rate C-4H
Figure B.47: Water Injection Rate F-1H
26
Figure B.48: Water Injection Rate F-2H
Figure B.49: Water Injection Rate F-3H
27
Figure B.50: Water Injection Rate F-4H
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
Figure B.52: 3D Seismic, line number 1100 showing the oil-water contact in 2003
30
Figure B.53: 3D Seismic, line number 1100 showing the oil-water contact in 2004
31
Figure B.54: 3D Seismic, line number 1100 showing the oil-water contact in 2006
32
Figure B.55: 3D Seismic, trace number 1600showing the oil-water contact in 2001
Figure B.56: 3D Seismic, trace number 1600showing the oil-water contact in 2003
33
Figure B.57: 3D Seismic, trace number 1600showing the oil-water contact in 2004
Figure B.58: 3D Seismic, trace number 1600showing the oil-water contact in 2006
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
TableC.3:Productiondata
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
TableC.4:Productiondata
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
ContinuedonNextPage...
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
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
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
Continued on Next Page. . .
64
Table C.5 Continued
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
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
Continued on Next Page. . .
65
Table C.5 Continued
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
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
Continued on Next Page. . .
66
Table C.5 Continued
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
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
Continued on Next Page. . .
67
Table C.5 Continued
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
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
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
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
Continued on Next Page. . .
69
Table C.6 Continued
F-1H F-2H F-3H F-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
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
Continued on Next Page. . .
70
Table C.6 Continued
F-1H F-2H F-3H F-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
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
Continued on Next Page. . .
71
Table C.6 Continued
F-1H F-2H F-3H F-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
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
Continued on Next Page. . .
72
Table C.6 Continued
F-1H F-2H F-3H F-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
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
' . /INCLUDE/VFP/C2H. Ecl ' /
−− VFPINJ nr . 14 Water i n j e c t i o n we l lbore Norne C−3H−−INCLUDE
' . /INCLUDE/VFP/C3H. Ecl ' /
−− VFPINJ nr . 15 Water i n j e c t i o n we l lbore Norne C−4H−−INCLUDE
' . /INCLUDE/VFP/C4H. Ecl ' /
−− 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 . 18 Water i n j e c t i o n we l lbore Norne F−2H−−INCLUDE
' . /INCLUDE/VFP/F2H. Ecl ' /
−− VFPINJ nr . 19 Water i n j e c t i o n we l lbore Norne F−3 H
−−INCLUDE
' . /INCLUDE/VFP/F3H. Ecl ' /
−− VFPINJ nr . 20 Water i n j e c t i o n we l lbore Norne F−4H−−INCLUDE
' . /INCLUDE/VFP/F4H. Ecl ' /
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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