Groningen Gas Field: Heterogeneities characterization of the sediments, by log evaluation.

by Aran Amin

August 2014

Committee members: Dr. A. Barnhoon & Dr. Karl-Heinz Wolf

Section for Applied Geophysics & Petrophysics, Department of Civil Engineering and Geosciences, Delft University of Technology Title: Groningen Gas Field: Heterogeneities characterization of the sediments,by log evalu- ation.

Author(s): Aran Amin

Date: August, 2014

Professor: Dr. A. Barnhoorn

TA Report number: BTA/TGP/14-22

Postal Address: Section for Applied Geophysics & Petrophysics Department of Geoscience & Engineering Delft University of Technology P.O. Box 5028 The Netherlands

Telephone: (31) 15 2781328 (secretary)

Telefax: (31) 15 2781189

Copyright 2014 Section for Applied Geophysics & Petrophysics

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No parts of this publication may be reproduced, Stored in a retrieval system, or transmitted, In any form or by any means, electronic, Mechanical, photocopying, recording, or otherwise, Without the prior written permission of the Section for Applied Geophysics & Petrophysics.

1 Abstract

This research focuses on the analyze of the heterogeneity of the Groningen gas field, i.e. charac- terization of the reservoir rock and the sealing Zechstein salt on top of the reservoir, by modeling the rock properties of the formations. The aim of this study is twofold, namely to characterize the thickness, shale content and porosity of the reservoir rock and the sealing Zechstein salt. But also to set an geological framework of the Groningen gas field, which can serve as a basic input for subsidence studies and geomechanical modeling of the Groningen field. The Gronin- gen gas field was first discovered in 1959 by well Slochteren 1 and has an horizontal extent of around 900 km2. The reservoir is situated at a depth of 2600-3200 m and the estimated recoverable volume is about 2700 billion m3. It lies within the Southern Permian Basin gas province, an extensive E-W stretched sedimentary basin. In order to analyze the heterogeneity of the sediments(this include the Ten Boer, Ameland and Slochteren member) and the salt rock, software named Quantumgis is used to obtain two dimensional interpolated plots of the three evaluated rock properties. The three rock properties evaluated are thicknesses, shale content and porosities. Well log data have been used to determine these properties. For the thicknesses, the penetration depth of the well bores are used. For the determination of the shale content, gamma-ray and spontaneous potential logs have been used. And eventually, the porosities are derived from density and neutron logs. The used data is obtained from NLOG, the Dutch gas and oil portal. The Zechstein member is a relative thick formation, and show a relative hetero- geneous thickness pattern. The Ten Boer member has a relative homogeneous thickness pattern. It has a high shale content and low porosity. Both properties show a heterogeneous pattern. The Ameland member is relative thin and is only present in the northern half of the field, with a high shale content. The distribution of the shale content show a heterogeneous pattern. Fi- nally, the Slochteren member, which is the main reservoir rock, has a heterogeneous thickness pattern. The porosities are high and the shale content is relative low. Both properties show a relative homogeneous pattern. In short, the evaluated formations show a relative heterogenous pattern for the three rock properties. If one relates the obtained models in this research with the compaction models done by the NAM [NAM, 2013], it is clear that production must be reduced or completely stopped in regions with high porosities, since at these regions subsidence values are the highest. This will lead to less compaction and a lower chance of seismic activities.

2 Contents

Abstract 2

1 Introduction 4

2 Geologic Setting 7 2.1 Geological history of the field ...... 7 2.2 Lithostratigraphy ...... 8

3 Literature Review 11 3.1 Well-log Interpretation ...... 11 3.2 Porosity, Shale Content & Formation Thickness ...... 12 3.2.1 Introduction ...... 12 3.2.2 Porosity ...... 12 3.2.3 Shale Content ...... 13

4 Data collection, Design & Processing 17 4.1 Data Collection ...... 17 4.2 Research Design ...... 17 4.3 Data Processing ...... 18

5 Results 24 5.1 Model Interpretations ...... 24 5.1.1 Formation Thickness ...... 24 5.1.2 Formation Shale Content ...... 28 5.1.3 Formation Porosity ...... 31 5.2 Compaction effects ...... 33

6 Discussion 36 6.1 Model comparison ...... 36 6.2 Limitations & Difficulties ...... 36

7 Conclusions 40

8 Recommendations 42

A Appendices 43

3 Chapter 1

Introduction

The Groningen gas field was discovered in 1959 by well Slochteren 1 (SLO-1) and lies in the Northeastern part of the Netherlands, see figure 1.1. The field has a horizontal extent of around 900 km2. The reservoir is situated at a depth of 2600-3200 m and its thickness varies between 100 and 200 m. The estimated recoverable volume is about 2700 billion m3 [Ketelaar, 2009]. The discovery of the field has been playing a huge role in the economical growth of the Nether- lands and is therefore of big importance for the country and its citizens. But on the other hand research has shown that the production of gas leads to a certain amount of ground subsidence, which is the negative part of the story. The amount of ground subsidence due to hydrocarbon production depends on several factors, like the rate of production and the geologic history of the field. The subsidence at the Groningen gas field and the surrounding area is a hot issue these days in the Netherlands, because it is proven that they lead to induced earthquakes in the Groningen area. Since 1986 relatively small earthquakes has occurred in the Groningen area in the Northern Netherlands, which caused damage to buildings and public houses. In the Huizinge area, on August 16th 2012 the strongest earthquake was recorded with a magnitude of 3.6 on the richter scale, causing significant damage and of course pubic concerns. It is clear that these events are causing feelings of unease amongst the citizens, so they need to be analyzed carefully.

A multidisciplinary study, initiated by the Ministry of Economic Affairs, analyzed the relation- ship between gas production and earthquakes. The conclusion is, based on the seismic pattern and the frequency magnitude distribution, that the earthquakes are of non-tectonic origin and most likely are induced by reservoir depletion [NAM, 2013]. In a report of TNO, an indepen- dent dutch research organization, subsidence and seismic hazard calculations are done with the purpose to bring out advice on the improvement of the Groningen field production plan to min- imize subsidence effects. Several production scenario’s and compaction models are considered, in which each model/method or a combination leads to different reservoir subsidence predictions.

This research focuses on the analyze of the heterogeneity of the Groningen gas field, i.e. charac- terization of the reservoir rock and the sealing Zechstein salt on top of the reservoir by modeling the rock properties. Heterogeneity in a hydrocarbon reservoir is referred to non-uniform, non- linear spacial distribution of rock properties [Mohaghegh et al., 1996]. The aim of this study is twofold, namely to characterize the porosity, thickness and shale content of the reservoir rock and the sealing Zechstein salt. But also to set an geological framework of the Groningen gas field, which can serve as a basic input for subsidence studies and geomechanical modeling of the Groningen field. But in this research the main focus will be on the first one, since several com- paction models and subsidence studies has already been realized by the Nederlandse Aardolie Maatschappij (NAM).

The characterization of the reservoir rock and the sealing salt rock is done by log evaluation, i.e. using information of data from the drilled wells in the Groningen gas field. All the data used, is obtained from the online Dutch Gas and Oil Portal(NLOG). The site provides information

4 about oil, gas and geothermal energy exploration and production in the Netherlands and the Dutch sector of the North Sea continental shelf. The data is used to set up models for the three petrophysical rock parameters (porosity, shale content and thickness). There are also other pa- rameters like the fluid saturation of the rock and the fault system in the research area that can be used to analyze the heterogeneity of the Groningen field, but in this research they are not included. The output of the data exists of trend maps of the three analyzed rock parameters. The main software used to obtain these trend maps is Quantum GIS (Geographical Information System).

In the next chapter the geologic setting of the Groningen gas field is described to get famil- iar with the reservoir rock and the overburden and underlying rocks. Then the used theory for this research, which finds its character in the Petrophysical discipline is described. In the data collection, design & processing section, the general strategy and method used to obtain the results is described. And finally the results, discussion and conclusions are given.

5 Figure 1.1: Location map of the Groningen Gas Field showing fault lineations, the Top Rotliegend depth contours, and the extent of the gas-filled area in green. Coastlines are shown as light blue lines. Key exploration wells and development clusters are indicated in various colours reflecting the time of drilling (see inserted legend), from [Gr¨otsch and Gaupp, 2011].

6 Chapter 2

Geologic Setting

2.1 Geological history of the field

The Groningen field lies within the Southern Permian Basin (SPB) gas province, an extensive E-W stretched sedimentary basin. It is formed on top of folded and tilted Carboniferous and older sediments in the foreland of the Variscan fold and thrust belt [Gr¨otsch and Gaupp, 2011]. The geological structure of the Groningen gas field in its present configuration started at late Carboniferous time. From this period in the geological history of the field there is evidence of the creation of the current structure. Unfortunately a more detailed reconstruction of the geologic history of the field isn’t possible, since erosion ’erased’ the more interesting gradual stratigraphic changes and effects of tectonic events in the area during depositional periods [Stauble and Mil- ius, 1970].

Evidence is found from the Upper Carboniferous-Lower Permian record, and confirms that the Groningen area was structurally high positioned. During this period the area was strongly affected by the last tectonic phases of the Variscan orogeny. These tectonics created uplifts, faulting and truncation. The truncation process leaded to two important unconformities in the area. During the Variscan orogeny a mountain range in the South of the Netherlands was created leading to deposition of Late Pennsylvanian redbeds. These redbeds covered the older Pennsyl- vanian deltaic shales, sandstones and coals. The seperation of the coal-bearing layer from the Late Pennsylvanian red beds is also known as the Asturian unconformity [Stauble and Milius, 1970]. The second unconformity separates the redbeds from the Rotliegendes formation, and is known as the Saalian unconformity. This unconformity is found in a well, in the East of the Groningen field, which is shown in figure 2.1. Here the strong change in the Self Potential value indicates the transition of the Rotliegendes formation into the redbeds from the Pennsylvanian Period.

These two unconformities are mainly found in the East, South and Southwest of the field. There are two explanations possible for the unconformities. The first one suggests that a large tectonic element attained a structurally high position of the field during the Asturian tectonic phase until the Early Permian Saalian tectonic phase. And the second one would be that the Groningen field was part of the Post-Asturian sedimentary basin, which was uplifted and trun- cated during the Saalin tectonic phase. There is not enough evidence too confirm one of the possible theories, but both explanations suggest that the Groningen area was structurally high positioned during the late Carboniferous time.

Further in time, when speaking of the Permian period until Late Jurassic, the Groningen area was part of the Northwest Europian sedimentary basin. This basin was formed during the Saalian tectonic phase. In figure 2.2 , we notice that the Jurassic time and a large part of the Triassic section is missing, due to erosion. This was in the period of the Late Kimmerian tectonic phase. In the Lower Triassic section, there is some evidence of formation of regional shallow

7 Figure 2.1: SP Log evidence, showing the Saalian unconformity.

Figure 2.2: Schematic cross-section through the Groningen field [Glennie, 2013] north-south striking swells and depressions. Complete sequences are found in the depressions, but not in the swells. From this one can say that the South of the Groningen field may have been part of a swell in the Lower Triassic period, since truncation is found. The uplift, caused by the late Kimmerian tectonic phase led to the formation of the Groningen field structure in its present configuration.

Finally, when the Laramide tectonic phase occurred during Late Cretaceous-early Tertiary, the Northern Netherlands part remained stable, while other parts of the Netherlands were strongly uplifted and truncated. Also during the Oligocene time, in the time of the late Alpine orogeny, the Groningen area remained also stable.

2.2 Lithostratigraphy

In this section, the focus is on the stratigraphy of the Groningen gas field. It is described chronologically, beginning with the oldest formation. Understanding the stratigraphy is a key to knowledge about the appearance of the accumulated gas in the reservoir, but also a key to

8 understanding the induced earthquakes at the area. For example: a higher porous rock leads to a higher potential of the rock to compact when pumping the gas out of the reservoir.

In the Groningen area all formations consists of sedimentary rocks, see figure 2.3. The old- est rock are from the Pennsylvanian period and consists of alternating deltaic shale, sandstone and coal. In late Pennsylvian, redbeds were deposited derived from a mountain range in the South of the Netherlands. So the deltaic facies turned into red bed facies without coal.

The deposition of these redbeds continued in the Lower Permian Rotliegendes formation. These formations form the important reservoir rock of the Groningen gas field. The Rotliegendes for- mation can be subdivided into two main rock-stratigraphic subunits, the Ten boer Member and the Slochteren Member. These two subunits are found in nearly all the wells that has been perforated since the discovery of the field in 1959. The base of the Slochteren member is defined by separation of the course clastic sediment of the Rotliegendes from the fine clastic facies of the Pennsylvanian. And the top as the uppermost massive sandstone underlying the Ten Boer Member [Stauble and Milius, 1970]. The beds range from coarse reddish conglomerate to poorly to very well-sorted, pebbly to fine, brown-gray sandstone. The beds have a higher shale and less conglomerate content in the lower part to the North of the field. The Slochteren member can be subdivided into: Fluviatile conglomerate, sandstone and clay, and eolian sandstone.

The top of the Ten Boer Member is defined by the first occurrence of red shale underlying the dark copper shale. The base is defined by the first occurrence of coarse sandstone of the underlying Slochteren Member. The beds consists of reddish-brown, hard, silty to fine sandy claystone, with white to green-gray anhydrite nodules [Stauble and Milius, 1970]. The strata- change from coarse (in Slochteren) to fine (in Ten Boer) is a indication of the change of arid to marine environment, where the sealing evaporites where formed. An interesting formation, the Ameland Member occurs in the Northern half of the field, but slightly fade out to the South (see figure 2.4and has more or less the same characteristics as the Ten Boer Member.

A thing copper shale layer overlies the Ten Boer Member and then a series of evaporite be- gins due to a marine transgression, which is known as the Zechstein formation, deposited in a differentially subsiding restricted marine basin. This thick salt layer (500 to 1500 m) functions as a perfectly sealing layer of the Rotliegendes reservoir rock. The next formation group de- posited in the Triassic period are known as the German threefold lithostratigraphy, subdivided into Buntsandstein, Muschelkalk, and Keuper [Gr¨otsch and Gaupp, 2011]. The lower part of the Bundstandstein consists of a sequence of marine anhydrite shale, then the region was tec- tonic active and caused deposition of rock salt , deposited in the Upper Bundsandstein. The Muschelkalk is characterized by Dolomite and green Shale. The Keuper formation is not found, probably due to late Kimmerian truncation of the strata [Stauble and Milius, 1970].

As mentioned before no strata is found of Jurassic age, due to Kimmerian tectonic phase. The next formations are of Cretaceous age. These formations are characterized by gray to brown, silty shale beds. During this age the sedimentary conditions were restored in the Groningen area and an sequence of marl grading upwards into chalk with chert nodules were deposited. During the Eocene, after a period of mild uplift and truncation, glauconite sand and clay were deposited. Next, sandy to shaley Oligocene beds were deposited on top of the eroded Eocene beds. Formations within the Miocene age are absent in nearly all the Groningen area. Finally the Quaternary is developed in a sandy to conglomeratic facies with few clay insertions.

9 Figure 2.3: Stratigraphy of the Groningen gas field [Stauble and Milius, 1970]

Figure 2.4: The lithostratigraphic subdivision of the Rotliegend in the Groningen area [NAM, 2013]

10 Chapter 3

Literature Review

3.1 Well-log Interpretation

This research is based on Petrophysics, a discipline lying somewhere between Reservoir Engi- neering, Petroleum Engineering, Geophysics and Petroleum Geology. In the oil industry, the primary functions of a petrophysicist are to ensure that the right operational decisions are made during the course of drilling and testing a well from data gathering, completion and testing. And thereafter, to provide the necessary rock parameters to enable and accurate static and dynamic model of the reservoir to be constructed [Darling, 2005]. This means that they have a key role in ensuring the success of a well, and the characterization of a reservoir. The work of a geophysicists lies between the surface seismic survey an the production testing, during the field development of a hydrocarbon reservoir.

A well-log is a continuous record of any of the characteristics (or geophysical parameter) of the rock formations along a borehole, obtained from measuring apparatus(logging tools) and wirelines in the well-bore [Serra, 1984], see fig- ure 3.1. The log data is recorded on paper or magnetic tape. To get all the necessary in- formation about the subsurface, not only well log data is evaluated, but also rock samples are obtained as cores or cuttings. But the lat- ter two techniques are not relevant for this re- search, and will not be described any further. There are several types of measuring devices and interpretation techniques, to provide val- ues of porosity, shaleyness and hydrocarbon saturation as a function of depth. To deter- mine these rock properties, many logging tools Figure 3.1: example of a log record on paper are needed to give the best possible combina- tion of measurements. The main goal is to relate the measurements to the volume fraction and type of hydrocarbon present in the porous reservoir formations. The measurement techniques are used from three broad disciplines: electrical, nuclear and acoustic.

11 3.2 Porosity, Shale Content & Formation Thickness

3.2.1 Introduction In general, the basic three log types that are used for the evaluation of reservoir rocks are:

1. Permeable zone logs (Spontaneous Potential, Gamma Ray, Caliper)

2. Resistivity logs (Electric Sonde, Induction Logs, Laterologs and Micro Resistivity Tools)

3. Porosity logs (Density, Neutron and Sonic)

For the purposes of this report, the first and third log types are used for the determination of the porosity, and shale content of the Groningen gas field reservoir. The penetration depth of the well bores are used for the determination of the thicknesses of the sealing Zechstein, Ten Boer member, Ameland member and Slochteren member. Below, a short description of the apparatus and techniques for the determination of the porosity and shale content are described.

3.2.2 Porosity For the determination of the porosities the density and neutron logs are used.

Density log Density logs are based on the principle of gamma ray absorption. The density tool contains a chemical gamma-ray source and two or more gamma ray detectors, which allows for borehole compensation to be applied. The tool is scaled in units of density(grams/cubic centimeter or kilograms/cubic meter) or sometimes in porosity units(percent). From the source, gamma rays are emitted and reach the surrounding rocks. Some of the induced gamma rays are absorbed and others are scattered by the rock and reaches one of the detectors. A higher density of the rock material will weaken more of the gamma rays coming from the source and thus less will reach the detectors [Wolf, 1999]. The response of the density tool is determined by the electron density (ρe) that is related to the bulk density. The formation bulk density (ρb) is a function of the matrix density, porosity, and density of the fluid in the pores. Also the electron density and apparent bulk density are related. The latter one can be read from the log, and in liquid filled sandstones, limestone and dolomite the apparent bulk density is practically identical to the bulk density. For gas bearing formations a gas correction is needed [Wolf, 1999]. An example of a density log is given in figure 3.2, showing density of the formation rock(solid line), density porosity on a limestone scale(dashed line) and a density correction. To use the data from a density log, the lithology assumption and the two end point values have to be identified. The porosity can be calculated using a chart or equation. In both cases the matrix density and type of fluid in the borehole has to be known. The following formula can be used to calculate the density porosity(obtained from [Wolf, 1999]: ρ − ρ φ = b ma ρf − ρma where: ρma= density log reading in 100% matrix rock. ρb=density log reading in zone of interest. ρf = pore fluid density.

But this is the general formula, without any correction for shale or gas, in the case of pres- ence. In the following equations, obtained from [Crain, 2000], it is shown how to correct for

12 shale and gas effects.

Applying density shale correction:

ρshale − ρma φshale = ρf − ρma

φshalecorrected = φ − Vshale ∗ φshale where: ρshale=density log reading in 100% shale. Vshale=shale volume

Applying gas correction: For the gas correction, a correction constant KD is chosen in the range of 0.5-1.0 depending on invasion and gas density. This correction is needed, when gas is known to be present.

Neutron log Neutron tools are logging tools, that use radioactive sources to determine the porosity of the formation. The response of the tool is identify the amount of hydrogen atoms present in the formation. The principle of the tool is as follows: A neutron source emits the high energy neutrons, then they collide with the formations nuclei and loose energy. The neutrons are then captured at thermal energy level. The capture of the neutrons leads to an emission of gamma rays and finally the slowed down neutrons and/or gamma rays are measured by a detector [Wolf, 1999]. The neutron log response gives a good measure of the porosity if the shale content in the logged formation is low and no gas is present. But if there is a high shale content and gas show ups, a combination of the density and neutron tool is required to determine the porosity. This can be done using a so-called cross-plot chart or a cross-plot formula(obtained from [Wolf, 1999]. cross-plot equation: φ + φ φ = d n (ifnogasispresent) 2

s φ + φ φ = d n (ifgasispresent) 2 where: φd=density porosity. φn=neutron porosity.

An example of a neutron log, correlated with laboratory porosities is given in figure 3.3.

3.2.3 Shale Content The presence of shale in the formation leads to a too high record of the porosity, derived from sonic and neutron logs. The density log on the other hand will not be affected by the present shale, if the density of the shale is equal or greater than the reservoir’s matrix density. Shale presence in formations causes also resistivity logs to record lower resistivity. Therefore, knowing the volume of shale of a reservoir is very useful and has to be taken into account when developing

13 Figure 3.2: Density log presentation (in track 2).

Figure 3.3: Neutron log.

14 Figure 3.4: Shale volume calculation from the gamma ray log, with the indication of the sand- and shale line [Wolf, 1999]. a hydrocarbon field. For the determination of the shale volume of formations, two log types ( Spontaneous potential and Gamma Ray ) can be used.

Calculation; using gamma ray logs: The natural gamma ray increase with the increase of clay or shale, by the presence of potas- sium [Wolf, 1999]. This gives the opportunity to calculate the shale volume. This can be done by the following equation(obtained from [Wolf, 1999]:

GR − GRmin Vsh = GRsh − GRmin where : GR= actual log reading. GRsh=gamma ray reading in a 100 % shale interval. GRmin=gamma ray reading in a clean sand interval.

An example is given in figure 3.4.

Calculation; using spontaneous potential logs: This method is based on the propagation of electric currents propagating into the formation. The spontaneous potential curve reflects the potential difference between a movable electrode

15 in the borehole and a fixed reference electrode at the surface [Wolf, 1999]. In the shale intervals of the formation, the SP reading is relative constant. This is called the shale base line. When moving into sandy or more permeable intervals, the SP reading shows a change in potential, i.e. deviates from the shale base line. This is called the sand line. The pattern of the SP log allows to calculate the shale volume of the formation. This can be done by the following equation(obtained from [Wolf, 1999]:

PSP − SSP V = sh SSP where : Vsh= the shale volume as a fraction or percentage. PSP =the SP log reading of a shaley interval as a deflection from the shale base line. SSP =the SP log reading in a clean reservoir as the deflection from the shale base line.

An example is given in figure 3.5.

16 Figure 3.5: Shale volume calculation from the spontaneous potential log, with the indication of the sand- and shale line [Wolf, 1999].

17 Chapter 4

Data collection, Design & Processing

4.1 Data Collection

Characterization of the sediments of a hydrocarbon field is a time-consuming process in gen- eral. But the time needed for the process depends strongly on factors like the availability of the required data, the number of petrophysical properties of the rock formations that are needed to be characterized and the kind of method that is applied. In this research the data used, is attained from the Dutch gas and oil portal (NLOG). It is a website, that provides information about exploration and production of oil, gas and geothermal energy in the Netherlands and the Dutch sector of the North Sea continental shelf.

For the purposes of this research, first of all data about the wells and boreholes of the Groningen gas field is needed. To characterize the heterogeneity of the gas field, orientation on the kind and amount of data available is needed. After that, a vulgar sketch of the research is done. NLOG provides information about a big amount of wells and boreholes, which is a big advantage. The next objective is to gain information about the seismicity and the induced earthquakes in the Groningen area, to be able to link this information with the obtained heterogeneity model of the field, in a later stage of the research. This information is again available on NLOG, but is also gained from a few other sources. The third objective is to collect all the data needed to determine the properties of the rock formations of interest and convert it into a image, showing the properties of the field, extending horizontally in the x and y direction. i.e. obtaining two dimensional interpolated maps of some of the rock properties. This will be described in the next section.

4.2 Research Design

The researched rock formations As it is clear from the geologic setting chapter, the Ten Boer and Slochteren member form the reservoir rock of the field. The younger rocks and thick sealing salt rock overly the reservoir rock. Below the reservoir, lies the source rock from carboniferous time. For the characterization of the heterogeneity of the gas field, the rock formations are divided into different sections. One can divide the field into many different sections and evaluate each section separately. The amount and kind of sections, needed to evaluate depends on the time but especially on the objectives, for which one wants to use the heterogeneity model of the gas field. All sections can be analyzed and used to characterize the field, but this is an inefficient way of working. Only the sections that are of importance should be included to give proper results for the research. The next question is, which sections should be included and how to decide to pick the proper sections for the research.

The rock formations of the Groningen gas field in this research are chosen, based on the pur- poses of the research, i.e to link the heterogeneity characterization to the study of the induced earthquakes in the Groningen area due to seismic activity. The gas is currently producing from

18 twenty clusters. Each cluster consists of eight to twelve wells [NAM, 2013]. The big amount of gas extraction from the gas field leads to declination of the reservoir pressure. This results in compaction of the reservoir rock, which leads to subsidence at the surface and strain-build up in the reservoir rock. These events eventually lead to the small scale earthquakes, that the people of Groningen is struggling with these days. So this means that the reservoir rock is the most important section to be evaluated. The reservoir rock is separated into four different sections as illustrated in table 4.1. The For- mation code in the last column of the table is used in all the log files used for this research, as a indication of the representing formation. As shown in the table, there are four different sections. In general there are two different reservoir rocks, the shaley Ten Boer member and the Slochteren member. The Slochteren member is subdivided into two sections due to the Ameland member that show up in the logs taken in the Northern region of the gas field. This is also shown in figure 2.4, from which it can be seen that it covers just a particular part of the area. Therefore the sections evaluated separately in this research are: Ten Boer member, Slochteren member (as a whole) and the Ameland member.

An other section that is evaluated, is the sealing Zechstein salt rock. The salt behaves like a highly viscous non-newtonian fluid [NAM, 2013]. This means that the salt used to move (deformate) in the subsurface, and has had an impact on the subsidence in the area. A more interesting aspect, is the acoustic impedance contrast between the Basal Zechstein and the over- lying halite package, creating a strong seismic reflector. This seams to be advantageous for the level of motion in the Groningen gas field. Directly above the reservoir there is a high-velocity layer (Basal Anhydrite), and thus represents the lowest part of the thick Zechstein interval. This high-velocity layer shown in figure 4.1 influences upward propagating seismic waves. It simply suppresses the strength of the waves arriving at the ground surface, which reduces motion of the ground [NAM, 2013]. So the fourth and last section evaluated in this research is the Zechstein salt rock.

The rock formation parameters The distribution of the rock properties in the Groningen gas field is a important factor in the study of induced earthquakes. For example, the higher the porosity of a formation, the higher the chance to compact as a result of gas production, leading to earthquakes. For the purposes of this research, the distribution of three rock properties has been evaluated. This includes:

1. Formation thicknesses ( Zechstein salt, Ten Boer, Ameland & Slochteren)

2. Shale content ( Ten Boer, Ameland & Slochteren)

3. Porosities ( Ten Boer & Slochteren)

The choice of these rock properties is made based on the relation between the heterogeneity research and the aspect of induced earthquakes in the Groningen area. To characterize the heterogeneity of a hydrocarbon field, many other rock properties can be taken into account, like the permeability and the water saturation. But when at the same time, focusing on the study of induced earthquakes, some rock properties that are not relevant can be omitted. Also the time needed for evaluation of the rock properties plays a role. In short, these factors leaded to the decision of the three chosen rock properties listed above.

4.3 Data Processing

The data obtained is processed, using excel and QuantumGIS(QGIS) as the main software, resulting in 2D interpolated plots of the three chosen rock properties of the gas field. To get started with the data processing, first an area of the Groningen gas field has to be defined. The defined area is shown in figure 4.3, and covers approximately 100 % of the actual gas field.

19 For the generation of the plots, the chosen area has to be defined by a coordinate system to be able to put in the obtained data points into the plot. The system of Rijksdriehoekmeting( RD-system) is used. In the Netherlands separate coordinate systems are used for location and height. The corresponding ellipsoidal coordinate system of the RD-system uses the so called Bessel-ellipsoid, with the reference point in Amersfoort [Crombaghs and kosters, 2000]. That’s why the RD-system is also known as ”Amersfoort RD”.

The area defined, in terms of the RD-coordinate system is shown in figure 4.2. The bound- aries of the area are chosen such that it covers approximately 100% of the field, but also taking into account the available well log data from NLOG. The Westernmost data available, is from field Winsum well (WSM-01), with coordinates: X: 230349, Y: 595857. The Northernmost data available, is from field Uithuizermeeden well (UHM-02), with coordinates: X:249314, Y:607914. The Southernmost data available, is from Annerveen-schilinsoord well (ANS-01), with coordi- nates: X: 244143 Y: 565998. And finally, the Easternmost data available, is from field Oostwolde well (OLD-01), with coordinates: X:265208 Y:582820. These wells can be found in appendix A.1 . The data used for the plots contains 40 well data for the thicknesses and the shale contents and 20 well data for the porosities. In first instance, for the evaluation of the thicknesses and shale contents, 30 well data has been used to obtain the plots, but the results showed on several locations unrealistic discontinuities. So the heterogeneity characterization of these two rock pa- rameters could not be done in a proper way. i.e. more data is needed to analyze the results. So another 10 wells has been added to the actual data and processed again. All the wells that have been used for the models can be found in appendix A.1. Although there hasn’t been drilled at all the locations in the field, the data is taken such that it covers as good as possible the whole area. The wells in appendix A.1 contain all their own value. This value can be the shale content, thickness or the porosity of the rock formation at that location. An explanation of the determination of the rock parameters will be described later in this section. Now the area is defined and the data is put in the right locations, they need to be interpolated.

The plots are derived by using QuantumGIS(QGIS). The data, which can be found in ap- pendix A.2 t/m A.12 is obtained before interpolating the data points. Each well is sorted in a column, with the corresponding coordinates and values, obtained from the logs. Further, the depths of the intervals are given. Also the calculations of the determined parameters is done in excel and are explained in short below;

Formation thickness The thicknesses of the formations are determined easily, using the stratigraphic unit depths data from NLOG, see figure 4.4. The measurements are done along the borehole axis. Most of the wells are deviated, this will affect the thicknesses, because the measurements are not the true vertical depths(TVD) of the units. However, no corrections are done on the thicknesses, since the deviations of the wells are relatively small. For example, the data shown in figure 4.5 is from well ANS-01. It shows the primary data of the well. But if you watch the difference between the total depth and the true vertical depth, it’s about 3 meters. This is over an vertical interval of more than 3 kilometers. Also the depths are measured relative to the rotary table of the well. See appendix A.2 t/m A.12 for the data.

Shale content The shale contents of the rock formations are calculated using the formula given in the literature review chapter. Gamma-ray log data from NLOG is used for the calculation. NLOG provides log traces (LIS/LAS), these are digital log curves that can be copied into excel to determine the shale content for each small interval, and averages are used for the shale content model. Due to lack of log traces (indicated with yellow in appendix A.2 t/m A.12) for some wells, the shale content for these wells is calculated using log curves as a image file. This is of course less

20 Table 4.1: Lithostratigraphic subdivision of the Gronigen Reservoir.

Figure 4.1: Profiles of S-wave and P-wave velocities showing the Basal Anhydrite at a location in the southern part of the Groningen field [NAM, 2013]. accurate than the shale content calculated using the digital log curves.

Porosities The porosities are determined using the density log data from NLOG. The data is applied to the given formula for density porosity given in the literature review chapter. For some of the wells also the neutron log is used to check the porosity relative to the neutron porosity, for the decision whether to apply a gas correction or not. Digital log curves(LIS/LAS) from NLOG has been copied into excel and averages of the porosity from each interval in the formations are taken for the porosity model.

21 Figure 4.2: Boundaries of the field, used for the assessment of the 2D plots.

22 Figure 4.3: Groningen gas field, the defined study area.

Figure 4.4: Example of the stratigraphy data from NLOG.

23 Figure 4.5: Example of primary data well from NLOG.

24 Chapter 5

Results

5.1 Model Interpretations

5.1.1 Formation Thickness Zechstein Member In figure 5.1 the result of the formation thickness of the Zechstein member is shown. The map shows the spatial distribution of the thickness of the salt rock. There is a strong variation in thickness. The minimal thickness measured is found in the Northeast of the area (282m) and the maximum in the Southeast (1783m). A general trend of the thickness in the map seems to be missing, although the Zechstein member in the Northeast is less thick than in the Southwest of the region. The nice thing is that the map represents the behavior of the zechstein salt that has been moving throughout time, since it has the characteristics of a highly viscous non-newtionian fluid. This behavior can be seen on the map as regions where the thickness variation is very sharp. In general it shows a enormous heterogeneous structure over the whole area. The sharp variation in thickness is also due to the complex fault system located in that region. For the creation of this map, there has been taken 30 well data in first instance. But the resulting map showed a very discontinuous thickness distribution in some parts of the region. So extra well data is taken in a form of three clusters in the region, with each cluster containing three extra well data. The first cluster is chosen on the basis of a southwest seismic profile of the field, to give a better image of the abrupt point in the Southeast of the region, where the thickness changes from about 500 m to almost 1800 m. In the surrounding of this location, three extra wells have been taken and resulted in a better image. The second cluster has been chosen in the Southwest of the area, where two peaks are present (1484m and 1644m). In this area, also three extra wells has been added to give a more realistic image of the thickness. The third and last cluster was planned to be taken in the Northeast, where a greatly thin layer is found (282m). This point show up as a outlier, but unfortunately there is no other well data available in that region. So three other wells at random locations have been added to the data. So in total, 40 data points are used to obtain the resulting thickness map. The map confirms that the Zechstein member is significantly thick and has a huge thickness variation over the area, i.e. showing a relative heterogeneous pattern.

Ten Boer Member In figure 5.2 the result of the formation thickness of the Ten Boer member is shown. The map shows the spatial distribution of the thickness of the shaley rock. At the first look, the map shows a layer thickness varying between 60 m to 80 m in the Northwest of the region that gradually decreases to the Southeast of the region with thicknesses varying between 15 m to 50 m. So it is clear that the formation is thicker in the North than in the South. Although there seems to be a clear trend in the map, two locations on the map captures our attention. These are the locations where the thickness variation is very sharp in the middle of the area ( changing from: 18m to 75m and 14m to 87m). At these two locations, there has been added more data

25 Figure 5.1: Thickness map of the Zechstein salt rock formation.

26 Figure 5.2: Thickness map of the Ten Boer rock formation. points to obtain a better image, but the discontinuities still maintained. An explanation to these two abrupt points on the map is that there are large faults found, resulting into a significantly change in thickness over a small distance in the area. Also for this map, there has been taken 30 well data in first instance, but later added 10 more well data to obtain a better image.

Slochteren Member In figure 5.3 the result of the formation thickness of the Slochteren member is shown. The map shows the spatial distribution of the thickness of the sandstone rock. In general, this map seems to follow the same pattern as the Ten Boer map, thicknesses gradually changing from thick in the Northwest to thin in the Southeast of the region. But the difference is that this map shows relatively more discontinuous spots on different locations. Also the thickness variation is larger than the Ten Boer. It varies between 21m to 288m, whereas the Ten Boer member varies between 14m to 87m. But the two maps shows also a similarity, because the two abrupt points where the thicknesses changes from 118m to 288m and 44m to 181m on the Slochteren map, are also found on the Ten Boer map at about the same locations in the region. Further, there

27 Figure 5.3: Thickness map of the Slochteren rock formation. are also some other points, showing sharp edges of thicknesses. Again for the obtained result, in first instance there has been 30 well data used, but later on supplemented by 10 extra well data to obtain a better image. The Slochteren formation shows a more heterogeneous behavior than the Ten Boer member and is also significantly thicker.

Ameland Member In figure 5.4 the result of the formation thickness of the Ameland member is shown. The map shows the spatial distribution of the thickness of the shaley rock. From the map it is clear that the formation is only present in the Northern part of the field. Although little well data is avail- able of the formation, it seems that it is a thin layer varying between a few meters to 18 meters thick to the North. In comparison with the thicknesses of the previous formations, the Ameland member is the thinnest and is also only present in the Northern part of the region. And it shows also the least heterogeneous pattern. In the regions where this formation is present, it divides the Slochteren member into two parts, the Upper Slochteren and Lower Slochteren formation.

28 Figure 5.4: Thickness map of the Ameland rock formation.

5.1.2 Formation Shale Content Ten Boer Member In figure 5.5 the result of the formation shale content of the Ten Boer member is shown. The map shows the spatial distribution of the shale content in the Groningen field. As it is shown, the shale content varies between 25 % to 75 %. This is a wide range in shale values, and there is also no trend in the map with regions only containing high shale values or regions with only low shale content. As expected from literature, the result confirms the high shale content in the Ten Boer formation. During the analyze of the well data, the lithology found in each well is taken into account. From this, one can say that each data point has a slightly to very different lithology. In some of the wells, the formation is very heterogeneous, i.e containing multiple small alternating layers with different mineralogy, whereas in other wells, the formation is relatively homogeneous, i.e containing one thick layer of claystone or silt. And also in other wells, the

29 Figure 5.5: Shale content map of the Ten Boer rock formation. lithology shows a thick sandy shale layer. So the lithology in each well reflects the heterogeneous distributed shale content in the Ten Boer formation. In total, 40 well data has been used. Just like the analyze of the formation thickness, in first instance there has been used 30 well data, but since this amount of data resulted in a less clear image of the shale content, it is extended to 40.

Slochteren Member In figure 5.6 the result of the formation shale content of the Slochteren member is shown. The map shows the spatial distribution of the shale content in the Groningen field. This map, in comparison with the Ten Boer shale content map, shows a relative homogeneous distributed formation shale content. The values vary between 16% to 57%. The values confirm that the Slochteren sandstone contains far less shale than the Ten Boer formation. It is striking that the formation contains a relative high shale content on two locations in the map. This can be explained by the fact that, the location with 57% shale (well SLO-1), clay intervals in the

30 Figure 5.6: Shale content map of the Slochteren rock formation. sandstone are present. And the other location with 54,5% also contains relatively more clay than the other wells in the area. Also in almost all the wells, the upper part of the Slochteren Formation contains more shale than the lower part, since gamma ray logs shows higher API val- ues. The lower part consists of course clastic sediments and the upper part contains a massive sandstone with more shale as mentioned in the lithostratigraphy section, due to environmental changes from arid to marine. The lithology found in the well data confirms this, since a lot of conglomerates are found in the lower part of the formation in nearly all the wells. Again 40 data points have been used in total to obtain this map.

Ameland Member In figure 5.7 the result of the formation shale content of the Ameland member is shown. The map shows the spatial distribution of the shale content in the Groningen field. The Ameland member has the same characteristics as the Ten Boer member, so at different locations in the

31 Figure 5.7: Shale content map of the Ameland rock formation. map, it shows more or less the same shale content. The values vary between 34% to 66%. with at one specific location a value of 17%, which can be seen as a outlier. At this location (well WSM-01) a clayey sand has been found from lithology inspection. Since the Ameland member occurs in the Northern half of the field, data points are taken only in that area. In total 11 data points have been used. In general one can say that the formation shale content of the Ameland member is relative heterogeneous distributed, just like the Ten boer, in comparison with the Slochteren member.

5.1.3 Formation Porosity Ten Boer Member In figure 5.8 the result of the formation porosity of the Ameland member is shown. The map shows the spatial distribution of the porosity in the Groningen field. The porosities in each well are derived with the density log and are shale corrected. The map shows values between 0% to 7% porosity in general, but with a few outliers. In this formation the expected porosity is low, this expectation is confirmed by most of the data points on the map. But there are a few points that show a relatively high porosity, like the location with 18,55 % porosity. This can not be explained by the corresponding shale content at that location, since there is no relation if one compares this location in both the porosity and the shale content map of the Ten Boer member. There is little data available to investigate other locations near the high porosity spots, i.e to explain these spots. In total 20 data points have been used for the resulting map. Further, the distribution of the porosity in the formation seems to have a relative heterogeneous pattern, although the values are low in the whole region except for the three high porosity data points.

32 Figure 5.8: Porosity map of the Ten Boer rock formation.

Slochteren Member In figure 5.9 the result of the formation porosity of the Slochteren member is shown. The map shows the spatial distribution of the porosity in the Groningen field. Again, the porosities are derived with the density log and are shale corrected. As the Slochteren member is the main formation, from which gas is produced, one expects high porosities. The results confirms this, and show acceptable porosity values, varying between 10% to 20,5%, with two outliers with 4% and 7% porosity. Since porosity is dependent on the depth, strong variations can take place when faults are present. This could be a explanation for the two outliers. In general there is a trend in the map, with a big region of relative high porosities and a smaller region in the Southwest with relative low porosities. So from this, one can say that the distribution of the porosity in this formation is relative homogeneous. Compared to the porosity map of the Ten Boer member, it seems that the low porosity region of the Slochteren member is the opposite of the Ten Boer member, where the porosities are high in that region. The neutron log shows

33 a uncorrected porosity of 20% at the location where the porosity is 7% (uncorrected 21%) for the Slochteren formation, and a uncorrected porosity of 29 % for the Ten Boer formation at the location where the porosity is 18,55 % (uncorrected 20%), see tables 5.1 and 5.2. So if one compares the neutron with the density log, they show more or less the same porosities, which confirms that the outliers are correctly determined. But they also show that indeed, the porosity in the Ten Boer formation is higher in that area than the porosity in the Slochteren formation. Again 20 data points have been used for the resulting map.

5.2 Compaction effects

Porosity model As it is mentioned before, porosity has a big influence on compaction calculations. In general, a higher porosity of the reservoir rock will lead to more compaction during gas production. Based on the derived porosity model in figure 5.8 and 5.9, locations in the gas field can be designated, so that the production rate can be reduced, which will lead to less compaction and thus to de- crease the chance of seismic activities. From the Ten Boer porosity model, may be suggested to lower or stop the production in the areas where the porosity is relative high. The high porosity areas are near well EKL-12, PAU-01 and ANN-05. Although the gas is mainly produced from the Slochteren member, the porosity of the Ten Boer will still have influence on the compaction. Despite the fact that in the porosity model of the Slochteren member, the porosities are more or less the same in the bigger part of the field, there are still a few spots where the porosity is relative higher. These high porosity areas are near well BIR-03, ZND-01, LRM-07 and OVS-01. Again, in these areas may be suggested to lower the production rate.

Thickness model The thicknesses of the formations will also have influence on the compaction, but in a indirect way. In general, the thicker the formation, the more volume of gas can be produced from. Loca- tions with high formation thickness values in the thickness model in figure 5.1, 5.2 and 5.3 can be designated, where the chance of compaction may be higher under production circumstances. Especially on the locations where a sharp decrease or increase in formation thickness occurs. An other aspect that also plays a role, as mentioned before, is the acoustic impedance contrast between the Basal Zechstein and the overlying Halite package. The high-velocity Basal layer suppresses the strength of the waves propagating to the ground surface. So the thicker the Basal unit in the Zechstein formation, the lower the level of motion on the ground in the Groningen area.

Shale content model The obtained shale content model in figure 5.5, 5.6 and 5.7 show a relative heterogeneous char- acter, with the exception of the Slochteren member. The shale distribution and content in the reservoir rock can be taken as a extra parameter in compaction calculations, to obtain better models of compaction.

34 Figure 5.9: Porosity map of the Slochteren rock formation.

Table 5.1: Differences between neutron and density porosities for the Slochteren formation.

35 Table 5.2: Differences between neutron and density porosities for the Ten Boer formation.

36 Chapter 6

Discussion

6.1 Model comparison

Since the obtained porosity model forms the basis for compaction calculations, it will be com- pared to the porosity model of the NAM. The determination process of the NAM differs from the method used in this research. The NAM determined porosities of the reservoir based on both density and sonic logs. The number of data points used, is 365, which is much more than the data used for the porosity model in this research. Also the interpolation method used by the NAM is different, which is based on Kriging, a stochastic interpolation method. Another thing, is the chosen intervals, over which the porosities are measured. The NAM has a different sub- division of the reservoir rock. These factors together lead to a different porosity determination. But still both results are in accordance with each other, to some extent, when the porosity model of the NAM in figure 6.1 is compared with the Slochteren member porosity model. In general, the values correspond to each other, although the porosity model of the NAM is only from the Upper Slochteren section. In the used models of the NAM, uncertainty analysis are missing, which makes the models unsuitable for the explanation of the subsidence analysis. The NAM have done a subsidence forecast for 2080, which is shown in figure 6.2. The maximum expected subsidence from 2013 until 2080 is 46,7cm [NAM, 2013]. In the Northwest of the region, too high subsidence values are calculated, duo to reduction of porosities. This porosity reduction can be explained, by the fact that in the Northwest faults are present with a big offset on short distance of each other. This leads to a overestimate of the compaction. However, the area where the highest level of subsidence are predicted, seem to correspond with the high porosity area in figure 5.9. Therefore, the porosity values and compaction model of the NAM validate the obtained porosity model in this research. To come back to the seismic hazard, one can say that it is very sensitive for uncertainties in the calculations and obtained models of compaction. Beside, production scenario’s play a big role, i.e. the amplitude of a seismic hazard is strongly related to the production of the gas. A logical choice, which arises from the results of this research and also mentioned by the NAM, is to reduce the production rate and stop the production near areas where the subsidence prediction is the highest. This will eventually lead to a reduction of compaction, and so to a reduction of seismic activity in the Groningen area.

6.2 Limitations & Difficulties

During the analysis and procession of the data a few limitations and difficulties were encoun- tered that are described below. First of all the time needed to obtain the results played a big role. The available time determines the amount of data that can be interpreted and processed. Since the time was limited, some data points from NLOG are omitted. But despite the limited time, the used data points are as good as possible chosen to represent a decent data set. Also more parameters could be chosen to characterize the degree of heterogeneity of the gas field, but again the time limited this option. Second, there are some regions on the maps that show sharp differences on a short distance between two data points. This could be fixed, by taking

37 Figure 6.1: Porosity model of the Groningen Gas Reservoir, by the NAM [NAM, 2013].

38 Figure 6.2: subsidence forecast for 2080, by the NAM [NAM, 2013].

39 more data points near these locations. But unfortunately more data points that were needed, were not available. So it had to be done with the available data points, i.e. the data was limited in some of the regions of the gas field.

A third point is the kind of data that is available on NLOG. For the shale content calcula- tions for example, a certain file is used, called .lis or .las files, which are put into excel to determine the shale content for each small interval of the relevant formation. These files were not available for each well that is taken for the shale content maps. Instead, the shale content for these incomplete data points are calculated using log files that are shown as a image. This method is of course less accurate and will influence the results to a certain extent. And for the porosity calculations the availability of the data caused also a problem. There are several methods to obtain the porosity of a rock formation from log data, each with its own advantages and disadvantages. In first instance, the idea was to determine the porosity of the analyzed formations, using density neutron crossplots. But for the chosen data set, these density and neutron logs were missing for some of the wells. So this method was excluded. An other option was the density sonic cross plot, but the same problem arose again. For each well, the density log is included, so this one was taken and corrected for shale, resulting in the obtained porosity maps for each formation. No gas correction is taken into account, since in several wells, the neu- tron porosity is higher than the density porosity, see table 5.1 and 5.2. This is especially valid for the Ten Boer member. For the Slochteren member, we can see that the density porosities are higher than the neutron porosities, so actually they need a gas correction. Since no neutron log was available for each well in the data set, it is assumed, for the purposes of this research, that each well didn’t need a gas correction. Still, gas corrections are done for each well in the data set, but they yielded low porosity values which are far less than the usual porosity for a gas field. However, these gas corrections are not included in the final results. A final point is the interpolation method. The method does not take into account measuring errors, since it is a deterministic interpolation method. There are better methods available for interpolation of the data, but these methods are not included in the software used to obtain the interpolated maps. So it is not the best method to interpolate, but still yields decent results for the purposes of this research.

40 Chapter 7

Conclusions

Zechstein rock The Zechstein rock is a relative thick formation, with a range of 282 to 1783 meters. The dis- tribution of the formation over the Groningen area shows a relative heterogeneous pattern.

Ten Boer member The Ten Boer rock is clearly thicker in the Northwest of the Groningen area, and decrease in thickness to the Southeast. The thickness varies between 60 to 80 meters in the North and 15 to 50 meters in the South of the field. The thickness map shows a relative homogeneous thickness distribution of the formation over the Groningen area. The formation has a relative high shale content, varying between 25% to 75%. The shale distribution shows a relative heterogeneous pattern. The porosity in the formation is relative low, varying between 0 % to 7%, but contains some regions, more or less in the middle and to the West of the gas field, with high porosities. The porosities distribution show a relative heterogeneous pattern.

Slochteren member The Slochteren rock show the same pattern as the Ten Boer when speaking of formation thick- nesses. The Slochteren member is thicker in the Northwest and decrease to the Southeast of the region, with thicknesses ranging from 21 to 288 meters. The thickness distribution shows a more heterogeneous pattern than the thickness of the Ten Boer member. The formation has a relative low shale content, varying between 16% to 30%, but with a few outliers with higher shale values. Also the shale distribution shows a relative homogeneous pattern. The Slochteren rock has a relative high porosity, varying between 10% to 20%, but also with a few outliers with low porosity values. Just like the shale distribution in this formation, the porosity distribution shows also a relative homogeneous pattern.

Ameland member The Ameland rock, is a highly shaley rock, that is only present in the Northern half of the gas field. The formation is relative thin, varying between a few meters in some regions to 18 meters to the upper North of the gas field. Although little well data is available, it seems that the distribution of the thickness of the Ameland member show a relative homogeneous pattern. The shale content varies between 34% to 66%, and its distribution show a relative heterogenous pattern, just like the Ten Boer shale content distribution.

41 Combined Conclusion The evaluated formations show a relative heterogeneous pattern for the three studied param- eters in this study. The Slochteren formation seems to be the least heterogeneous of the four studied formations. But it is also the most important formation, when relating it to the induced earthquakes in the Groningen area, since the gas is produced mainly from this rock formation. The formation has a high porosity. In regions where the porosities have the highest values, the compaction of the rock is also the highest. This compaction is predicted by the NAM and presented in their subsidence forecast for the year 2080. In order to reduce compaction in the Groningen area, it is recommended to reduce the production rates in high porosity areas and stop the production in the areas near well LRM-07 and ZND-01, where compacting predictions has the highest values. Although better models are presented, like the models of the NAM, presented in their report [NAM, 2013], the outcome of this study could be used as a basic input for subsidence studies and geomechanical modeling of the Groningen field.

42 Chapter 8

Recommendations

It would be convenient to use more data to obtain the models presented in this research. This would give the possibility to describe the obtained results in more details. So a larger focus on the data set, and less focusing on other parts of the research is recommended. It would also be interesting to involve the faults and fractures models of the Groningen gas field. A correlation between the obtained porosities, shale contents and thicknesses on one side and the the fractures and faults in the area on the other side, can lead to interesting results and better understanding of the spatial distribution of the evaluated rock parameters. The findings that emerge from it, are better applicable to the compaction models.

Also a more accurate interpolation method, for example a Kriging based interpolation, would be recommended, since it gives a better interpolation between the data points and thus more reliable results. Also, omitting outliers from the dataset, lead to less discontinuous regions on the models. Furthermore, a subdivision of the study area in multiple areas is more efficient. In this way, one can describe each area separately and in more details, since the Groningen gas field is relative big. This would lead to a clearer description of the obtained models. It is also recommended to use offered software by Schlumberger, on their website, to analyze the digital log data on NLOG in a much faster and operative way. Finally, an excursion to the Groningen gas field would provide more data and a better understanding of the gas field, and eventually lead to better results if this can be planned in the time needed for writing the research. But above all, it is a beautiful and instructive experience that one can gain with such an excursion.

43 Appendix A

Appendices

Figure A.2: Thickness data Zechstein rock

44 Figure A.3: Thickness data Ten Boer member

45 Figure A.4: Thickness data Slochteren member

46 Figure A.5: Thickness data Ameland member

Figure A.6: Shale content data Ten Boer member

47 Figure A.7: Shale content data Slochteren member

Figure A.8: Shale content data Ameland member

48 Figure A.9: Density porosity data Ten Boer member

49 Figure A.10: Density porosity data Slochteren member

Figure A.11: Neutron porosity data Ten Boer member

50 Figure A.12: Neutron porosity data Slochteren member

Figure A.1: Well Locations

51 List of Figures

1.1 Location map of the Groningen Gas Field showing fault lineations, the Top Rotliegend depth contours, and the extent of the gas-filled area in green. Coast- lines are shown as light blue lines. Key exploration wells and development clusters are indicated in various colours reflecting the time of drilling (see inserted legend), from [Gr¨otsch and Gaupp, 2011]...... 6

2.1 SP Log evidence, showing the Saalian unconformity...... 8 2.2 Schematic cross-section through the Groningen field [Glennie, 2013] ...... 8 2.3 Stratigraphy of the Groningen gas field [Stauble and Milius, 1970] ...... 10 2.4 The lithostratigraphic subdivision of the Rotliegend in the Groningen area [NAM, 2013] ...... 10

3.1 example of a log record on paper ...... 11 3.2 Density log presentation (in track 2)...... 14 3.3 Neutron log...... 14 3.4 Shale volume calculation from the gamma ray log, with the indication of the sand- and shale line [Wolf, 1999]...... 15 3.5 Shale volume calculation from the spontaneous potential log, with the indication of the sand- and shale line [Wolf, 1999]...... 16

4.1 Profiles of S-wave and P-wave velocities showing the Basal Anhydrite at a location in the southern part of the Groningen field [NAM, 2013]...... 20 4.2 Boundaries of the field, used for the assessment of the 2D plots...... 21 4.3 Groningen gas field, the defined study area...... 22 4.4 Example of the stratigraphy data from NLOG...... 22 4.5 Example of primary data well from NLOG...... 23

5.1 Thickness map of the Zechstein salt rock formation...... 25 5.2 Thickness map of the Ten Boer rock formation...... 26 5.3 Thickness map of the Slochteren rock formation...... 27 5.4 Thickness map of the Ameland rock formation...... 28 5.5 Shale content map of the Ten Boer rock formation...... 29 5.6 Shale content map of the Slochteren rock formation...... 30 5.7 Shale content map of the Ameland rock formation...... 31 5.8 Porosity map of the Ten Boer rock formation...... 32 5.9 Porosity map of the Slochteren rock formation...... 34

6.1 Porosity model of the Groningen Gas Reservoir, by the NAM [NAM, 2013]. . . . 37 6.2 subsidence forecast for 2080, by the NAM [NAM, 2013]...... 38

A.2 Thickness data Zechstein rock ...... 43 A.3 Thickness data Ten Boer member ...... 44 A.4 Thickness data Slochteren member ...... 45 A.5 Thickness data Ameland member ...... 46 A.6 Shale content data Ten Boer member ...... 46

52 A.7 Shale content data Slochteren member ...... 47 A.8 Shale content data Ameland member ...... 47 A.9 Density porosity data Ten Boer member ...... 48 A.10 Density porosity data Slochteren member ...... 49 A.11 Neutron porosity data Ten Boer member ...... 49 A.12 Neutron porosity data Slochteren member ...... 50 A.1 Well Locations ...... 50

53 List of Tables

4.1 Lithostratigraphic subdivision of the Gronigen Reservoir...... 20

5.1 Differences between neutron and density porosities for the Slochteren formation. 34 5.2 Differences between neutron and density porosities for the Ten Boer formation. . 35

54 Bibliography

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