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Deliverable D2.3

Stimulation design and cost report (Second Part)

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Dipl.-Ing. Christin Dieterichs

Dr.-Ing. Silke Röntzsch

Dipl.-Ing. Florian Engert

Checked by: Approved by:

Name: Name:

Date: Date:

Signature: Include scanned signature Signature: Include scanned signature

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Due date of Deliverable Project Month 24

Actual Submission Date 2017-10-16

Start Date of Project 2015-03-01

Duration 36 months

Deliverable Lead Contractor TUBAF

Revision Version 1.1

Last Modifications 2017-10-16

Nature

Dissemination level

Public Summary enclosed

Reference / Workpackage

Digital File Name

Document reference number

No of pages 68

Keywords Casing, cost estimation, drilling, hydraulic stimulation, perforation

In bibliography, this report should be cited as follows:

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List of figures

Figure 1: Well site with noise barriers [6] ...............................................13

Figure 2: Example of a casing design depending on pore and frac

pressures (black line represents the mud density in each drilling section)

..............................................................................................................14

Figure 3: Typical casing design (after [7]) ..............................................14

Figure 4: Well completions, left: with open hole section, right: completely

cased well with perforated production casing [8, 9] ...............................15

Figure 5: Illustration of a drilling rig with its components [10] .................16

Figure 6: Simplified design of a drill string with its components together

with different stress zones observed along the string (after [11]) ...........17

Figure 7: Spiral blade stabilizers with different blade sizes [12] .............18

Figure 8: Downhole mud motor with its inside view [14] ........................18

Figure 9: Drilling a deviated (left side) and straight well paths (right side)

with a directional drilling motor [16] (MWD/LWD: measuring/logging while

drilling) ..................................................................................................19

Figure 10: Rotary steerable system (RSS) with steering ribs [17] ..........20

Figure 11: Rotary steerable system (RSS) with deflected drill bit drive

shaft [18] ...............................................................................................20

Figure 12: Magnetic guidance tool (MGT) operational setup [21] ..........21

Figure 13: Definition of short, medium and long radius drilling ..............22

Figure 14: Schematic of the two well configurations for the BIOMOre

wells ......................................................................................................24

Figure 15: Pressure window for the BIOMOre wells ..............................26

Figure 16: Well path of injection (green) and production (blue) well (2D-

image) for configuration 1......................................................................28



Figure 18: Casing and tubing scheme of the lower wellbore (producer,

configuration 1) .....................................................................................32





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Figure 21: Placement of injection (green) and production (blue) well in

the reservoir for configuration 2 .............................................................35

Figure 22: Casing and tubing scheme of the parent wellbore (lower well,

configuration 2) .....................................................................................37

Figure 23: Typical bullet gun and its components [24] ...........................40

Figure 24: Jet perforating process [24] ..................................................41

Figure 25: Reusable hollow-carrier gun [24] ..........................................42

Figure 26: a) Expendable hollow-carrier gun and b) recovered

expendable hollow carrier gun [24] ........................................................42

Figure 27: Exposed-charge gun (left) and hollow-carrier gun (right, for

comparison) [25] ...................................................................................43

Figure 28: Working mechanism of an extended-diameter through-tubing

gun [24] .................................................................................................44

Figure 29: The operation steps of a radial drilling [33] ...........................45

Figure 30: Performance variations caused by gun clearance [27] .........47

Figure 31: Performance of bullet, jet and hydraulic perforator types in

formations of various compressive strength [27] ...................................48

Figure 32: Scheme of plug-and-perforate operation using wireline plugs

..............................................................................................................51

Figure 33: Plug-and-perforate assembly with one tubular plug [38] .......52

Figure 34: Plug-and-perforate process with two tubular plugs [40] ........52

Figure 35: Frac baffle operations developed by Halliburton [41] ............53

Figure 36: Longitudinal and transversal fractures for different azimuth

angles (α) of wellbore laterals [43] ........................................................54

Figure 37: Drilling cost expenses for one wellbore (Configuration-1)

estimated by the company Rhein Petroleum GmbH (used with the

courtesy of that company) .....................................................................64

Figure 38: Drilling cost expenses of the pilot and main well of the KTB

project (after [48]) ..................................................................................64

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List of tables

Table 1: Formation pore and fracture pressure profile ...........................25

Table 2: Well path of the lower well (producer, configuration 1) ............27

Table 3: Well path of the upper well (injector, configuration 1) ..............27

Table 4: Calculation of casing specifications for the lower wellbore

(producer, configuration1), costs based on 700 $ per t of steel .............30

Table 5: Calculation of casing specifications for the upper wellbore

(injector, configuration1), costs based on 700 $ per t of steel ................31

Table 6: Well path of the parent borehole (lower horizontal section,

producer, configuration2) ......................................................................33

Table 7: Well path of the side track (upper horizontal section, injector,

configuration 2) .....................................................................................33

Table 8: Calculation of casing specifications for the parent wellbore

(lower well, configuration 2), costs based on 700 $ per t of steel ...........36

Table 9: Shot phasing for well perforations [35].....................................46

Table 10: Fluid-selection guidelines for hydraulic stimulation operations

[45] ........................................................................................................57

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Executive summary

This report is prepared by the IBF TUBAF (the Institute of Drilling Engineering and

Fluid Mining, Technical University of Freiberg) in the framework of the Task 2.5. It

serves to give comprehensive information about design, calculations and cost

estimations of drilling and its components. It is prepared as a complementary report

to the Deliverable D2.3 (Stimulation design and cost report) which was already

submitted by IFGT TUBAF (Institute for Geotechnics / Chair of Geomechanics, Rock

Mechanics and Rock Engineering) on 22.03.2017. Calculations and cost estimation

analyses were based on the modelling results which were comprehensively

explained in the Deliverable 2.3.

Chapters were arranged to give information from general to specific concerning

drilling procedure, hydraulic stimulation and respective equipment used. Since 2016

possible wellbore configurations prior to hydraulic stimulation design were reduced

into two main configurations. These are two single (Configuration 1) and stacked

multilateral wells (with a sidetrack - Configuration 2). In terms of drilling the most

challenging step is considered to be drilling the horizontal parts. The well path,

casing design and feasibility calculations were performed by using the commercial

software Landmark (Halliburton).

Using the calculated pressure profiles based on prior simulations and assumptions

for loads during drilling, casing schemes were proposed. Subsequent to the

elaboration of a possible well path and borehole construction with the required

casing diameters and their installation depths; experts from German drilling industry

have been contacted to get a quote for the proposed well designs roughly. Estimated

rough costs for the casing and borehole design considering the requirements of the

BIOMOre project was supplied by the authors. Furthermore, technical information

were given about perforation technologies and hydraulic stimulation methods (fluids

and proppants). As a rough estimation from the experts, the costs of one BIOMOre

wellbore (Configuration 1) were given to be in a range between 5 (lower limit) and 20

Million euros (upper limit).

Finally, stacked multilateral well (Configuration 2) is selected considering economy

and technical feasibility in conjunction with the project requirements and geological

setting. This selection procedure was a dynamic scientific process between IBF and

IFGT and it is based on actual drilling practices, opinions from experts and modelling

results of in-situ stress and stimulation model results.

(Kemal Yildizdag, M.Sc. Eng., IFGT TUBAF Bergakademie)

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Content

List of figures .......................................................................................... 5

List of tables ........................................................................................... 7

Executive summary ................................................................................ 8

1. Technological aspects of drilling a well ....................................... 11

1.1. Exploration .................................................................................. 11

1.2. Well site ...................................................................................... 11

1.2.1. Approval process ........................................................................ 11

1.2.2. Construction of the well site ........................................................ 12

1.3. Well planning .............................................................................. 13

1.4. Rotary drilling .............................................................................. 16

1.4.1. The drilling rig ............................................................................. 16

1.4.2. The drill string ............................................................................. 17

1.4.3. Drill string components for directional drilling .............................. 18

1.4.4. Magnetic ranging ........................................................................ 21

1.4.5. Horizontal drilling ........................................................................ 22

1.5. The BIOMOre wells ..................................................................... 23

1.5.1. Well plan for the Configuration 1 (two single wells) ..................... 26

1.5.2. Well plan for the Configuration 2 (multilateral wells) .................... 32

1.5.3. Drilling program ........................................................................... 37

2. Perforation Technologies ............................................................ 39

2.1. Gun types ................................................................................... 39

2.1.1. Bullet guns .................................................................................. 39

2.1.2. Jet guns ...................................................................................... 40

2.1.3. Through-Tubing guns .................................................................. 43

2.1.4. Hydraulic abrasive perforators .................................................... 44

2.1.5. Laser perforation ......................................................................... 44

2.1.6. Radial drilling .............................................................................. 44

2.2. Factors affecting the perforation operations ................................ 45

2.2.1. Perforation geometry................................................................... 45

2.2.2. Pressure and temperature .......................................................... 48

2.2.3. Underbalanced perforating .......................................................... 49

2.3. Challenges of perforation operations........................................... 49

2.3.1. Plugging of perforations .............................................................. 49

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2.3.2. Casing splitting and damage ....................................................... 49

2.3.3. Cracking of cement ..................................................................... 49

2.4. Perforations for hydraulic stimulation .......................................... 49

3. Hydraulic stimulation ................................................................... 50

3.1. Multilayer stimulation – zonal isolation ........................................ 50

3.1.1. Diversion ..................................................................................... 50

3.1.2. Progressive perforation and stimulation ...................................... 50

3.2. Special features for deviated and horizontal wells ....................... 53

3.3. Hydraulic stimulation fluids .......................................................... 55

3.3.1. Newtonian fluids .......................................................................... 55

3.3.2. Non-crosslinked polymer gels ..................................................... 55

3.3.3. Borate-crosslinked fluids ............................................................. 55

3.3.4. Organometallic-crosslinked fluids ................................................ 55

3.3.5. Gelled-oil systems ....................................................................... 55

3.3.6. Surfactant gels ............................................................................ 56

3.3.7. Foams ......................................................................................... 56

3.3.8. Emulsions ................................................................................... 56

3.4. Proppants ................................................................................... 58

3.4.1. Particle size ................................................................................ 58

3.4.2. Proppant concentration ............................................................... 58

3.4.3. Proppant strength (hardness) and density .................................. 59

3.4.4. Grain shape ................................................................................ 59

4. Organization of a drilling operation .............................................. 60

5. Cost estimation ........................................................................... 62

6. References ................................................................................. 65

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1. Technological aspects of drilling a well

1.1. Exploration

First off all, the technical and economic objectives of the well have to be clearly defined. After that a preliminary survey at preferred geographical regions can be conducted on the basis of existing geological data (geological maps, data from existing wells), environmental conditions (nature reserves, hilly landscape, swamplands, built-up areas etc.). The aim of the preliminary survey is to define few locations which could meet the geological and environmental requirements for the drilling project. These sites will be then further investigated by geological exploration works that could include seismic methods. [1]

If a preferred drilling location is defined then site analyses are carried out. They consider factors like infrastructure (road connections, energy supply, and the supply of fresh water), landscape protection, political and public acceptance issues. Several studies are prescribed by law in this phase of exploration such as environmental impact assessment.

1.2. Well site

1.2.1. Approval process

Before the conductor pipe (see also chapter 1.3) can be installed and the well site can be constructed, the operation must pass an approval procedure. In Germany, a special operations plan (Sonderbetriebsplan) must be submitted to the mining authority. Among others, the following aspects have to be considered [2]:

Designation and purpose of the drilling operation

Date of drilling

Selection of the drilling rig

Exact location of the well

Minimal distances to different objects in the surrounding area

Aspects of transport infrastructure

Descriptions about land use planning and environmental protection

Ownership structures of the building ground

Explanations about water supply and wastewater/mud disposal

Building specification of the drilling site

The mining authority informs all the other relevant authorities (local government, water authority, nature conservation agency, forestry office, etc.) and includes them into the approval process. All of the involved authorities are allowed to claim

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additional formal requirements to the proposer. The approval process often lasts several months. [3]

1.2.2. Construction of the well site

The highest priority during a well site construction is always to ensure that no environmental damage may occur during the drilling operation and fluids of the drilling process may not penetrate into the soil. Therefore, the well site must conform to the German Federal Water Act (Wasserhaushaltsgesetz).

The required space of a well site depends on the equipment which is intended to be used and can amount to 10,000 m². Firstly, the topsoil has to be excavated and stored for remediation purposes. Then the conductor pipe is rammed into the ground. The area, where the drilling rig will be set up, is the core area of the well site. Within this area, a stable concrete foundation is installed to bear the heavy loads during the drilling and completion of the wellbore. Containers, material storage and liquid tanks, etc. are positioned around the core area.

The entire well site is sealed with concrete and asphalt. All the occurring liquids on the well site, even rain water, have to be collected and disposed of according to their environmental hazard potential. Therefore, the well site is equipped with a system of drainage channels and pipes. [4, 5]

It is possible to drill number of different well branches from the parent well. Thereby, the space required for additional drilling locations can be reduced. Those wells are referred to as multilateral wells. Figure 1 shows a well site with noise barriers.

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Figure 1: Well site with noise barriers [6]

1.3. Well planning

The most important factors considered in well planning are the geological profile of the underground, as well as the needed diameter in the final section of the borehole and the last cemented casing. The installation of casings in a well and their cementation is necessary to ensure wellbore stability. On the one hand, the well is prevented from sediments caving and intrusion of reservoir fluids. On the other hand, the formation is secured against the invasion of drilling fluids and the spreading of the high hydrodynamic pressure of the well. A well is always planned from bottom to top. The depths, at which the casings have to be set, depends on the formation pressure (pore and frac pressure gradients as shown in figure 2) and on the possible presence of “problematic” formations. These are none-stable formations and they could slip into the well. The rocks which exhibit swelling and plastic behaviour as clays or salts, as well as formations with abnormal (not following the expected pressure gradient) pressure gradients can be considered to be “problematic.”

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Figure 2: Example of a casing design depending on pore and frac pressures (black line

represents the mud density in each drilling section)

A borehole is always telescopically designed as shown in figure 3. The diameters of borehole and casings decrease from top to bottom.

Figure 3: Typical casing design (after [7])

The conductor pipe and the surface casing are obligatory parts. They prevent the well from the unconsolidated sediments in the upper layers of earth, as well as the environment and the groundwater from impacts of the drilling operation. The conductor pipe is rammed into the ground. The surface casing is embedded in the underlying solid rock. The blowout preventer will later be mounted on that casing, so it has to stick safely in the ground.

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The length of the following borehole sections depends mainly on the formation pore and fracture pressure. The bottom hole pressure of the well has always to fit into the pressure window of the formation (figure 2). It has to be slightly higher than the formation pore pressure and lower than the fracture pressure. If it is no longer possible to hold the bottom hole pressure within the pressure window, the drilling process has to be stopped and a casing has to be set and cemented. After that the drilling process can be continued (with a smaller bit diameter). Those casings are called intermediate casings. Also after drilling through problematic formations (e.g. due swelling clay, creeping salt or unstable borehole walls) an intermediate casing has to be set. The planned number of intermediate casings determines the diameter of surface and conductor casing.

Casings can either reach the surface or be installed in the lower part of the previous casings. The pipes, which do not reach to the surface, are called liner.

The casings are cemented in order to anchor them to the surrounding rock. A well planned and appropriately performed cementation ensures wellbore integrity. Sometimes the cement does not reach to the surface, but it always has to reach into the previous casing to a sufficient extent. In order to ensure the fluid exchange between the wellbore and the reservoir, there are different possibilities to complete the last interval. If geomechanical conditions are favorable and the formation is stable then wellbore stability is given without means of installation and cementing of casings. Such a wellbore completion is referred to as open hole completion (figure 4, left). In these cases, less resistance to flow is caused. However, the wellbore must be prevented from collapsing in most cases. Casings should be then installed and cemented. The communication between the wellbore and target zones is established by perforations, as shown in the right picture of figure 4. More information about perforation technologies are given in Chapter 2.

Figure 4: Well completions, left: with open hole section, right: completely cased well with

perforated production casing [8, 9]

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1.4. Rotary drilling

1.4.1. The drilling rig

The structure of a typical drilling rig for rotary drilling operations is shown in figure 5.

Figure 5: Illustration of a drilling rig with its components [10]

The main functions of a drilling rig are the lifting and lowering of heavy loads, the rotational drive of the drill string, maintaining a closed mud circulation and preventing the uncontrolled leakage of drilling and reservoir fluids from the well.

The heavy weights of the drill string, casings and tubings are handled by means of draw works and a pulley tackle. During the drilling process, the drilling rig has to manage much higher loads in case that drill string gets stuck in the wellbore. The hook load is one of the most important values when a drilling rig has to be chosen for a specific operation. Big drilling rigs have a hook load of up to more than 1000 tons.

The rotary drive of the drill string is provided by either the rotary table in combination with the Kelly joint or the top drive. The first method uses a polygonal bar (Kelly joint) at the upper end of the round pipes of the drill string. The Kelly joint is positively connected to the rotary table, but it still can be moved up and down. The rotary table is driven by a motor. The top drive is installed on the hook of the rig and can be lifted and lowered. It is firmly connected to the drilling rig, so it can transmit high torques. The drill string can be directly attached to the top drive, which provides the rotary motion.

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1.4.2. The drill string

The drill string is the connection between the drilling rig at the surface and the underground operation place at the bottom of the wellbore. The upper part of the drill string consists of drill pipes which are mostly around 10 m in length and relatively light-weighted. Their purpose is to transfer the rotational forces and to lead the drilling mud to the depth of the well. The drill pipes must not be suspended to axial thrust. Otherwise they would instantly buckle. Therefore, the upper part of the drill string is always under tensile stress. However, the drill bit has to be pushed into the formation to destroy the rock. Hence, there is a neutral point in the drill string, where tensile and compressive stresses cancel out each other. The compressive forces in the lower part of the drill string are caused by the weight of the heavy-weight drill pipes and the even more massive drill collars. A scheme of a simple drill string is shown in figure 6.

Figure 6: Simplified design of a drill string with its components together with different stress

zones observed along the string (after [11])

The diameter of the drill string is much lower than that of the drill bit. Thereby the annulus, which is needed for the drilling fluid to rise up to the surface, is created. Stabilizers are installed to avoid buckling of the drill string in the lower part of the well. These are short tools with spiral blades, which are mounted on the drill collars or directly on a downhole motor (figure 7). This is especially important if high-tech equipment is installed above the drilling bit, as it is often the case in directional drilling operations (see chapter 1.4.3).

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Figure 7: Spiral blade stabilizers with different blade sizes [12]

The efficiency of a drilling process can be increased by increasing the rotational velocity of the drill bit. However, the drill string, especially the screw joints between the drill pipes, will suffer from the fast rotation because they will more excessively scratch on the borehole wall. Thereby, the drill pipes wear out, finally losing their stability. By means of a downhole motor, which is actually an eccentric screw pump, but driven by the hydraulic power of the fluid, additional rotational energy can be produced directly above the drill bit. The downhole motor is consists of a corkscrew-shaped rotor made of steel and a stator made of rubber, as shown in figure 8. It is driven by the drilling mud, which flows through the motor (between rotor and stator) and thereby causes the rotor to move. Powerful downhole motors may generate 750 kW [13].

Figure 8: Downhole mud motor with its inside view [14]

The drill string can also contain other components like drilling jars, which creates percussions in order to rip a stuck drill pipe free. There might be also shock absorbers integrated into the drill string. The usage of these tools prevents more delicate tools to be disturbed or even destroyed by vibrations or shocks during the drilling process.

1.4.3. Drill string components for directional drilling

Reich (2012) stated that “directional drilling is the art of drilling a well path according to a plan so that the well reaches the defined target.” [13]. For directional drilling operations, it is essential to know the course of the well path and where the drilling bit is exactly located in the underground. Therefore, an MWD (Measuring While

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Drilling) device is installed into the drill string near to the bit to determine the inclination and the azimuth of the wellbore. The MWD tool basically consists of a compass and plumb bob. To deflect the wellbore into the desired direction a directional drilling motor (bent sub) or a Rotary Steerable System (RSS) is needed.

A directional drilling motor consists of a downhole motor (mud motor) and a bent sub which has a small bending angle. With a directional drilling motor it is possible to drill both a straight and a deviated path. If the whole drill string is rotated from the surface, the well path will remain its direction, and a straight hole is drilled (figure 9, right). When the rotation of the drill string from the surface stops and the bit is only driven by the mud motor, the well path will be deflected in the direction of the bit position. [13, 15] This is shown on the left side of figure 9.

Figure 9: Drilling a deviated (left side) and straight well paths (right side) with a directional

drilling motor [16] (MWD/LWD: Measuring/Logging While Drilling)

A Rotary Steerable System, as it is shown in figure 10, is equipped with extendable steering rips, which can be pressed onto the borehole wall, causing the drill bit to change its direction.

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Figure 10: Rotary steerable system (RSS) with steering ribs [17]

There are other Rotary Steerable Systems working without steering ribs. Instead, there is a mechanism that deflects the drive shaft of the drilling bit so that it always points in the desired direction even while the drill string (including the RSS and the bit) rotates (figure 11). With such systems a range of tilt angles and therefore a range of radii of curvature can be adjusted.

Figure 11: Rotary steerable system (RSS) with deflected drill bit drive shaft [18]

Nowadays, nearly every well is directionally drilled. Directional drilling is of special importance in or near the target formation (e.g. oil or gas reservoir) in order to place the wellbore as beneficially as possible for future production operations. For those operations, information about the surrounding formation of the wellbore are required. Such data are measured by LWD (Logging While Drilling) tools. For example, clay layers can be determined by detecting natural gamma radiation and by resistivity measurements, it can be investigated if the pores of the reservoir are filled with water. [19]

The “intelligent” part of the drill string consisting of the drill bit, the directional drilling motor or Rotary Steerable System and the MWD/LWD tools is referred to as Bottom Hole Assembly (BHA). The BHA is provided by special service companies like Baker Hughes, Halliburton, Schlumberger or Scientific Drilling (cf. Chapter 4).

The data obtained by MWD and LWD are sent to the surface by Mud Pulse Telemetry. Special valves in the drill string create pressure changes in the mud column which can be detected at the surface. The “code” of pressure changes is then decrypted to get the information about the currently drilled well path and the surrounding formation. Usually, an MWD and LWD survey is conducted every 30

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metres. The more precise the measuring tools and the more often a survey is carried out, the better the drilled well will conform to the planned well path. However, all the measuring points contain errors which accumulate along the well path. In the case of long parallel wells, the uncertainties could start to overlap at some point. To avoid wellbore collision, the drilling operation would have to be stopped here. For such applications ranging technologies have been developed and comprehensive information about this technology is given in the following chapter.

1.4.4. Magnetic ranging

The distance and orientation of the well being drilled to a target or reference well can be determined by means of ranging methods. This technology facilitates drilling of a wellbore which is precisely orientated towards another well. There are active and passive magnetic ranging technologies.

Passive Magnetic Ranging (PMR) methods determine the magnitude and orientation of the magnetic field around the well being drilled, which is the sum of the earth magnetic field and possible interfering factors. One of those interfering factors is the steel casing of a reference well. If the earth magnetic field is constant in the drilling area and the reference well is the only interfering factor, the well being drilled can be oriented by means of the PMR measurements. However, due to the uncertainty, if there are other disruptive factors in the formation, measurements have to be taken every 2 metres of the well path. The parallel detection range is only 6 – 8 m, which is too short for the BIOMOre wells with the distance of 20 m (see figure 14). [20]

Active Ranging Methods (ARM) utilize a magnetic field of known strength and direction. The most widely used ARM method is the MGT (Magnetic Guidance Tool) technology. An electromagnetic source is positioned in the target well (lower one in figure 12) and the BHA of the well being drilled contains a specially designed directional sensor as shown in figure 12 (upper well).

Figure 12: Magnetic Guidance Tool (MGT) operational setup [21]

A measurement of the magnetic field is conducted every 9 metre. The data are analysed by special MGT software. The parallel detection range is around 30 m, with

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a maximal error of around 1 m. This technology might be technically applicable for the BIOMOre project. Other ARM methods are the Rotating Magnet Ranging Service with a parallel detection range of 15 – 30 m and the Single Wire Guidance Technology with a measuring range of up to 100 m. However, there are only few practical experiences on both technologies by now. [20]

The magnetic sources used for ARM operations are electromagnets which induce an electromagnetic field in the formation. Therefore ARM methods are affected by the specific electrical resistance of the drilling fluid and the formation. A water based drilling fluid should be used when applying ARM methods during drilling. This is possible in sandstone formations [22]. In the reference geology of the BIOMOre project, the copper ore is located between sandstone and limestone.

1.4.5. Horizontal drilling

In a horizontal well the force to push the drill bit into the formation cannot be provided by the weight of the drill collars if they are positioned directly behind it. The drill collars are always located in the vertical or inclined part of the well, but never in the horizontal section. The drill string in the horizontal part is always subjected to compressive strength. Therefore, simple drill pipes cannot be used and so that the lower part of the drill string is made of heavyweight drill pipes. The drill string lies on the borehole wall at the bottom side of the horizontal well. High friction forces occur when the drill string has to be pushed forward or rotated. The length of the horizontal section of a well is often limited due to this friction.

In the drilling industry, horizontal wells are distinguished by their radius of curvature into long, medium and short radius wells. The curvature is mostly given in °/100 ft (≈ °/30 m). The definition of long, medium and short radius is not sharp. However, the given values in figure 13 provide an impression about common radii [15, 23].

Figure 13: Definition of short, medium and long radius drilling

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The shorter the radius, the higher is the friction between the drill string and the borehole wall. Furthermore, the steel components of the drill string are relatively stiff and mostly around 10 m long. It gets more and more difficult to push these drilling tools through the well with decreasing radius, and the performance of delicate elements like the downhole motor could also suffer from extensive bending. Therefore, for medium to short radius wells special drilling equipment is needed, which is more expensive than conventional tools. However, by decreasing the radius of the directional section, the length of the horizontal section might be increased. Hence, the reservoir contact of the well would be greater, resulting in higher production rates following a successful completion in the reservoir. On the other hand, the higher friction forces in the deviated section with a short radius will limit the horizontal length of the well. The opposite effects of radius of curvature on the length of the production interval of the well have to be calculated and considered in the economic evaluation.

1.5. The BIOMOre wells

The well path, casing design and feasibility calculations were performed by using the commercial software Landmark Drilling and Completions (Halliburton). By means of this software two different configurations of the BIOMOre well were planned and designed including analyses regarding torque and drag of the drill string and casing.

Since 2016 several project-specific wellbore configurations have been discussed among project partners. At the project meetings in Freiberg (14.10.2016) and London (04.11.2016) selected configurations were introduced. These two configurations are:

Configuration 1: Two single horizontal wells

Configuration 2: Multilateral well with two horizontal branches

As shown in figure 14 both configurations include two horizontal wells with a length of the horizontal section of 900 m. In both cases the lower well (producer) is located in a true vertical depth (TVD) of 1564 m. The upper well (injector) is going parallel to the lower one in a distance of 20 m (1544 m TVD).

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Figure 14: Schematic of the two well configurations for the BIOMOre wells

The plan is to drill, case, perforate and stimulate the lower well at first. A MWD (Measuring While Drilling) device is used to follow the planned well path as good as possible. The second well or sidetrack is drilled after that. To ensure that the second well is parallel to the first one the ranging technology is used.

For well planning it is necessary to know the lithology and the pressure window of the formation to be drilled. Simulation assisted pore and fracture pressure values along the production well path were calculated by IFGT (table 1). The calculated pressure window is shown in figure 15.

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Table 1: Formation pore and fracture pressure profile

Depth [m] Formation Pore pressure [Bar]

Fracture Pressure [Bar]

0 Cenozoic Sediments 0.0 0.0




635 Buntsandstone 62.3 128.9






1240 Evaporite 121.6 261.9

1290 Evaporite 126.5 271.9

1440 Limestone 141.3 298.5

1500 Limestone 147.2 309.6

1610 Rotliegend & Grauliegend

Sandstone

157.9 233.8

1680 Rotliegend & Grauliegend

Sandstone

164.8 241.2

| Page 26

Figure 15: Pressure window for the BIOMOre wells

1.5.1. Well plan for the Configuration 1 (two single wells)

Well path

The lower well (producer) is drilled first. The vertical section of the producer is drilled to a depth of 1085 m. The deviated section with 3.65°/100 ft (long radius) reaches 90° inclination at 1837.4 m MD and 1564.0 m TVD. The following horizontal section has a length of 900 m as planned. Hence, the total length of the well is 2737.4 m. The data for the well path of the producer is given in table 2. The used abbreviation are explained as following:

MD: Measured depth (length of the wellbore along well path)

CL: Length of borehole section

Inc: Inclination

Azi: Azimuth

TVD: True vertical depth

NS and EW: Distance from reference point in NS and EW direction

V.Sec: Vertical section (horizontal distance from wellhead)

Dogleg: Curvature of the borehole section

0

200

400

600

800

1.000

1.200

1.400

1.600

1.800

0 100 200 300 400

TV

D [

m]

Pressure[bar]

Pore pressure

Fracture pressure

| Page 27

T.Face: Tool face orientation (direction of the drill bit)

Build: Build rate (increase of inclination)

Turn: Turn rate (increase of azimuth as measurement for the direction).

Table 2: Well path of the lower well (producer, Configuration 1)

After perforation and stimulation of the lower wellbore, the injection well is drilled. In relation to the production well the wellhead is located 20 m to the north. The vertical section of the injector is drilled to a depth of 1085 m. The following deviated section is characterized by a slightly shorter radius than the producer (3.80°/100 ft). The inclination of 90° is reached at 1806 m MD and 1544 m TVD. The horizontal section goes parallel to the horizontal section of the lower borehole with a vertical distance of 20 m and a length of 900 m. The total length of the well is 2706.0 m. The data for the well path of the injector is given in Table 3.

Table 3: Well path of the upper well (injector, Configuration 1)

MD

[m]

CL

[m]

Inc

[°]

Azi

[°]

TVD

[m]

NS

[m]

EW

[m]

V.Sec

[m]

Dogleg

[°/100 ft]

T.Face

[°]

Build

[°/100 ft]

Turn

[°/100 ft]

0 0 0 0 0 0 0 0 0 0 0

1085 1085 0 0 1085 0 0 0 0 0 0 0

1837.4 752.41 90 360 1564 479 0 479 3.65 360 3.65 0

2737.4 900 90 360 1564 1379 0 1379 0 0 0 0

MD

[m]

CL

[m]

Inc

[°]

Azi

[°]

TVD

[m]

NS

[m]

EW

[m]

V.Sec

[m]

Dogleg

[°/100 ft]

T.Face

[°]

Build

[°/100 ft]

Turn

[°/100 ft]

0 0 0 0 20 0 0 0 0 0 0

1085 1085 0 0 1085 20 0 0 0 0 0 0

1806 721 90 0 1544 479 0 459 3.8 0 3.8 0

2706 900 90 0 1544 1379 0 1359 0 0 0 0

| Page 28

The figures 16 and 17 show 2D and 3D images of the wellbores, as well as their placement in the reservoir.

Figure 16: Well path of injection (green) and production (blue) well (2D-image) for

Configuration 1

| Page 29

Figure 17: Well path of injection (green) and production (blue) well (3D-image) for

Configuration 1

Casing scheme

With the given pressure profiles and assumptions for loads during drilling and production, the following casing scheme was calculated and given in Table 4. For every casing string the outer diameter (OD), weight per meter, steel grade and safety factors are given as well as the steel costs.

| Page 30

Table 4: Calculation of casing specifications for the lower wellbore (producer, Configuration1), costs based on $700 per ton of steel

Footnote: * CC – Conductor Casing, SC – Surface Casing, IC – Intermediate Casing, PL – Production Liner

For the second well (injector) a similar casing scheme was calculated (Table 5). So, the overall casing steel costs for configuration 1 are around $325,000. The given costs are only for the pure steel. For the installation of the casings additional costs have to be considered as welding service, centralizers, cement, cementing, testing and measurement services.

String* OD

Weight

Grade

MD

Interval

[m]

Drift

Diameter

[inch]

Minimum Safety Factor (Abs) Design Cost

[$] Burst Collapse Axial Triaxial

CC

18 5/8‘‘

130.214 kg/m

J-55

0-30

17.567

+100

+100

+100

22.54

3,015

Total =

3.015

SC

13 3/8‘‘

101.195 kg/m

N-80

0-420

12.259

1.71

4.12

1.65

1.65

41,325

Total =

41,325

IC

9 5/8‘‘

59.527 kg/m

N-80

0-1085

8.75 A

1.93

2.15

1.45

1.45

62,793

Total =

62,793

PL

7‘‘

34.228 kg/m

N-80

1065-2737.4

6.25 A

2.16

1.64

1.35

1.31

55,637

Total =

55,637

| Page 31

Table 5: Calculation of casing specifications for the upper wellbore (injector, Configuration1), costs based on $700 per ton of steel


In terms of casing installation the 7´´ production liner is the critical part (high friction forces in the horizontal section). The liner with the liner hanger is set on a 5´´ drill string. Torque and drag calculations showed that the liner can be run to target depth without rotation.

Well completion

After finishing perforation and stimulation of the first wellbore along the horizontal section, a tubing string is installed. This string is a 5 ½´´ tubing with a subsurface safety valve in the upper part, in case of production a downhole pump and a packer at 1837.4m MD (above the perforated zone). The steel quality is N-80, and the weight is 25,299 kg/m³. The estimated steel costs are 45,300 $ based on the assumption of 700$ per ton of steel.

String* OD

Weight

Grade

MD

Interval

[m]

Drift

Diameter

[inch]



CC

18 5/8‘‘

130.214 kg/m

J-55

0-30

17.567

+100

----

+100

22.54

3,015

Total =

3.015

SC

13 3/8‘‘

101.195 kg/m

N-80

0-420

12.259

1.71

4.12

1.65

1.65

41,325

Total =

41,325

IC

9 5/8‘‘

59.527 kg/m

N-80

0-1085

8.75 A

1.93

2.15

1.45

1.45

62,793

Total =

62,793

PL

7‘‘

34.228 kg/m

N-80

1065-2706

6.25 A

2.16

1.69

1.35

1.32

54,592

Total =

54,592

| Page 32

The packer isolates the annulus between tubing and casing from the perforated part of the wellbore with expandable elastomers. The annulus between tubing and casing is filled with a fluid which protects the casing from pressure and temperature changes during injection/production and from corrosion caused by aggressive fluids. Figure 18 shows the casing scheme of the production well completed with the tubing string.

Figure 18: Casing and tubing scheme of the lower wellbore (producer, Configuration 1)

The injection well will be completed with a tubing string similar to that of the production well.

1.5.2. Well plan for the Configuration 2 (multilateral wells)

Well path

The lower well (producer) is drilled first. So, it is the so called parent wellbore. The vertical section of the producer is drilled to a depth of 1085 m. The deviated section with 3.65°/100 ft reaches 90° inclination at 1837.4 m MD and 1564.0 m TVD. The following horizontal section has a length of 900 m as planned. Hence, the total length of the well is 2737.4 m. The data for the well path of the producer is given in Table 6.

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Table 6: Well path of the parent borehole (lower horizontal section, producer, Configuration2)

The injector well is drilled as a side track of the parent wellbore. It leaves the parent well at the depth of 1045 m. The deviated section is characterized by a slightly less radius than the producer (3.5°/100 ft). The inclination of 90° is reached at 1828.8 m MD and 1544 m TVD. The horizontal section goes parallel to the horizontal section of the parent borehole with a vertical distance of 20 m and a length of 880 m. The total length of the well is 2708.8 m. The data for the well path of the injector is given in Table 7.

Table 7: Well path of the side track (upper horizontal section, injector, Configuration 2)

The figures 19 to 21 show 2D and 3D images of the multilateral well, as well as their placement in the reservoir.

MD

[m]

CL

[m]

Inc

[°]

Azi

[°]

TVD

[m]

NS

[m]

EW

[m]

V.Sec

[m]

Dogleg

[°/100 ft]

T.Face

[°]

Build

[°/100 ft]

Turn

[°/100 ft]

0 0 0 0 0 0 0 0 0 0 0

1085 1085 0 0 1085 0 0 0 0 0 0 0

1837.4 752.41 90 360 1564 479 0 479 3.65 360 3.65 0

2737.4 900 90 360 1564 1379 0 1379 0 0 0 0

MD

[m]

CL

[m]

Inc

[°]

Azi

[°]

TVD

[m]

NS

[m]

EW

[m]

V.Sec

[m]

Dogleg

[°/100 ft]

T.Face

[°]

Build

[°/100 ft]

Turn

[°/100 ft]

1045 0 0 1045 0 0 0 0 0 0 0

1828.8 783.83 90 360 1544 499 0 499 3.5 360 3.5 0

2708.8 880 90 360 1544 1379 0 1379 0 0 0 0

| Page 34

Figure 19: Well path of injection (green) and production (blue) well (2D-image) for Configuration 2

| Page 35

Figure 20: Well path of injection (green) and production (blue) well (3D-image) for Configuration 2

Figure 21: Placement of injection (green) and production (blue) well in the reservoir for Configuration 2

Casing scheme

With the given pressure profiles and assumptions for loads during drilling and production, the following casing scheme was calculated and given in Table 8. For

| Page 36

every casing string the outer diameter (OD), weight per meter and steel grade are given.

Table 8: Calculation of casing specifications for the parent wellbore (lower well,

Configuration 2), costs based on $700 per ton of steel


For the side track (injector) only the 7´´ production liner is needed. The liner hanger is set at the depth of 1025 m and the liner reaches to the target depth of 2708.8 m MD. The liner is of the same quality as the production liner of the parent wellbore (34.228kg/m, N-80) and it is estimated cost is $56,000. So, the overall casing steel costs for Configuration 2 are around $220,000. The given costs are only for the pure steel. For the installation of the casings additional costs have to be considered as welding service, centralizers, cement, cementing, testing and measurement services.

In terms of casing installation the 7´´ production liner is the critical part (high friction forces in the horizontal section). The liner with the liner hanger is set on a 5´´ drill

String* OD

Weight

Grade

MD

Interval

[m]

Drift

Diameter

[inch]



CC

18 5/8‘‘

130.214 kg/m

J-55

0-30

17.567

+100

----

+100

22.54

3,015

Total =

3.015

SC

13 3/8‘‘

101.195 kg/m

N-80

0-420

12.259

1.71

4.12

1.65

1.65

41,325

Total =

41,325

IC

9 5/8‘‘

59.527 kg/m

N-80

0-1085

8.75 A

1.93

2.15

1.45

1.45

62,793

Total =

62,793

PL

7‘‘

34.228 kg/m

N-80

1065-2737.4

6.25 A

2.16

1.64

1.35

1.32

55,637

Total =

55,637

| Page 37

string. Torque and drag calculations showed that the liner can be run to target depth without rotation.

Well completion

After finishing perforation and stimulation of the wellbore along the horizontal section, a tubing string is installed. This string is a 5 ½´´ tubing with a subsurface safety valve in the upper part, in case of production a downhole pump and a packer at 1837.4 m MD (above the perforated zone). The steel quality is N-80, and the weight is 25,299kg/m³. The estimated steel costs 45,300 $ based on the assumption of $700 per ton of steel.

The packer isolates the annulus between tubing and casing from the perforated part of the wellbore with expandable elastomers. The annulus between tubing and casing is filled with a fluid which protects the casing from pressure and temperature changes during injection/production and from corrosion caused by aggressive fluids. Figure 22 shows the casing scheme of the production well completed with the tubing string.

Figure 22: Casing and tubing scheme of the parent wellbore (lower well, configuration 2)

The injection well will be completed with a tubing string similar to that of the production well.

1.5.3. Drilling program

All the wells discussed above can be drilled with standard drilling equipment. A water based mud with a density of 1050 kg/m3 can be used.

In terms of drilling the most critical step is drilling the horizontal parts. In the deviated and horizontal part the drill sting is built of heavy weight drill pipes. Normal drill pipes would buckle due to compression forces. Because the relatively heavy drill string lies on the lower side of the borehole the friction forces are high. So, torque and drag calculations were carried out. The calculations showed that for the BIOMOre wells

| Page 38

buckling limits are just achieved. So, the usage of a rotary drilling system is recommended.

The drill string always contains a MWD system (Measuring While Drilling) for directional drilling. For drilling the BIOMOre production (lower) wells a MWD system with low measurement errors is recommended. With such a system the absolute measurement error at target depth is +/- 4.66 m in vertical direction and +/- 1.49 m in horizontal direction.

The injector (upper) wells are directed through the ground using a magnetic ranging system to guide the second (upper) well in parallel to first (lower) well. As in chapter 1.4.4 presented, Active Ranging Methods (ARM) can be used. Their measurement error is +/- 1 m. So, the overall well path error of the injection well in vertical direction is +/-5.66 m.

| Page 39

2. Perforation Technologies

The most common perforation technologies in the oil and gas industry, as well as geothermal industry, are bullet guns and jet guns. Bullet guns were already applied in the 1930s and jet guns in the 1940s. Perforation guns are therefore a fully developed and still the most applied technology [24].

Other methods are hydraulic, abrasive perforation (water jets), laser perforation or radial drilling. These technologies are only used for some special applications in oil and gas industry, or most of them are still under development. These technologies will be described in the following chapters briefly, but the focus of this document will be put on perforation guns due to the requirements of the BIOMOre project.

2.1. Gun types

A perforating gun consists of a carrier with many single explosive charges. The charges can explode in all radial directions and thus shoot holes into the casing and the cement. The explosions also affect the near wellbore area directly behind the cement, causing little fractures. The perforation gun on a wireline is lowered into the well, and the explosions are ignited from the surface.

2.1.1. Bullet guns

Bullet guns work like a revolver with a muzzle velocity of around 1000 m/s. The diameter of a gun hole is 8 cm or larger. A bullet gun is equipped with ca. 13 – 19 shots per meter in a phasing between 60 and 120 °. They should be used in the formations with compressive strengths up to around 40 MPa. When the compressive strength is lower than around 14 MPa, the perforation length achieved by bullet guns will be higher than with jet guns. Bullet guns have been favoured over jet guns if accurate and consistent perforation size is required. Gun clearance should be low when applying bullet guns to ensure that most of the energy during shooting is used to perforate casing, cement, and formation. High gun clearance leads to dissipation of much energy within the gun carrier, which may result in burring. A typical bullet gun is shown in figure 23.

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Figure 23: Typical bullet gun and its components [24]

2.1.2. Jet guns

Jet guns (also: shaped charge guns) are the most used perforation guns. Over 90 % of the wells are perforated with jet guns [24]. The perforation process is a chain reaction which is illustrated in figure 24. An electrical ignition from the surface detonates first the primacord, the high-velocity booster, and the main explosive. Then the conical liner begins to flow because of high pressure and the inner metal layers form a needle-like high-speed jet of fine particles (≈ 6000 m/s) causing a pressure of around 35,000 MPa at the point, where the jet leaves the gun case. The outer layers of the liner form a slug (so called: carrot) with a velocity between 450 and 900 m/s. The slug may plug some flow paths in the perforated rock. Therefore, its dimension should be as small as possible. The higher the quality of the jet gun, the less material forms the slug. However, high quality is often accompanied by higher costs.

| Page 41

Figure 24: Jet perforating process [24]

Jet guns can be constructed as hollow-carrier or exposed-charge guns. In a hollow-carrier gun, the jets are inside a heavy wall tube or carrier and therefore, sealed against wellbore fluids and pressure. When charges detonate, detonating pressure is confined within the carrier which causes slightly swelling or fracturing of the carrier. However, recovery of the carrier from the wellbore is not affected. The advantage is that most debris from the exploding charges remains in the carrier after detonation. There are two configurations of hollow-carrier guns: reusable and expendable.

Reusable hollow-carrier guns have fix openings in the tube (figure 25). Sealable port plugs hold the charges in the openings. After perforation operation, the port plugs can be renewed if necessary, and the carrier can be used several times.

| Page 42

Figure 25: Reusable hollow-carrier gun [24]

Expendable hollow-carrier guns have no prefabricated openings for the charges, but in most designs, external recesses or scallops are provided in the carrier wall as shown in figure 26-a. After detonation of the jets, the carrier is destroyed and the gun is discarded when recovered from the well (figure 26-b).

Figure 26: a) Expendable hollow-carrier gun and b) recovered expendable hollow carrier gun [24]

Exposed-charge guns are not surrounded by a carrier and therefore the shaped charges have to be individually sealed against wellbore environment. Detonating cords are also exposed to wellbore pressure, temperature and fluids. Especially in deviated wells, the components of the gun might be damaged by grinding along the casing. The charges can be a little larger than charges of a hollow-carrier for the

| Page 43

same well diameter which makes the gun more efficient. The disadvantage of this construction is that all debris falls into the wellbore after detonation. This might cause damage to tubing, downhole pumps and etc. In figure 27, an exposed-charge gun together with hollow-carrier gun, for comparative purposes, is shown.

Figure 27: Exposed-charge gun (left) and hollow-carrier gun (right, for comparison) [25]

2.1.3. Through-Tubing guns

The outer diameter of conventional through-tubing guns is much smaller than the inner diameter of the casing which may result in high gun clearances. Centralizing is not practical in this case because all perforations would be in poor hole size and perforation depth as mentioned in chapter 2.1.1. These guns are thus often deployed by using magnets or by mechanical means to have contact with the casing. It is important to notice that the phasing is limited to 0 – 60°.

Figure 28 shows another configuration of through-tubing guns which is an extended-diameter through-tubing gun. The charges are pivot-mounted inside the carrier. When running through the tubing, which is shown in the upper part of the pictures in figure 28, the charges are folded into the carrier wall (left picture of figure 28). When the gun has left the tubing and reached the location to be perforated, the guns can be then deployed (middle picture of figure 28). In their firing-position (right picture of figure 28) the charges have only a low distance to the casing. The efficiency of the perforation operation can be thus increased for the through-tubing gun [26].

| Page 44

Figure 28: Working mechanism of an extended-diameter through-tubing gun [24]

2.1.4. Hydraulic abrasive perforators

In perforation operations with hydraulic abrasive perforators, a mixture of fluid and sand is jetted through an orifice against the casing. The higher the wellbore pressure, the lower is the penetration. The efficiency of this technology is already significantly reduced if the wellbore pressure is greater than 2 MPa [27]. The addition of nitrogen intensifies the fluid stream. Hydraulic abrasive perforation is more time-consuming and cost intensive than perforation by guns. An advantage of hydraulic abrasive perforation is that the penetration depth can be controlled by adjustment of pumping rates and pressure [28].

2.1.5. Laser perforation

Permeability enhancement by lasers relies on the creation of micro-fractures in the formation by inducing thermal stresses. When a laser beam is targeted on a rock, it is heated up to several hundred degrees Celsius causing the rock material to expand. After laser application, it cools down and contracts again. During this process, micro-fractures develop. Furthermore, some mineral components are melted or even vaporized at the high temperatures produced by the laser which also contributes to the creation of fractures [29, 30].

2.1.6. Radial drilling

Radial drilling is an alternative perforation method. Such an operation can be divided into three working steps, as shown in figure 29. In the first step, small holes around 1’’ in diameter are milled into the casing. The mill is driven by a mud motor connected to a coiled tubing. In the second step, a hose with a nozzle is inserted into the hole. Then a fluid is pumped through the nozzle with a pressure higher than the

| Page 45

frac pressure of the formation. Thus, a hole with a distinct length is created by hydraulic jetting. In the last step, the hose is pulled out of the hole. By continuously pumping the fluid, the hole is washed out [31, 32].

Figure 29: The operation steps of a radial drilling [33]

2.2. Factors affecting the perforation operations

A well-planned perforation operation leads to higher fluid flow efficiency between wellbore and reservoir. Successful perforation can be achieved by suitable perforation geometry and underbalanced perforating in solid-free liquids [34]. Favourable formation properties are crucial as well as drilling history. High-extent formation damage during drilling operation affects the communication between well and reservoir in a negative manner. Some factors influencing perforation operations are described below:

2.2.1. Perforation geometry

Perforation geometry is determined by shot density, clearance, depth of perforation, shot phasing and diameter of shot holes (hole size). All parameters have characteristic influences on the perforation operation as explained in detail below.

Perforation (shot) density depends on desired flow rates, formation permeability and length of the perforated interval. The optimal shot density is calculated depending on expected production data before starting the perforation operation. The shot density varies between 6 and 14 shot per meter. The stress limits of the

| Page 46

casing must always be considered. It is also noteworthy to mention that reduced perforation density leads to lower costs.

The shot phasing is the angle between the charges. Most common values are 0°, 180°, 120°, 90° and 60° as shown in Table 9 [35].

Table 9: Shot phasing for well perforations [35]

The gun clearance is the distance from the gun to the casing. A high clearance leads to insufficient penetration length, inadequate hole size and irregularly shaped holes. Bullet and jet guns should be operated with 0 – 1.5 cm clearance [36]. However, the diameters of hollow-carriers are often large enough, so only small clearances are obtained. Clearance control can be conducted by using spring-type deflectors or magnets. If the gun clearance is higher than 5 cm and it cannot be reduced due to the high ratio between wellbore inner diameter and gun outer diameter, decentralization of the gun and orientated explosions can be taken into account. Figure 30 shows typical performance variations with a 90° phased perforator with 1 11/16´´ diameter inside a 7´´ casing.

Parameter Value

Phasing: 0° 180° 120° 90° 60°

Number of shots:

1 2 3 4 6

| Page 47

Figure 30: Performance variations caused by gun clearance [27]

| Page 48

The penetration depth and hole size of jets can be designed to either achieve maximum penetration depth or maximum hole size. With regard to plugging or for hole cleaning purposes, the minimum entrance diameter of a hole should be around 1 – 1.5cm [27].

The compressive strength of the formation also has an effect on the perforation depth and on the selection of the guns. Jets penetrate deeper than bullets in formations with higher stiffness. In formations with lower stiffness, bullets are more efficient than jets (figure 31).

Figure 31: Performance of bullet, jet and hydraulic perforator types in formations of various compressive strength [27]

Increased values of compressive strength of casing, cement and formation rock leads to a reduction of penetration length and hole size for jet perforators, but to a much greater extent for bullet guns. Casing properties, such as the strength of the steel and wall thickness have a minor effect on penetration depth, but definitely affect the hole size. In general, the higher the casing strength, the lower will be the hole size. Multiple casing strings also affect perforation performance negatively.

2.2.2. Pressure and temperature

High bottom hole pressures could be a limiting factor for exposed charge guns. High temperature (HT) environments may cause self-detonation. HT perforation packages are available and should be used under these conditions. Using an expandable rubber impression packer, the location of the perforations downhole can be analysed.

| Page 49

2.2.3. Underbalanced perforating

Usually in wellbores overbalanced conditions are dominant. This means the pressure in the wellbore is slightly higher than the formation pore pressure. Underbalanced conditions are present in a borehole when the well pressure is lower than the reservoir pressure (formation pore pressure). Such conditions are preferable for perforation operations because the pressure between formation and wellbore prevents the perforation from plugging by the slug of a gun or by solids from the drilling mud.

2.3. Challenges of perforation operations

2.3.1. Plugging of perforations

The holes can be plugged by metal slug, mud solids, crushed formation rock and etc. Clean perforations are achieved by using carrot-free jet guns and operating at underbalanced conditions (pressure of reservoir > wellbore pressure) in solid-free fluids (e.g., salt water, oil). In order to remove plugging material from perforations in unconsolidated sands, backsurge tools and perforation washers can be used [37]. In carbonate reservoirs, mud plugs can be removed by acidizing. The usage of acids (HCl or CH3COOH) as a perforation fluid is common in carbonate reservoirs and prevents plugging of the perforation holes.

2.3.2. Casing splitting and damage

The lower the casing strength and diameter, the higher the perforation density, the more likely is casing splitting. Hollow-carriers should be used because they absorb remaining energy from charge explosions. By operating with zero gun clearance damaging burrs inside the casing are avoided.

2.3.3. Cracking of cement

Usage of hollow-carriers is again recommended if the cement cracks depending on cement quality and cross section, as well as perforation density.

2.4. Perforations for hydraulic stimulation

For hydraulic stimulation operations, large, round and smooth holes (diameter ca. 1.9cm) are needed to provide low pressure loss at high flow rates. The shots should be positioned according to fracturing design, as well. The emphasis is clearly put on hole diameter and hole geometry; the perforation depth is of secondary interest.

| Page 50

3. Hydraulic stimulation

Hydraulic stimulation of a reservoir is initiated by injecting fluid through an open hole or perforated well at high pressure. As long as the fluid is pumped, the fracture propagates into the reservoir. The pressure which is required for fracture propagation is often lower than that for frac initiation. Propagation of the fracture is mostly normal to the minimum principal stress direction and should have been considered during well planning. Due to the high formation pressure in the earth through overburden, an induced fracture would close after a short time. Therefore, support materials (proppants) are pressed into the fractures with the fracture fluid to keep it open and thus maintain high conductivity. Hydraulic stimulation has been applied in both low- and high-permeable reservoirs.

3.1. Multilayer stimulation – zonal isolation

During stimulation of several zones within a well, the individual zones have to be isolated from each other. This can be done either by diversion or progressive perforation and stimulation.

3.1.1. Diversion

In case of operating in open hole sections with a too large diameter or in cased holes with poor casing cement wherein the usage of packers is impracticable, diverting agents are then used. Bridging material is introduced into the well to plug an existing fracture at the face of the borehole wall. Hence, no further fluid can penetrate into that fracture during stimulation of the next stage. The most common bridging materials are graded water-soluble rock salt and oil-soluble ground naphthalene. The success of this zonal isolation with diverting agents is very uncertain; therefore, the application of mechanical bridge plugs or packers is mostly preferred.

3.1.2. Progressive perforation and stimulation

The well intervals are preferably stimulated from bottom to top of a wellbore due to operational and technical reasons. After the process has been finished in the first zone, it is isolated, and the next zone can be perforated and stimulated. There are several mechanical tools for isolation as explained below.

Mechanical bridge plugs:

Mechanical bridge plugs can be run on drill pipes or wireline. Plugs run on tubulars are retrievable and can be used several times. Wireline plugs cannot be removed after stimulation and have to be milled.

Hydraulic stimulation with wireline plugs are usually more time efficient and do not require a drilling rig. In figure 32 the plug-and-perforate operation using wireline plugs is sequentially illustrated. The first interval was isolated at the bottom of the well by a wireline bridge plug. After that, the perforation gun is lowered into the

| Page 51

borehole, so the casing is perforated. After the gun is retrieved, the hydraulic stimulation fluid is injected and then the stimulation of the first interval is performed. In the next step, another plug is set to isolate the next interval and the procedure can be started again. After stimulation of all intervals, the plugs have to be milled.

Figure 32: Scheme of plug-and-perforate operation using wireline plugs

Hydraulic stimulation operations using tubular plugs are conducted when the productivity of the intervals shall be tested before the next interval is stimulated. These operations can be performed using a drill rig or coiled tubing unit. In figure 34 the plug-and-perforate process using tubular plugs is illustrated. The BHA is run into the borehole and set at the desired position to perforate casing and cement. Then the tool is lifted up and set above the perforated interval, the bridge plug is inflated, and the stimulation fluid can be pumped finally. After successful stimulation, the fluid and, especially, the proppants have to be sufficiently flushed out of the wellbore. Before the bridge plug is loosened and the operation is repeated in the next zone, the conductivity of the stimulated formation can be tested.

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Figure 33: Plug-and-perforate assembly with one tubular plug [38]

Usually, the pressure needed to initiate the development of fractures in the rock, decreases with decreasing depths of the formation [39]. If the stimulation operation is conducted from bottom to top of the well, only one bridge plug could be sufficient (figure 33). In horizontal wells, two plugs can be used to secure the wellbore above and below the actually treated zone.

Figure 34: Plug-and-perforate process with two tubular plugs [40]

Frac baffles:

Frac baffles are part of the casing string as illustrated in figure 35.

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Figure 35: Frac baffle operations developed by Halliburton [41]

The baffles have to be installed between the different perforation intervals. After the lowermost interval is stimulated, a fracturing ball is dropped into the casing string. The ball seats on the frac baffle and seals the lowermost interval from the upper part of the wellbore. The next interval can be treated. If multiple zones are stimulated, the diameters of the frac baffles have to be gradually decreased from bottom to top of the well. The balls can be removed from the well with the stimulation fluid. This method of zonal isolation is very time-efficient [42]. The major disadvantage is that the seating efficiency of the balls (pressure-tight isolation) is quite uncertain due to the erosion of the baffles which is caused by the proppants in the hydraulic stimulation fluid.

3.2. Special features for deviated and horizontal wells

Before planning a deviated and horizontal wellbore, special technical requirements should have been considered due to the complexity. The well section to be fractured must be thoroughly cemented to provide good zonal isolation. The use of external casing packers and selective perforating should also be considered.

Already during the planning of the well path, the reservoir conditions such as formation stress has to be considered. The orientation of the well with respect to the formation stress determines fracture orientation and therefore, the direction of the

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deviated or horizontal section of the well should be either along or perpendicular to the minimal principle stress (figure 36).

Figure 36: Longitudinal and transversal fractures for different azimuth angles (α) of wellbore laterals [43]

Stimulating a well, which is drilled diagonal to the direction of a minimum principal stress, may result in very complex fracture geometries. In this case, it would be much harder to ensure that there is no communication between the different treated intervals which would be detrimental to injection or production performances.

The creation of few large (fracture length and aperture) and highly conductive fractures is intended. Multiple small and branched fractures cause excessive pressure losses. To minimize this effect in highly deviated and horizontal wells, the length of the perforated interval should be limited to around 4 times the wellbore diameter [43].

The proppant transport is essential in deviated wells. Depending on the properties of the stimulation fluid and the used proppants, there is a critical velocity below which the proppants are deposited on the bottom of the deviated well section. In order to re-suspend the proppants, even higher fluid velocities than a critical velocity are required. This should be considered for completion and pump dimensioning.

Deviated and horizontal wells are commonly fractured using coiled tubing [24, 44] to bring the equipment in place.

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3.3. Hydraulic stimulation fluids

Fundamental requirements on liquids, which are applied for hydraulic stimulation, are low fluid loss, low formation damage, good proppant transport as well as cost-effectivity and environmental compatibility. The mostly used fluids are as follows.

3.3.1. Newtonian fluids

Newtonian fluids like water, diesel or brines are applied in hydraulic stimulation operations with high pump rates in reservoirs with low to moderate permeability. The advantage of this type of liquids is that they hardly cause formation damage. However, the fractures created with Newtonian fluids are mostly quite short. The liquids show poor proppant transport capability and there is significant fluid loss into the formation matrix.

3.3.2. Non-crosslinked polymer gels

Polymers, which are used in non-crosslinked polymer gels for hydraulic stimulation, are for example guars, xanthan or biopolymers. Hydroxyethyl cellulose (HEC) is mostly used because the gel formed by HEC does not release residues in the reservoir. Therefore, it causes low formation damage. The polymer solutions show improved fluid loss and proppant transport capabilities compared to Newtonian fluids.

3.3.3. Borate-crosslinked fluids

Borate-crosslinked fluids contain guars in brine, e.g. fresh water, sea water, brines of NaCl and KCl. The cross-linking with borate depends on pH-value (pH > 9: cross-linking, pH < 8: no cross-linking). These fluids are stable against high shear, exhibit good fluid-loss control and effective proppant transport. They are often applied in high permeable reservoirs [27].

3.3.4. Organometallic-crosslinked fluids

Organometallic-crosslinked fluids, such as titanate and zirconate complexes of guars, are mostly applied in lower permeable formations. They are stable at high temperatures (>150 °C) and show very good proppant transport properties. In low permeable reservoirs they build up a resilient filter cake, which results in excellent fluid-loss control. Since the filter cake can be removed, it only seldom causes formation damage. However, in high permeable formations, the application of organometallic-crosslinked fluids leads to great in-depth formation damage.

3.3.5. Gelled-oil systems

Gelled-oil systems were the first high-viscosity fluids used for hydraulic stimulations. Therefore, there is considerable practical experience with these fluids. They prevent clay swelling because of their low water content. Gelled-oils have low fluid loss,

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moderate to good proppant transport and good clean-up characteristics. However these systems are costly and there are concerns about HSE issues (Health, Safety & Environment).

3.3.6. Surfactant gels

Surfactant gels are polymer-free viscous fluids. The viscosity is developed by the formation of complex (e.g. wormlike) micelles and decreases in contact with hydrocarbons. These systems are shear-thinning, show good proppant transport and low formation damage. The fluid loss capabilities are comparable to Newtonian fluids or non-crosslinked polymer solutions.

3.3.7. Foams

Foams are two-phase mixtures (liquid/gaseous) stabilized by surfactants. The liquid phase is usually water. The gas phase can contain nitrogen or carbon dioxide. By now foams have been only rarely applied, but there have been successful operations with nitrogen-foamed borate-crosslinked fluids [27]. The fluid loss of foams is lower than when only water is applied as hydraulic stimulation fluid. Possible application areas might be in high-permeable low-pressure gas reservoirs. The major disadvantages are that there is more complex equipment needed for a stimulation operation using foams, and these systems show insufficient proppant transport.

3.3.8. Emulsions

An emulsion is a mixture of polar (e.g. water) and nonpolar (e.g. oil) phase, stabilized by surfactants. Emulsions are only seldom used because of HSE and equipment limitations. Gel breakers are needed for post treatment clean-up of fractures to remove gels. Otherwise, these gels have a detrimental effect on fracture conductivity. Table 10 shows the guidelines for fluid selection on hydraulic stimulation operations.

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Table 10: Fluid-selection guidelines for hydraulic stimulation operations [45]

Reservoir/formation

condition

Favoured fluid

systems

Disfavoured fluid

systems

Perforated-interval length

< 15 m Non-crosslinked gel,

surfactant gel

Borate-crosslinked fluid

15 – 30 m Non-crosslinked gel,

surfactant gel, borate-

crosslinked fluid

> 30 m Borate-crosslinked fluid Non-crosslinked gel,

surfactant gel

Reservoir permeability and fluid type

< 50 mD, gas Non-crosslinked gel,


crosslinked fluid

> 50 mD, gas Borate-crosslinked fluid Non-crosslinked gel,

surfactant gel

< 500 mD, oil Non-crosslinked gel,


crosslinked fluid

> 500 mD, oil Borate-crosslinked fluid Non-crosslinked gel,

surfactant gel

> 500 mD, Heavy oil Non-crosslinked gel,


crosslinked fluid

Reservoir quality (lithology)

Uniform sand Non-crosslinked gel,


crosslinked fluid

Laminated pay Borate-crosslinked fluid Non-crosslinked gel,

surfactant gel

Layered pay with

interbedded shale

Borate-crosslinked fluid Non-crosslinked gel,

surfactant gel

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3.4. Proppants

The most common types of proppants are either naturally occurring silica sand or manufactured alumina-silicates (ceramics). They are injected with higher pressures into the created fractures to prevent the fractures from closure due to formation pressure. In most applications, a mixture of LWC (LightWeight Ceramic) proppants (≈ 50 % Al2O3) and silica sand is used [46]. LWC have the same density as silica sand, but greater sphericity and roundness. Their compressive strength is higher than sand but lower than bauxite proppants, whereby bauxite proppants (70 – 80 % Al2O3) have high compressive strength. The conductivity of a proppant-packed fracture depends on a variety of parameters, such as particle size, proppant concentration, proppant strength (hardness) and density as well as their grain shape as explained below.

3.4.1. Particle size

In general, the larger the particle size of the proppants, the higher will be the conductivity of the fracture. However, it should be noted that large proppants may not be transported that far into a fracture (bridged out). Therefore, the end of a fracture may not be stabilized by proppants and could be closed by formation pressure. Large proppants are more likely crushed and deformed by high closure stress. Hence the conductivity is less influenced by proppant size at high closure stresses.

3.4.2. Proppant concentration

The proppant concentration is defined as the mass of proppants per surface area of the fracture. The higher the proppant concentration, the higher is the fracture conductivity. The proppant concentration should be chosen to be higher in formations with lower stiffness, due to partial embedment of the proppants.

Close contact to formations/fluids not to be affected

< 15 m Non-crosslinked gel,

surfactant gel

Borate-crosslinked fluid

> 15 m Borate-crosslinked fluid Non-crosslinked gel,

surfactant gel

Reservoir pressure gradient

< 0.9 MPa/100 m Borate-crosslinked fluid Non-crosslinked gel,

surfactant gel

> 0.9 MPa/100 m Non-crosslinked gel,


crosslinked fluid

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3.4.3. Proppant strength (hardness) and density

The higher the formation stress (for example in deep wells), the higher must be the hardness of the proppants. It should be noted, that stronger proppants are also denser and more expensive.

3.4.4. Grain shape

Proppants with high roundness (measure of sharpness) and sphericity are preferred. The shape determines the porosity and packing structure of the proppants. The rounder the grains, the higher are the porosity and permeability, and the closure stress is more uniformly distributed.

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4. Organization of a drilling operation

In the oil and gas industry the oil companies (e.g. Shell, Exxon Mobil, Wintershall etc.), which in the end sell the recovered hydrocarbons, invest in drilling operations. In most cases, the oil companies do not own or operate drilling rigs but rent the necessary equipment and staff. However, there is always a company representative on the rig site to stay informed about the drilling progress.

The drilling rig, the essential parts of the drill string and drilling crew are provided by the contractor. The drilling crew usually works 24 hours, 7 days a week in two or three shifts. The crew consists of the drilling supervisor (tool pusher), shift supervisors (drillers), floormen, labourers, truck drivers, electrician, assistant driller, crane operator, welder, radio operator and at least a mechanic. The contractor is responsible for the professional handling and maintenance of the rig and the drill string.

Drilling a well is a very complex operation, and there are different service companies which have specialized on a special task of the drilling operation. They are responsible to develop and maintain high-tech equipment and so they have the expertise to utilize it in a professional way. In the case of logging services, they also have the know-how to analyse and to interpret the data, which are obtained during their operations. [5, 47]

Every company develops and produces its own products with own technology. Products from different companies are not compatible with each other. The handling of the equipment and the analysis of obtained data is so complex that the staff of a service company needs time-consuming and complex training. Therefore, there is always a service engineer on the rig site, who is responsible for the professional application of his tool.

The following aspects of a drilling operation are mostly performed by service companies:

Drilling Fluid

Casing running

Cementing

Well stimulation (hydraulic stimulation)

Perforating

Installation of packer

Mud logging

Mud motor

Directional drilling

Logging while drilling

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Well Testing

Wireline services

Coiled tubing

Fishing services

Casing milling

Some services contributing to drilling and completion operations are accompanied to others. For example, perforation and fishing services require wireline or coiled tubing services. Packers are often needed for well stimulation.

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5. Cost estimation

There are many factors influencing the financial expense of a drilling operation. The following list of factors affecting well costs does not claim completeness:

Drilling, mud program and completion program

Evaluation, measurement, logging

Safety services

Trucking, rig moving

Engineering, supervision, administration

Surface conditions

Well location and infrastructure

Target of the well (field development or exploration)

Commodity prices (consumables and produced materials to be sold)

Economic environment (i.e. supply and demand of different drilling services)

Company policy

Taxation effects in different countries

Time is a critical factor with respect to the financial plan of a drilling operation because in most cases the rig including personnel and all the drilling services are rented per day [23]. Even the costs of two theoretically identical wells may vary because of time delay in the drilling schedule due to weather conditions, the human factor and logistics. Since the service companies are operating on different well sites, there could be a delay in the delivery of tools which costs time. Drilling a well is a complex interplay between the contractor, the oil company and all the different service companies on the rig site. Problems during the drilling process, like wellbore instabilities, are not even considered in this study. It is nearly impossible to predict, how long a drilling operation will last and every additional day needed for a special service can push up the price for the well significantly.

There are of course fix costs, which can be quite easily estimated. The costs of the well site can be assessed when the location is defined, and from the well plan, the required amount of casings can be concluded. Knowing the actual price for steel a rough estimation of casing costs can be made.

However, these expenses only make up 10 – 20 % of the total drilling costs and the share varies between different projects (see figures 37 and 38). Other challenging factors with respect to cost estimation are the political, legal and tax-law regulations, which differ very much in the different countries.

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Based on the variety of the above-mentioned impact factors, it becomes clear that there are hardly even two wells, which have been drilled under similar conditions. Cost estimation for a planned drilling operation by comparison to other wells is therefore very difficult.

The cost assessment for a drilling operation is very complicated and complex. Particularly in the case of the BIOMOre well, there are no publications on well costs in Germany, which are comparable. With respect to stimulation costs, it is even more complicated to get data on the financial scope. The application of this method is very restricted due to political decisions in Germany. German operators mostly banned hydraulic stimulation from their service portfolio. Therefore, conclusive information about the costs of hydraulic stimulation operations on the German market with respect to German laws could not be gathered. The only available data were received from the company Fangmann Energy Services GmbH, who estimated only the costs for the pumps required for the stimulation operations with around €65,000.

However, subsequent to the elaboration of a possible well path and the borehole construction with the needed casing diameter and their installation depths, industrial partners from Germany have been contacted to estimate the costs of such a well roughly. It has to be noted that the statements are based on the assumption of two separate wells (Configuration 1, no bilateral well). All contacted persons confirmed that the assessment of drilling costs is a very complex topic, especially if there are only the geology, a concept of the wellbore design and model-based underground stress profiles supplied. As a rough estimation, the costs of one BIOMOre wellbore were stated to range between 5 (lower limit) and 20 Mio. € (upper limit). The share of the drilling costs for only one well was assessed as shown in figure 37. For configuration 1 (Chapter 1.5.1) the second well is anticipated to be less expensive because the well site will be already built. In Configuration 2 the steel for the casings in the vertical section is needed only once. However, the precise technology required for drilling a multilateral well might cause some additional costs.

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Figure 37: Drilling cost expenses for one wellbore (Configuration 1) estimated by the company Rhein Petroleum GmbH (used with the courtesy of that company)

For comparative purposes, the pie diagrams of expenses of the pilot and the main wells of the KTB (Kontinentale Tiefbohrung – continental deep drilling) project are given in figure 38. The KTB project was a geoscientific research project conducted in Germany. The objective was to investigate the continental crust of the earth extensively. The main well is the deepest drilled well in Germany and one of the deepest in the world (9101 m) [48].

Figure 38: Drilling cost expenses of the pilot and main well of the KTB project (after [48])

Although the KTB wells were already drilled more than 20 years ago (1987 – 1994) the shares of costs show a good conformity to the estimation for the BIOMOre well (figure 38). The drilling rig and the drilling costs amount for the greatest part of the financial expenses.

Well site construction

11,9%

Drilling 53,1%

Material Costs (Lost in Hole)

12,7%

Cementing and Completion

13,3%

Measuring/Testing

4,9%

Misc. 4,2%

Estimated shares of BIOMOre drilling costs

overall financial volume: ca. 5 Mio. €

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6. References

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