d6.1 integration plan - unileoben.ac.at

This project has received funding from the European Union`s Horizon 2020 research and innovation programme under grant agreement No. 641202.

D6.1 Integration plan ThermoDrill Identifier: ThermoDrill-D61-ESG-02-IntegrationPlan

Author(s) and company: Clément Baujard (ESG), Albert Genter (ESG), Régis Hehn (ESG), Olivier Seibel (ESG), Antony Martin (RED), Philipp Hilzensauer (RED), Alexander Buchner (Sirius), Johann Plank (TUM), Timon Echt (TUM), Roland Faschingbauer (GES), Alfredo Ramos Rodriguez (INERCO), Antonio Diaz (INERCO), Dimitra Teza (BESTEC), Sepp Steinlechner (MUL)

Document status: Final version

Work package: WP6

Confidentiality: Public

Keywords: Drilling, Geothermal energy, ThermoDrill, Integration, FMECA, SWOT, Simulations

Abstract: This document contains a detailed integration plan of all the ThermoDrill system parts, including a FMEA and SWOT analysis.

Version Date Reason of change

1 11/04/2017 Document created

2 30/08/2017 Final version

The content of this report reflects only the authors’ view. The European Commission and Innovation and Networks Executive Agency (INEA) as well as the Swiss Government are not responsible for any use that may be made of the information it contains.

The work was supported by the Swiss State Secretariat for Education, Research and Innovation (SERI) under contract No. 15.0163.

Ref. Ares(2019)851796 - 12/02/2019

ThermoDrill D6.1 Integration Plan

© ThermoDrill - consortium - all rights reserved page ii


© ThermoDrill - consortium - all rights reserved page iii

Table of Content

Executive Summary ............................................................................................................ 1

1. Introduction ..................................................................................................................... 2

1.1 Purpose of this document .......................................................................................... 2

1.2 Scope of this document .............................................................................................. 2

1.3 Related Documents ................................................................................................... 2

2. Overview of a conventional rotary drilling process, system parts and associated operations ............................................................................................................................ 3

2.1 The rotary drilling process .......................................................................................... 3

2.2 Downhole equipment and parameters ........................................................................ 5

2.3 Surface operations related to drilling .......................................................................... 9

2.4 Drilling mud ...............................................................................................................10

2.5 Surface operations related to mud ............................................................................13

2.6 Conventional drilling PFD (Process Flow Diagram) ...................................................16

2.7 Conventional drill site ................................................................................................18

3. ThermoDrill system parts and connections description of connections ...................20

3.1 State of the ThermoDrill system parts development ..................................................20

3.2 ThermoDrill downhole specific element parts description ..........................................22

3.3 ThermoDrill BHA (Bottom Hole Assembly) ................................................................22

3.4 ThermoDrill BHA and specific elements connections ................................................23

3.5 ThermoDrill mud system ...........................................................................................24 3.5.1 ThermoDrill mud .................................................................................................................................................. 24 3.5.2 Field tests mud .................................................................................................................................................... 26

4. ThermoDrill process and operations description ........................................................28

4.1 ThermoDrill surface operation related to downhole equipment ..................................28

4.2 ThermoDrill surface operation related to mud ...........................................................29

4.3 ThermoDrill drilling PFD (Process Flow Diagram) .....................................................31

4.4 ThermoDrill drill site ..................................................................................................34

4.5 ThermoDrill HSE aspects ..........................................................................................36

5. Simulated test run of the well operating conditions ...................................................38

5.1 Simulation description ...............................................................................................38

5.2 Borehole trajectory ....................................................................................................39

5.3 Torque and Drag simulation ......................................................................................40

5.4 Hydraulic simulation ..................................................................................................43

6. FMECA - Failure Mode, Effects an Criticality Analysis ...............................................47

6.1 Failure Mode, Effects and Criticality Analysis description ..........................................47

6.2 Methodology .............................................................................................................47 6.2.1 Function .............................................................................................................................................................. 47 6.2.2 Functional Failure ................................................................................................................................................ 48 6.2.3 Failure Mode ....................................................................................................................................................... 48


© ThermoDrill - consortium - all rights reserved page iv

6.2.4 Failure Cause ...................................................................................................................................................... 49 6.2.5 Failure Effects ..................................................................................................................................................... 50 6.2.6 Failure Detection ................................................................................................................................................. 51 6.2.7 Severity Classifications ........................................................................................................................................ 51

6.3 Assumptions .............................................................................................................53

6.4 ThermoDrill taxonomy and equipment partition .........................................................53 6.4.1 Taxonomy ........................................................................................................................................................... 53 6.4.2 FMECA work frame ............................................................................................................................................. 56

6.5 ThermoDrill FMECA results.......................................................................................56

7. SWOT analysis ...............................................................................................................57

7.1 Strengths ..................................................................................................................58

7.2 Weaknesses .............................................................................................................58

7.3 Opportunities ............................................................................................................58

7.4 Threats .....................................................................................................................59

7.5 SWOT analysis results ..............................................................................................59

8. Conclusions ...................................................................................................................60

9. References .....................................................................................................................61

10. Glossary ..................................................................................................................62


© ThermoDrill - consortium - all rights reserved page 1

Executive Summary

The main goal of the ThermoDrill project is the development of an innovative drilling system to allow minimum 100% faster drilling in hard rocks and a cost reduction of more than 30% for the well construction.

In order to achieve this goal, the ThermoDrill project counts on the following physical process: to take the tension out of the rock in front of the drill bit. This phenomenon is supposed to allow the bit to erase and break the rock surface easier and faster. The technology planned to be used to achieve this goal is “water jetting”. The ThermoDrill project aims to prove that this technique, combined with traditional drilling operations, fulfils the rapidity increase and the cost reduction goals.

The jetting technology consists in the generation of a high pressure drilling mud jet (approx. 3000 bars) propelled toward the rock formation through small nozzles (approx. 1 mm). This high pressure jet damages the formation beneath the drill bit, enhancing the drilling speed. The high pressure is generated by a Downhole Pressure Intensifier based on piston pump technology. A driving unit operates the pressure intensifier, using the drilling mud flow in the drillstring as a source of energy. The mud going through the jetting system and the drilling mud used for lubrication of the drill bit and for the evacuation of the drilling cuttings are the same. This last point implies to adapt the traditional mud circuit to improve its filtration in order to preserve the jetting devices.

In order to ensure that all elements parts developed within the ThermoDrill project will interoperate smoothly; the proposed integration plan briefly describes all ThermoDrill equipment parts, details connections and interfaces between the different parts.

A conventional drilling process is exposed, in order to be used as a base to the integration of the ThermoDrill process. The impact of the use of a ThermoDrill tool and mud on the drilling process and operations is quantified. Special attention is paid to the monitored parameters and to the mud cleaning process, which is, as a result, the most impacted process by the use of ThermoDrill.

The well operating conditions are then simulated, using Wellplan software packages from Halliburton Landmark, which is an industry standard solution.

Then, a Failure Mode, Effects an Criticality Analysis (FMECA) and a Strength, Weaknesses, Opportunities and Threats (SWOT) analysis is proposed, based on the integrated ThermoDrill process and on the simulated well operating conditions.

Some results of the works carried out in WP6 are confidential. Therefore, 2 versions of the deliverable D6.1 “Integration plan” were prepared: a public version, which can be widely distributed, and a confidential version, which is to be used only by the ThermoDrill Consortium.



1. Introduction

1.1 Purpose of this document

This document proposes an integration plan of the overall ThermoDrill Process. It presents the integration of the ThermoDrill specific elements on a conventional drilling process.

Thus, this document should be seen as a tool to make sure that everything has been considered, that every part fits together, and that everyone in the project is aware of the concerns of other partners.

Moreover, the FMECA and SWOT analysis performed pointed out that the integration of the ThermoDrill process on a drill site and in a drilling process could bring some additional complexity to a drilling process, which is already complicated. Thus, the guideline for this deliverable is to make sure that the ThermoDrill process is easily implementable on a real drill site, and that the additional complexity introduced is reduced as much as possible.

Finally, the public version of this deliverable will inform the community on the progress of the project and on the basic details of the developed technology.

1.2 Scope of this document

This document describes the conventional drilling technology process and protocols. Then, it highlights the modifications that have been made to integrate the jetting system, study and minimize the inherent risks of this technology

1.3 Related Documents

Although the ThermoDrill system parts are briefly described in this deliverable, the purpose of this document is not to describe every system part in detail. Thus, the reader is invited to refer to the following documents for the different system parts:

Specification and design of the different drilling prototypes: D3.4. This deliverable also contains information on the DPI (Downhole Pressure Intensifier) and the results of the FMECA, which has a strong impact on the process design

ThermoDrill Drilling Mud: D4.1

ThermoDrill Bit Design: D5.1 and D5.2

For the rock mechanical tests and numerical simulations, the reader should refer to D2.1, D2.2 and D3.3.

This deliverable is also linked to D7.1 (Test and Validation Plan), as the integration and the testing of the ThermoDrill Process interact in both ways.



2. Overview of a conventional rotary drilling process, system parts and associated operations

This section proposes a general overview of a conventional drilling process, from downhole equipment (including the bit and BHA) to surface equipment (mud cleaning and solid control); including the mud types. The required operations are also described. Casing running, and cementing, mud logging and well testing are not described here as these processes are not impacted by the ThermoDrill drilling process.

2.1 The rotary drilling process

The process of rotary drilling is relatively simple (see Figure 1). A tool (drill bit) is rotating downhole and damaging the rock at the bottom of the well. The rotational energy is generated on the rig (“rotary drilling”) and transmitted to the drill bit via the drill string, which are rotating in the well. A drilling fluid is injected in the drill string, goes out of the tool at the well bottom and comes back at the surface through the annulus space between drill strings and the open hole or the casings. The mud has to lubricate the tool, give a hydrostatic pressure on the well to avoid collapse and carry the cuttings to the surface.

Figure 1 – Conventional rotary drilling process. The arrows figure the mud circulation loop.

Conventional (old) drilling rigs use a rotary table to generate rotation on the rig floor (see Figure 2) whereas modern rigs use a Top Drive System (TDS, see Figure 3). In this latter case, the rotation is generated on the mast below the hook. The vertical movement of the travelling



block, hook and swivel (or of the TDS) can use drawworks and cable brakes or on hydraulic transmission.

Figure 2 – Main elements of a conventional drilling rig with a rotary table



Figure 3 – Top drive system (source RED)

2.2 Downhole equipment and parameters

Drill Bit

Typically, two families of bits are to be distinguished: Roller Cone and PDC bits (see Figure 4). The drillstring or the mud-motor gives rotation to the bit. For a Roller Cone bit the bit cones roll along the bottom of the hole in a circle. As they roll, teeth come in contact with the bottom of the hole, crushing the rock immediately below and around the bit tooth. On the contrary, a PDC bit has no moving part and the cutters scrape the bottomhole rock when the tool is rotating.

Figure 4 – Examples of Roller cone bit (left) and PDC bit (right) examples (source Smith Bits)



Roller Cone Bit design focal points include:

The bit body

Bearing types

Cone configurations

Cutting structures (Inserts or standard)

Metallurgical, and hydraulic considerations in engineering bit design solutions.

PDC bit design focal points include:

The bit body

Blades numbers (3, 5, 7) and configuration

Cutting structures (numbers and shape of cutters)

Metallurgical, and hydraulic considerations in engineering bit design solutions.

More details on drill bit types and design can be found in ThermoDrill deliverables D2.3 and D3.3.

BHA (Bottom Hole Assembly)

The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavy-weight drillpipe, jarring devices ("jars") and crossovers. The bottomhole assembly must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment and provide the driller with directional control of the well. Often the assembly includes a mud motor for directional drilling, measurements-while-drilling tools, logging-while-drilling tools and other specialized devices.



Figure 5 – Typical Bottomhole assembly for drilling a vertical well (left) and a deviated well (right). Source: Schlumberger Oilfield Glossary

In both directional and straight holes, the position of the well must be known with reasonable accuracy to ensure the correct wellbore path and to know its position in the event a relief well must be drilled. The measurements themselves include inclination from vertical, and the azimuth (or compass heading) of the wellbore. These measurements are made at discrete points in the well, usually every 30 m, and the exact path of the wellbore computed from the discrete points. Measurement devices range from simple pendulum-like devices to complex electronic accelerometers and gyroscopes used more often as MWD becomes more popular.

It is possible to integrate some tools in the BHA that provide LWD services (Logging While Drilling), which provide measurement of formation properties during the drilling phase, or shortly thereafter during a dedicated trip into the hole. LWD, while sometimes risky and expensive, has the advantage of measuring properties of a formation before drilling fluids invade deeply. Furthermore, many wellbores prove to be difficult or even impossible to measure with conventional wireline tools, especially highly deviated wells. In these situations, the LWD measurement ensures that some measurement of the subsurface is captured in the event that wireline operations are not possible. Timely LWD data can also be used to guide well placement so that the wellbore remains within the zone of interest or in the most productive portion of a reservoir



Directional drilling

Two main directional drilling technologies exist:

Mud motor with a bent housing

Rotary Steerable Systems.

A mud motor has a prescribed bend set on it as recommended by the BHA design to meet its trajectory requirements. The mud motor itself does not rotate while steering, but generates torque that is transferred to the bit whilst drilling. During sliding the directional driller steers the assembly via tool faces supplied by the MWD tool where his "12 o'clock" on the drillers display references the bend on the motor pointing to the highside of the hole. Once a slide interval is complete the string can be rotated to hold a trend if needed.

Figure 6 – Typical mud motor system (source: Prime Horizontal)

A Rotary Steerable System (RSS) on the other hand rotates all the time barring its housing. The bit is oriented by actuators inside the tool to point or deflect to a tool face supplied by the directional driller (Point-the-bit). Other methods include extending the RSS pads against the well bore to achieve deflection (Push-the-bit). The benefits of the RSS are its ability to compensate changes in bit deflection either by surface telemetry or cycling the pumps while drilling and maintaining rotation. It gives the directional driller the flexibility to make spot decisions on the fly and change them.

Figure 7 – Typical RSS1

RSS allows complex well geometries, a better hole cleaning, but are more expensive than mud motors.

1 Source: http://www.ingenieriadepetroleo.com/rotary-steerable-system-directional-drilling



Drilling parameters

The main drilling parameters are:

RPM: Rotations Per Minute = Bit rotation speed. The bit rpm is very dependent on the tool being used. It typically varies from 40-120 rpm for a roller cone bit to 300 rpm for PDC bits. In order to reach such high values of RPM, it is necessary to use a downhole motor.

WOB: Weight On Bit (see Figure 8). The WOB depends on the drilled section diameter. Typical WOB value when drilling a 8’’1/2 section is around 5-15 tons.

Figure 8 – Weight On Bit

2.3 Surface operations related to drilling

RIH (Run in hole) operations

The BHA is picked up in components, starting with the steering mechanism (PDM/Rotary steerable), the first stabilizer, and the MWD non-magnetic drill collar. At this point, any adjustment to the bend in the motor is made and MWD/LWD installed in the collar and initialised, before the drill bit is screwed and torqued to the bottom connection. The first part of the BHA is lowered into the hole slowly as the Directional Driller draws the line from the bent point of the motor to the highside line of the MWD collar and the offset is measured. This is so any offset between the two caused by torqueing the tools together can be input into the surface software. The rest of the BHA, including any further stabilisers, drill collars, jars and heavy weight drill pipe (HWDP) is then picked up and run in hole, followed by the drill pipe. As each item is run in hole, the driller will check it off his tally in order to maintain accurate depth tracking. At this stage the drillstring will be run in on the rig’s elevators and won’t be connected to the top drive system.

As the tubulars are run in, they will displace drilling fluid from the borehole. As the displacement volume is known, it will be tracked on a “trip sheet” to ensure that the correct volume is



displaced and that any discrepancies are noted and dealt with where necessary; e.g. too much displacement from calculated could indicate an influx into the well, and too little displacement could indicate fluid losses in the well.

Once the drill bit reaches the last casing shoe depth, the well will be “flow checked” to make sure the fluid level is static, before running in further.

During the trip in, if any tight spots are encountered (indicated by increasing drag on the drillstring) then the top drive system of the rig will be connected to the drill pipe and the rig pumps started to reduce the drag and clean any cutting which may be in the borehole (“washing down”). If this does not solve the issue then rotation from the top drive will be applied in addition to the rig pumps (“reaming down”). Usually, this last procedure will take place 20-30 m before bottom is reached as a matter of standard practice.

POOH (Pull out of hole) operations

Pulling out of hole is simply the reverse of running in hole, with the addition that the well will be circulated clean for at least a full circulation cycle before the pulling out of the drillstring commences.

Normal drilling operation

During a normal drilling operation, the parameters such as weight on bit (WOB), rotary speed (RPM) and flow rate, will be set by the Directional Driller so as to achieve the optimum environment for rate of penetration, trajectory control and hole cleaning. Once these are set for a particular formation, the Driller will track the parameter trends seen on an hourly basis, as shown in Figure 9.

Figure 9 – Driller’s Trend Sheet

Once a stand of drillpipe (either two or three singles joined together, depending on the size of the rig) has been drilled all the way down, the driller will pick the bit off bottom and ream the section which has just been drilled. This helps to clear cutting from the BHA and move them uphole to surface and helps avoid stuck pipe. The driller will then bring the bit to around 1 m from bottom and hang the drill pipe off in “slips”. This equipment sits in the rotary table and bears the weight of the entire drillstring in the borehole so the top drive system can be disconnected and raised up in the derrick to pick up the next stand of drill pipe. This is termed “making a connection”. This process will be continued until the final depth of the well is reached, or there is reason to pull out of hole, e.g. for a bit change or downhole tool failure.

Maintenance operations

Routine, daily maintenance such as servicing the top drive system with grease will usually be undertaken during a connection and rarely impacts the drilling process by more than a few minutes. However during trips in or out of hole, the drilling line will periodically be “slip and cut” to change the wear positions between the line and the sheaves. This operation is performed when the drill bit is inside the casing shoe and not in open hole.

2.4 Drilling mud

A brief overview of drilling fluid fundamentals can be found in deliverable D2.2. The consortium provides in the following an overview of the conventional mud types used in drilling industry.



Role of mud

The drilling fluids or muds serve numerous purposes within the drilling process, as there are:

Carrying the cuttings generated by the drill bit back to surface

Maintaining hydrostatic pressure against the confining pressure of the rock to avoid collapsing borehole

Maintaining hydrostatic pressure to contain potential fluids or gases under pressure from the reservoir

Preventing fluid loss during the drilling operation for cooling the tools

Stabilization of clays

Lubricate tool and string to reduce friction due to rotation

The ability to carry all cuttings from the bottom of the borehole to the surface as well as cooling and lubricating the drill bit are among the most important roles of the drilling mud. Efficient hole cleaning consequently allows higher rates of penetration and generally requires a mud with a high carrying capacity (high yield point and good suspending properties).

When drilling conventional oil and gas wells, managing the borehole pressure is one of the most important requirements for the drilling mud. The borehole pressure should always be maintained in the “pressure window” between pore pressure and fracture pressure. If the borehole pressure is below the pore pressure, formation fluids and gases may enter the borehole. While above the fracture pressure, cracking of the formation can occur resulting in loss of the drilling fluid (lost circulation) (Darley 1988).

The borehole pressure is composed of the hydrostatic pressure, regulated by the fluid density, and the dynamic pressure that consists of pressure resulting from friction when circulating the drilling fluid. Controlling the fluid density is extremely important for borehole safety, as the impact of the dynamic pressure is much smaller compared to the impact of the hydrostatic pressure. Maintaining the desired fluid density is achieved via solids control at the surface where all cuttings should be removed. However, it is difficult to separate them from the drilling mud without removing essential fluid components such as e.g. the viscosifier. Another function of drilling fluids is to transmit hydraulic power to the drill bit.

For geothermal wells, the drilling mud has slightly different requirements, as the formation typically is highly permeable (for example through the presence of natural fractures) in order to be economical for e.g. hot steam production. Due to the highly permeable formation, mud density has to be as low as possible (often just fresh water or salt water), to reduce the occurrence of lost circulation events without endangering borehole stability. A positive secondary effect is that differential sticking events are less common because the pressure difference between borehole and formation is rather small. Lubrication presents an important factor on geothermal wells drilled through hard, crystalline rock formations which not only can damage the drill bit but also the drill pipe and reamers. Furthermore, the drilling mud also needs to cool the drill bit to prevent excessive wear of the bit.

Removing the cuttings is achieved by using a drilling fluid with high carry capacity (high yield point) which can clean the borehole well from any debris. Since geothermal wells are drilled in hot formations, cooling the bit is more important than on conventional oil and gas drilling.

Different mud types, main parameters and typical values

Important properties for drilling fluids include rheology, filtration control properties, density and pH. Rheology of drilling muds is typically determined using a rotational coaxial cylinder viscometer such as the FANN 35SAor the PVS Rheometer which allows for testing under actual borehole conditions. Using the shear stress values determined at different shear rates, the plastic viscosity (PV), yield stress (YP) and gel strengths can then be determined. These values describe the ability of the fluid to suspend cuttings (yield point), the energy required to pump the fluid (plastic viscosity) and the gelling behaviour of the drilling mud when circulation



is stopped for a longer period of time (static aging). Alternatively, the Marsh funnel can be used to measure relative changes in the viscosity of the mud. The Marsh funnel viscosity describes the time required for 1 quart of the drilling fluid to flow through the funnel.

Numerous different types of drilling fluids exist and the choice of drilling fluid depends on a variety of factors such as, among others, expected temperature and pressure, characteristics of the drilled formation, required density, operator preferences and health, safety and environmental (HSE) considerations. Water-based fluids are predominately used in geothermal drilling, this includes bentonite muds, dispersed muds and polymer muds.

Bentonite is a naturally occurring swelling clay mineral with the layered clay montmorillonite as the main component. Bentonite hydrates in alkaline water forming a viscous shear thinning colloidal suspension. However, when exposed to high temperatures, bentonite muds can gel excessively leading to problems when circulation needs to be reinitiated after a stop in pumping. A typical bentonite mud used in Northern Germany contains polyanionic cellulose (PAC) to enhance filtration control. The system is characterized by high YPs and PVs with a YP:PV ratio of ~ 1.

Dispersed systems are muds treated with dispersants such as lignites, lignosulfonates or tannins to deflocculate clay particles allowing for improved rheology control in high-density alkaline muds. The deflocculation leads not only to lower YPs and gel strengths, but also the filter-cake quality is improved as in the dispersed system a thin, low permeability filter-cake is formed.

Polymer systems include xanthan gum based systems which use the polysaccharide biopolymer xanthan gum as its viscosifier. The system has the advantage that relatively it is shear thinning, salt tolerant, provides adequate hole cleaning and solids are easy to remove. However it is not very temperature stable as it degrades at high higher temperature (> 120 °C) and requires constant replenishment. It is usually formulated with freshwater and a pH control agent. Modified starch can be added to improve the hole cleaning properties and provide fluid loss control. They are often used to drill reactive formations because unlike bentonite, they are compatible with shale inhibitors such as amines. As biopolymers generally degrade when exposed to elevated temperatures over prolonged periods of time, synthetic polymers are extensively used at high temperatures as they possess higher thermal stability. This includes polymers such as polyacryamides, polyacrylates and especially 2-acrylamido-2-methylpropane sulfonic acid (AMPS®) based copolymers such as Hostadrill which function up to 200 °C.

Mud circulation

Shown in Figure 1 below is a schematic of a basic land rig circulation system. The drilling mud is circulated through the drill pipe to the drill bit and back up through the borehole annulus. The mud is then cleaned (see Section 2.5 for further details) and pumped into the mud tank. If required, adjustments to the drilling fluid are made such as addition of further additives if the properties of the mud have changed (rheology, pH, density, etc.). The replenished mud is then injected again into the borehole. For a 8’’1/2 section, the typical mud circulation rate is around 1500-2000 L/min.



Figure 10 – Basic rig circulation system (source IADC 2015)

2.5 Surface operations related to mud

A general description of the mud system is given in ThermoDrill deliverable D2.3 and in Deliverable 3.2. The consortium focuses in this document on the process and element parts.

Mud preparation

Mixing and treatment of drilling fluid is done even on the rig site or in a specially designed mud plant. For most onshore activities in Europe, water base drilling fluids are mixed at the rig side, while NAF (non-aqueous fluids) are prepared in mud plants. The procedure and required equipment is very similar in both cases.

Required equipment is provided by the drilling contractor or service companies. The basic equipment is part of the drilling rig and consists of following components:

Mud tanks

Mixing hopper od high shear hopper (for NAF)

Mixing pump

Additional Equipment

Storage tanks for drilling Fluids

Storage tanks for Products (Barite, Bentonite)

Bulk transfer equipment

Transfer pumps

Forklift

Cutting table for big bags

Safety:

Follow HSE standards and procedures

Enclose hopper as much as possible

Local exhaust ventilation or PPE (respiration productive equipment)

Provide required PPE as per SDS



The detailed fluid recipe as designed by the drilling fluid company and accepted by the operator descripts product concentrations, mixing procedures and required quantities. The drilling fluid engineer will supervise the mixing process. He will do the required testing and adjust product additions as required to ensure the correct fluid properties.

State of the art of mud cleaning

The design objective of any solids control system is to achieve a step-wise removal of progressively finer drilled solids. This allows each piece of equipment to optimize the performance of downstream equipment.

Fluid cleaning is a continuous process, which involves different equipment parts (solid control system):

The shale shakers, to remove the medium and intermediate particles (cuttings),

The screens (desilter – desander), to remove fine particles,

Centrifuges, for fine and ultra-fine particles,

Dewatering unit, to remove ultra-fine particles and colloidal solids.

An integrated solid control station is showed in Figure 11. The different system parts are showed in Figure 12 and are briefly described below.

Shale Shaker l Mud Cleaner I Desilter I Centrifuge

Figure 11 – Integrated solid control station principle, including Shale Shaker, Mud Cleaner, Desilter, Centrifuge



Figure 12 – Different elements constituting an integrated mud cleaning system. Shale shakers (1); desilter (2); cuttings and fine collecting tank (3); mud tanks and mud pumps (4); centrifuges (5)



Shale shakers

They are the primary defence against the drilled solids contamination and they can handle the entire circulating flow rate. Shale Shakers remove the drilled solids on the basis of size at the first pass, but they still allow barite and other additives to remain in the circulating system. These shakers can remove solids larger than 74 microns. Their motion type can be linear, balanced elliptical (BEM) or circular.

Screens

The Screens are the primary component. Their defined characteristics are the type and the size. These parameters affect capacity, separation efficiency, blinding resistance and screen life.

Desander removes solids with sizes of 44 microns and larger.

Desilter removes solids with sizes of 20-25 microns and larger.

Microclones removes solids with sizes of 8-15 microns and larger.

Mudcleaner.

Processing rates are depending on the numbers of cyclones and has to be min. 125% of the circulation volume.

Centrifugation unit

Centrifuges remove solids with sizes of 5 microns and larger. The primary benefit of centrifuge utilization is to control fine solids that would contribute to undesirable mud density or rheology. The processing rate determines the retention time of solids available for separation by the centrifuge. Unless solids are exposed to the centrifugal forces for the time required to settle out then they will not be removed. Greater processing rates result in larger cut points. Usual processing rates are 10-30 m³ / hour.

Dewatering unit

A dewatering unit combines the use of a centrifuge with chemical treatment (use of coagulants / flocculants).

2.6 Conventional drilling PFD (Process Flow Diagram)

The PFD (Process Flow Diagram) of a conventional drilling process is showed in Figure 13. This process is focussed on the mud loop, which is the most impacted process by the ThermoDrill system. The sensors and typically monitored parameters are also showed in this figure.

As the mud goes out of the well, it goes through gas separator, for safety, and through a series of mud cleaning processes (see detailed description in section 2.5). The cleaned mud is collected in an active mud tank, where it is monitored and mixed again with additives. The resulting drilling mud is then reinjected into the well with the help of the mud pumps.

Numerous parameters related to the mud and to the drilling itself are monitored in the whole process. The most important parameters are the applied Weight on Bit and speed, and the resulting Torque and Rate of Penetration. The gas graphs from the mud are also very important for the well security.



Figure 13 – Conventional drilling PFD



2.7 Conventional drill site

A conventional drill site is constituted by the following equipment:

The rig, including o the pipe rack, walk way and pipe handling system o the mast (Derrick), TDS and pipes o the generators o the mud pumps

some storage for pipe and casings

the cabins and facilities (toilets, showers etc.) for the rig company crew and services crews

some water storage capacities, mainly for the pumping tests

the mud preparation and solid control area

A typical conventional drilling implementation is showed in Figure 15. As it can be seen on the drawing, the surface reserved to mud preparation and solid control operations is very important.

Figure 14 – Conventional drill site view (source RED)



Figure 15 – Conventional drill site (source RAG)



3. ThermoDrill system parts and connections description of connections

This section proposes a detailed description of the ThermoDrill system parts, focusing on the connection between parts.

3.1 State of the ThermoDrill system parts development

The development of the different parts of the ThermoDrill system is not a straight forward process. Conventional drilling is a complex combination of many different domains, professions and expertise. The ThermoDrill system also adds its part of complexity, risk and uncertainties, making the global process even more complex. Due to the global complexity of the whole system, one of the principal concerns of the development of the ThermoDrill system was trying to keep it as simple as possible to implement and operate. Many studies, simulations, laboratory tests and expert deliberations have been made to make the prototype designing phase possible.

The development of the ThermoDrill system started from the initial “jetting” idea, leading systematically to the real condition test phase of the prototype:

1. The question that had to be answered at the beginning of the project was: is the jetting

really damaging hard rocks? And if so, what is the influence of the different jetting

parameters (pressure, temperature, nature of fluid, angle of jetting stream, standoff

distance etc) on the final resulting damage of the hard rock surface? To answer this

question, numerical models, and laboratory tests have been conducted. As a first result,

the jetting proved to be efficient to damage hard rock samples. The simulations showed

that the jetting pressure needs to be approximately 4000 bars. The angle of the jetting

stream should be orthogonal to the rock surface and not deviate too much from this

trajectory to ensure effective damage.

2. The second major question was will the jetting process damage the hard rock

under real deep underground conditions? To answer this question, the consortium

proposed a representative model of what would be deep hard rocks drilling conditions:

3 km depth, 300 bars of confining pressure, abrasive and massive granite, 150°C,

diameter of 8’’1/2, etc. Further models and laboratory tests have been made, taking

into account these new parameters. The uncertainties of the results increased slightly

due to the complexity of the numerical models and the impossibility to reproduce

exactly the downhole conditions in the laboratories. Finally, the literature review

showed that the jetting technology should work in real drilling conditions. Some

adjustments and tests on the high pressure system showed that the assumed jetting

pressure is effective even at higher nozzle diameters.

3. Once it is known that the technology should work, an essential part of the research is

the design phase of the prototype. This phase is conducted to see how the

technology can be included in a conventional drilling system. The numerical models

are continuously adapted to the new designs in order to asses that the current version

of the prototype is still compatible with the jetting technology, and that the capacities of

the ThermoDrill drill bit are not altered. Other simulations are developed to be sure that



the newly designed ThermoDrill tool is compatible with the conventional drilling

technology.

This phase is particularly critical because the development of the prototype is costly and nothing should be missed. As the conventional drilling technology is already a complex process, many parts have to be designed to obtain the global ThermoDrill system:

o the drill bit adapted to the high pressure jetting;

o the Downhole Pressure Intensifier;

o the Driving Unit of the DPI;

o the connections between the different parts;

o the drilling and jetting fluid;

o the filtering system.

Two more phases are necessary to conclude the ThermoDrill project, but they have not started at the redaction of this report:

4. The next phase corresponds to the manufacture of the prototype.

5. The final step corresponds to the testing phase of the prototype.

In phase 3 (prototype design), workgroups have been created to boost the design and developments on previously listed ThermoDrill parts. The main results are listed below:

o Choice of the drill bit type: tricone bit, with Tungsten carbide inserts and one

or two high pressure nozzles. The tricone bit has been chosen because it is the

most common bit used in hard rocks and because the integration of the high

pressure system is easier in tricone than in PDC bits.

o Position of the Pressure Intensifier: downhole. The generation of high

pressure at surface is easier but then the system would need a second mud

string with high pressure connections all along the drilling pipes. The choice to

have a high pressure generator downhole is safer and finally simpler. In

consequence, only one fluid will be used for jetting and drilling.

o Position of the filtration system: on surface. The filtration degree of the mud

is essential for the longevity of the downhole high pressure system. The

decision has been made not to put any filtration system downhole for the

fraction of the mud going in the DPI, because of the lack of robustness and the

poor results of this type of solutions. Filtration of the mud at surface is

challenging because all the mud has to be filtered properly as all the mud can

potentially be used for the high pressure jetting. Nevertheless, this solution is

more robust, reliable and the simplest method.

o Technology of the Pressure Intensifier: piston pump with mechanical driving

unit. The choice has been made to keep the system as simple as possible to

increase its longevity and its robustness.

o Choice of the drilling and jetting fluid: sepiolite based mud. It was agreed by

the consortium that the use of single fluid is the way to proceed, as the technical

complexity added by a dual fluid drilling process (one jetting fluid and one drilling

fluid) was estimated as a technology killer from the drilling engineers. The mud

has to keep good carrying parameters at high temperature and to be compatible



with the jetting. The jetting with this type of mud is still on-going at the time this

report is written.

The prototype design is not fully finalized at the time this report is written and some cited parameters could still be modified depending on the results of additional simulations and tests.

3.2 ThermoDrill downhole specific element parts description

DPI

The DPI will intensify the pressure from the hydrostatic pressure of the moving mud column inside the drillstring to up to a significant high pressure and pass this through to high pressure nozzles in the drill bit, in order to be able to effectively jet the bottom of the borehole. The installation of the DPI in the collar must allow for the majority of the flow to pass around the intensifier. The volume of fluid required by the intensifier will be drawn directly from the fluid flow. The high pressure fluid will exit through high pressure nozzles housed in the drill bit.

The DPI will be housed in a purpose built collar, directly above the drill bit and contain one pressure intensifying system. This intensifier will lead to a single high pressure outlet at the base of the collar to be connected directly to the high pressure connection of the bit.

The collar should have an 8.375” stabilizer, straight or spiral bladed, on the lower end of it (1 m – 2 m from the lower connection).

The pressure intensifier will be mechanically driven using the mud flow from the rig pumps and operate whenever the rig pumps are running.

The DPI should be able to be removed from the collar in a workshop for maintenance.

More details on the DPI Design can be found in deliverable D3.4.

ThermoDrill Bit

A novel Rolling Cone Drill Bit is currently under development that will provide the means for the high-pressure jetting of the hard rock.

More details on the ThermoDrill Bit can be found in deliverables D3.4 and D5.1.

3.3 ThermoDrill BHA (Bottom Hole Assembly)

The planned BHA for the ThermoDrill system is kept as simple as possible. No directional system is planned at the moment. The reason why no directional system is integrated in the BHA is that the ThermoBit has to be plugged directly to the DPI. A directional drilling system (bent motor or RSS) should be integrated on the top of the DPI. Thus, the directional system would be too far from the bit to be effective

As no directional tool and no MWD system will be implemented in the BHA, it will be necessary to run a gyroscope on wireline in the drill string before tripping out of the hole in order to check the bottom hole location. This measurement will help to determine the efficiency of the BHA. Thus, a UBHO (Universal Bottom Hole Orietation) sub will be integrated in the BHA above the stabilizer. This acts as a landing sub for the gyro to seat in when it is run in on the wireline.

The BHA will be composed of the following elements:

5” DP from surface

7 x 5” HWDP, 64.4m length

6 ¾” Jar, 9.2m length

22 x 5” HWDP, 202.4m length.



4 x 6 ¼” DC, 36.8m length

UBHO Sub, 0.9m

8 3/8” String Stabiliser, 2.5m length

DPI collar (including drive mechanism), with a sleeve stabilizer, 6.5m length.

Bit – 0.35m length

The planned BHA is shown in Figure 16.

Figure 16 – Planned BHA fort the ThermoDrill system © RED, the drawings are not to scale

3.4 ThermoDrill BHA and specific elements connections

The following elements will use NC50 Box x Pin connection (pin downhole):

Drill pipes

HWDP

Hydraulic Jar

Drill collars

UBHO sub

Stabiliser

The connection will then change to 4 ½” REG Pin x Box (box downhole) from the DPI sub. The ThermoDrill BHA and specific elements connections are shown in Figure 17.



Figure 17 – Elements connections © RED

Connection DPI – ThermoBit

This special connection allows double flow (normal mud flow and high pressure mud flow from the DPI). The HP tube in the ThermoBit is aligned with the bit body center axis to facilitate reliable connection to the downhole pressure intensifier (DPI). The exact connection between the DPI and the ThermoBit will be set-up with the DPI design.

3.5 ThermoDrill mud system

3.5.1 ThermoDrill mud

The ThermoFluid developed by TUM consists of sepiolite, a natural magnesium silicate clay belonging to the group of phyllosilicates with the chemical formula of Si12Mg8O30(OH)6(OH2)4·8H2O. It forms needle like particles. The non-swelling needles can aggregate and associate to form a random network which is responsible for the viscosifying effect.

For comparison, a xanthan gum – based fluid which currently presents the state – of – the – art system for drilling geothermal wells was used. Xanthan gum is a completely water-soluble microbial biopolymer prepared via fermentation using the bacterial strain of Xanthomonas campestris. Sodium metabisulfite was added as an oxygen scavenger to decrease the oxidative degradation of xanthan gum at elevated temperatures.

The sepiolite based ThermoFluid is prepared by mixing the sepiolite with water. Salt is then added, and the drilling fluid is mixed again. The pH value is adjusted to ~10.5. The xanthan gum reference system is prepared by dissolving the biopolymer powder (“Satixane CX 90 T” from Cargill) at 400 rpm using a propeller type mixer for 1 hour and allowing the polymer to hydrate overnight at room temperature. Salt is then added while mixing for 1 h at 400 rpm. Sodium metabisulfite is used as an oxygen scavenger to decrease the rate of degradation of xanthan gum at elevated temperatures and the pH value is adjusted to ~10.5 using Na2CO3. When salts are added to the xanthan gum fluid, a defoamer is needed to reduce air entrainment.



Prior to measurement, the fluids are hot rolled for 16 h at the corresponding temperatures (27 to 150°C) to simulate the circulation and the aging in the borehole. Rheology, density and pH of the fluids were measured to compare their stability and rheological properties after prolonged exposure to high temperatures.

The systems can be prepared using three different commonly used salts to achieve a wanted fluid density of ~1.1 g/mL. The drilling fluids are adjusted to a pH of ~10.5 to minimize the potential for corrosion.

Figure 18 – Photos demonstrating the exceptional carrying capacity for solids of 1.5 wt.% sepiolite fluid holding 12.1 wt.% K2CO3 after 16 h of static aging

The sepiolite system shows the best performance. It possesses thermal stability at least up to 150 °C as it maintains a low plastic viscosity and high low shear rheology which indicates high carrying capacity and therefore good hole cleaning property, even at 150°C. The rheological properties are exceptional, regardless of the salt used for weighting, though it performed best with KCl. Besides the stability under circulating (dynamic) conditions, the ThermoFluid also exhibits exceptional carrying capacity under static conditions at temperatures up to 150°C (see photo in Figure 18). This further indicates its superior hole cleaning properties. Specifically devised experiments could demonstrate that the sepiolite fluid also retains its viscosity when measured at 150°C of actual temperature (Figure 19).

Figure 19 – Time-dependent yield point of the xanthan gum and sepiolite fluids holding 17.6 wt.% KCl, measured at 150 °C in the Brookfield rheometer



In comparison, the xanthan gum fluid shows much lower temperature stability (max ~ 120 °C) than the sepiolite system despite addition of sodium bisulfite as a temperature extender. It shows a very high salt tolerance, being compatible with high dosages of KCl, NaCl and K2CO3. Despite exhibiting still high rheological values after hot roll at temperatures up to 120 °C, its carrying capacity is significantly lower than that of the sepiolite system as its static carrying capacity is lost already at 70°C, even at a high xanthan gum dosage (Figure 20).

Figure 20 – Photos demonstrating the limited carrying capacity of 1.0 wt.% xanthan gum fluid holding 12.1 wt.% K2CO3 after 16 h of static aging

To conclude, the sepiolite drilling fluid shows excellent salt tolerance, shear-thinning rheology, high temperature stability and carrying capacity indicating that it can provide hole cleaning properties which are much superior over that of the xanthan gum fluid, thus allowing faster drilling. In addition, it possesses good Ca2+ tolerance, a low corrosion potential and attractive cost effectiveness.

3.5.2 Field tests mud

For the field tests it has been agreed within the consortium that the testing fluid will be the RED standard K2CO3-Polymer drilling fluid and not the sepiolite system. The reason is that the potentially formation damaging properties of the sepiolite mud are still unknown. The formation in the wells to be drilled are interbedded with shale formations clays or water sensitive formations above the granite, and this might lead to swelling of the formation and hole instability when using the sepiolite fluid. Furthermore, the K2CO3-Polymer fluid can be used also in the granite section, and no fluid exchange is necessary. And a fluid exchange in open holes are explicitly against the standard of well engineering and oil field practices, because this can lead to a collapse of the hole open hole section due to changes in the stress regime.

The RED standard K2CO3-Polymer drilling fluid consists of:

1. Drill water 2. Polyanionic cellulose for fluid loss control 3. Biopolymer for rheology 4. Potassium Carbonate for inhibition and weight control 5. Citric acid for pH adjustment



While drilling through reactive formation, some of these solids are incorporated into the filter cake and help to reduce API fluid loss. A concentration of 3-6% drill solids are usually acceptable in a K2CO3-Plymer drilling fluid.

The system key properties are as follows:

Rheology: Rheology control is done by the addition of Biopolymer. Proper low end rheology will ensure good cutting transportation.

Inhibition:

Inhibition is provided correctly adjusted K+ ion concentration. Monitor the condition of the cuttings at the shakers to ensure they are firm and dry inside. Sticky and balled-up cuttings may indicate insufficient inhibition.

Hole cleaning: A 6-RPM reading of 6 – 12 and a good flow rate will ensure effective hole cleaning.

pH: A pH range of 10.0 – 11.0 for this system is best and comes from the addition of Potassium Carbonate. If pH is higher, add citric acid to bring it back to the desired rang.

API fluid loss: A constant low API fluid loss, together with a thin and slick filter cake, indicates a properly formulated system.



4. ThermoDrill process and operations description

This section proposes a detailed description of the operations needed to operate the ThermoDrill system on-site.

4.1 ThermoDrill surface operation related to downhole equipment

Downhole equipment assembling

The ThermoDrill tools will arrive at location in two separate parts: Drill bit and DPI. The first procedure will be to measure the exact dimensions of these tools and produce a fishing diagram, as is standard practice for all tools and tubulars going downhole. This is so that in the event the drillstring parts in any way, an accurate record of the true dimensions of the parts to be fished from the hole is present on location.

The DPI will be the first part to be picked up to the rig floor, thread protectors removed, and hung off in the rotary table using collar slips and a dog collar for safety. A visual inspection will be made to check there is no debris in the top of the tool, which could cause it to fail. The UBHO sub will be torqued on top of the DPI, followed by the first drill collar. Rig tongs should be used for these operations and the connections torqued to the specified value for the connection type and collar size.

With the DPI sub in the derrick, the bit should be placed in the rotary table in the bit breaker. A visual inspection should be made inside the top connection of the bit to ensure it is clear from debris, with special attention paid to the UHP connection. The connection will be greased with pipe dope and the DPI sub lowered on top of it. This should be done slowly and with careful observation to ensure the upper and lower parts of the UHP connection are joined correctly and without damage to the edges. The string should then be picked up so the protector on the UHP nozzle can be removed for the surface function test.

The top drive system should be connected and the bit positioned at the rotary table for the surface function test. The pumps should be lined up to pump fresh water and slowly brought up to 100 lpm above the minimum required rate to drive the DPI and the flow path through both standard and UHP nozzles verified as clear. The pumps should then be stopped and the UHP nozzle covered with the rubber protector. The assembly is now ready to be run in hole.

RIH (Run In Hole) operations

During the trip in, the pumps should not be turned on above the minimum required rate for the DPI until 20 m from bottom unless critical to operations as this will activate the DPI and destroy the rubber protector over the UHP nozzle.

POOH (Pull out of hole) operations

Once drilling is completed, no special precautions are required during the trip out of hole until the bit is in previous casing. Unless critical, no circulation above the DPI minimum required rate should occur as this could cause jetting damage to the casing.

Once the tool is on surface, the DPI should be connected to the top drive and flushed through with clean water. The flow rate should be the same as the pre-run surface test. Once this is completed, the bit should be unscrewed, cleaned, thread protector put in place and graded for record. The DPI should then have the lower end thread protector screwed in and the collar is then ready to be laid down.



Normal drilling operations

No special operations related to the downhole equipment are required during ThermoDrill system operation. Special attention will be paid to following drilling parameters:

The torque and drag will be monitored in order to make sure that the well cleaning is sufficient.

The cuttings recovery at the surface will be monitored for the same reason (make sure that well cleaning is sufficient)

As there will be no direct indication at surface that the DPI is working, it should be inferred from the ROP against offset data.

Maintenance operations

The maintenance operations required by the DPI should be finalized when the design of the tool is finalized.

Concerning the ThermoDrill bit, no specific maintenance operations are required.

4.2 ThermoDrill surface operation related to mud

Mud preparation

Preparation of the ThermoDrill fluid follows the same procedures as described in section 2.5.

A sepiolite fluid will be prepared starting with filling sweet water (drinking water or drill water) into a mixing tank. To adjust pH and control the level of soluble calcium ions, sodium carbonate is added to the water through a mixing hopper. If a mud weight higher than 1,01 kg/lt is required, salt (KCl, NaCl) is mixed to the water. In case potassium carbonate is used, the treatment with sodium carbonate is not required. In this case the pH of the drilling fluid is adjusted after mixing potassium carbonate by additions of citric acid.

Once the salt is in solution and the pH is adjusted to 9.0 – 11.0, sepiolite is mixed to this solution. To ensure proper yielding of the product, a high shear mixer is required. The rheology of the fluid needs to be checked and depending on the result, additional products are added to reach the desired rheological values.

Figure 21 –Vortex shear mixer



Mud cleaning (filtering + solid control)

Because of the special requirements of the downhole equipment, the cleaning of the ThermoDrill fluid is extremely important. Therefore, the standard cleaning and separation equipment as described in section 2.5 needs to be improved by addition of the following components:

1.) Special designed hydro cyclones to remove hard and abrasive drill solids from a cut point of 74 microns down to 20 microns. The throughput for each hydro cyclone unit will be minimum two times the circulation volume.

Figure 22 – FlSmidth-Krebs

2.) The underflow of the hydro cyclones goes over a shaker dressed with > 250 mesh screens or alternatively goes into a high-speed centrifuge to remove ultra-fine solids (< 20 microns).

Figure 23 – High-speed centrifuge

3.) Together with the centrifuge, a floc-Unit for the addition of floc-polymer is used. This set up can reduce solids in the drilling fluid to a minimum level.



Figure 24 – Floculation unit (Source Sirius ES)

4.) Filtration Equipment

For further cleaning of the ThermoDrill fluid, different types of filtration equipment can be added to the standard SCE depending on the test run and the lifetime of the DPI and ThermoBit:

Duplex cartridge filter units with < 50-micron replaceable filter candles

Filter technology with self-cleaning filter cartridges

Figure 25 – Left: Duplex cartridge filter units (source Twin filters); right: Filter technology (source Lenzing filtration technology)

4.3 ThermoDrill drilling PFD (Process Flow Diagram)

The global ThermoDrill drilling process is very similar to a conventional drilling process (see section 2.6). The main difference on the process is constituted by additional mud cleaning equipment like filters on the mud loop, in order to achieve a “cleaner” mud in terms of low solids content and defined max. particle size distribution (PSD), in comparison to a conventional mud. The integration of these additional cleaning capacities is showed in Figure 26). As described in section 4.2, some components (hydrocyclone and centrifuges) would have different size and/or configurations. The additional filtering equipment will be integrated after the conventional mud cleaning system, before the active mud tank.



The following parameters should be specifically monitored when using or testing the ThermoDrill system:

Weight on Bit and Rotary speed: during the tests, these parameters should be kept very similar to the parameters used in a conventional drilling process of offset wells in order to be able to quantify the advantages of the ThermoDrill system.

The pump speed and stroke should also be kept similar than when using a conventional drilling system.

The ROP, of course, will be specifically monitored as a resulting parameter, allowing to quantify the advantages of the ThermoDrill system

Additionally, it is suggested to analyse the cutting size distribution which is in the mud injected into the well.

After the well has been drilled using a ThermoDrill system, a trajectory measurement should be done in order to check if any unexpected deviation of the well trajectory has been induced by the ThermoDrill system.

Standard drilling fluids parameter with particle size distribution or top cut screening of the mud from suction tank with e.g. 50 µm steel hand screen (needs to be defined)



Figure 26 – ThermoDrill drilling PFD



4.4 ThermoDrill drill site

The ThermoDrill drill site is quite similar to a conventional drill site. All elements that can be found on a conventional drill site will also take place on the ThermoDrill drill site: the rig, storage, cabins and facilities, water storage and mud preparation area.

The main difference is the additional space that is needed by the additional filtering and solid control process (see description in section 4.2). This additional space is estimated to 5 m x 10 m (see Figure 27 below).

This additional space is not very big, so it does not heavily influence the drill site overall design. Nevertheless, as the mud process is very sensitive in a well drilling process, the detailed design of the drill site has to take into account this additional space from the beginning in order to ensure a smooth mud cleaning loop.



Figure 27 – ThermoDrill drill site (source RAG, modified by ESG)

Additional space for filtering equipment



4.5 ThermoDrill HSE aspects

One of the most important activities during an integration plan is identifying and monitoring the HSE aspects to assure a proper risk management of the ThermoDrill concept/project. For that purpose, a HSE (Health, Safety and Environment) aspects and project risk study has been carried out for the ThermoDrill project.

Specifically, the following main tasks have been carried out:

A HAZID (HAZard IDentification) process for Health and Safety issues and

A life-cycle thinking approach: Life Cycle Assessment (LCA) for the Environmental impacts.

In one hand, in order to identify and analyze HSE aspects and project risks for ThermoDrill, a HAZID (HAZard IDentification) methodology was applied. HAZID (HAZard IDentification) is a formal, in-depth study to identify the hazards, risks and controls required in an operation or installation, and to assess the acceptability of such hazards, developing a semi quantitative risk assessment using a risk matrix considering both frequency and the severity of the consequences. It identifies the measures that must be adopted to reduce or eliminate all unacceptable risks, according to the defined criteria. HAZID studies provide a forum for people to use their experience and skills to assess ways in which hazards or operating problems might arise. It is a systematic approach, considering each system, mode of operation and type of hazard in turn, thereby minimising the chances of overlooking an incident.

The goals pursued within the ThermoDrill project are the following:

Utilization of combined experience of staff in a constructive way.

Early interaction between design and end user personnel.

Systematic approach for the identification of hazards and for minimizing risks.

Confirmation of equipment fitness for purpose

Reduction of commissioning and mobilization delays.

Finally, as outcomes, the main risk scenarios from HAZID Study that are considered specifics of this type of project are the following:

Risk of earthquake generation with damages to equipment and structures (rig). Possible damages to workers and population in the surroundings due to induced seismicity due to drilling operations.

Possible damages to electrical equipment and structures and risk of fire with possible damages to workers due to thunderstorms and lightning (climatic extremes).

Possible damages to workers by radioactive exposure due to drilling operations through rocks with radioactive characteristics.

H2S cloud formation with possible personal damages and fatalities of workers and population due to drilling operations.

Potential risk of fire and/or explosion with damages to workers and facilities due to accidental release of flammable/combustible substances.

Risk of Blowout generation (in case of uncontrolled kick) with damages to workers and property, due to mud weight increases, swabbing, failure to fill the hole often enough, etc.

In the other hand, the environmental benefits of the ThermoDrill process will be assessed by comparison of the “ThermoDrill case” with those obtained for “baseline case” (which represents the current technology used in deep well drilling).

For that purpose, a life-cycle thinking approach has been considered to analyse the different environmental impact categories within the drilling stage of geothermal power generation. This



study focuses on the drilling phase. The boundary limits of the case study are set considering the drilling phase from 2000 m to 5000 m depth (including activities upstream and downstream that may change as a result of ThermoDrill: drilling fluid production, bit manufacturing, wastes management, etc).

This analysis aims at evaluating the environmental impacts that may arise from the ThermoDrill project, so that potential impacts are identified and corresponding recommendations are provided and addressed within the rest of the deliverables.

LCA is a very useful methodology to systematically assess environmental impacts in a consistent way that ensures comparability with other alternative processes. But some environmental impacts are not included in the impact categories usually used in LCA studies.

The “baseline case” is based on Well Model TD-1 (included in deliverable 8.1), considering specific data of drilling hard crystalline rocks in the range 2000-5000 m depth, which are being provided by other partners in the Consortium.

Although the boundary limits of the ThermoDrill project considers the drilling phase from 2000 m to 5000 m depth, the success of ThermoDrill project may increase the application of deep geothermal energy, so that environmental analysis considers not only the activities directly related to the ThermoDrill project, but also a general overview of the rest of activities involved in deep geothermal energy projects, including operational phase. So, when determining the environmental criteria for process/project feasibility, following issues should also be considered

Potential impacts that may occur occasionally are:

Induced seismicity: may occur mainly during the stimulation phase, but it cannot be excluded that it may occur in the long term during the operational phase of EGS.

Induced seismicity may lead to social rejection and the failure of the project. So, assessment of risks of induced seismicity, monitoring and mitigation strategies are crucial for project development

Land subsidence: may occur in hydrothermal systems if geothermal fluid production rates are greater than recharge rates. Subsidence impacts are not expected for EGS

Radioactivity: when drilling geothermal wells, there is a risk of exposure to naturally occurring radioactive materials. This hazard can be regarded as low, but requires proper monitoring of drilling wastes and corresponding waste management plan should consider how to deal with wastes exceeding a certain radioactivity threshold. The other concern for radioactivity is the contamination of the fluid that runs through the rocks, but potential effects are minimized in EGS because of the closed loop system

Disturbance of wildlife habitat and vegetation

Noise pollution

Thermal pollution

Alterations in the landscape

According to preliminary LCA analysis, the energy use (electricity or diesel oil consumption) for drilling is the most relevant aspect to focus on. The reinforcing steel and cement used for the casing of the well are also relevant. The improvement of the technology due to the ThermoDrill project may lead to positive changes both in energy consumption and in the use of these two material categories. According to available information at this stage of the project, energy consumption is expected to be the main aspect to be assessed.



5. Simulated test run of the well operating conditions

5.1 Simulation description

In order to gain an overview about the anticipated loads, torque, pressures, pressure losses etc. as well as hole cleaning during all expected operating conditions during the field test simulations with Wellplan software packages from Halliburton Landmark were performed.

A stabilized rotary BHA was used during the planning in order to gain information for the test well.

The BHA will be composed of the following elements:

5” DP from surface ;

5 x 5” HWDP ;

6 ½” Jar ;

15 x 5” HWDP ;

3 x 6 ½” DC ;

UBHO Sub ;

8 3/8” String Stabiliser ;

1x 7” DC (will be later the position of the DPI) ;

Bit.

Figure 28 – Planned BHA



5.2 Borehole trajectory

The Figure 29 shows the planned borehole trajectory that has been assumed for the sake of the simulations.

Figure 29 – Planned well trajectory for simulations

The simulation well is planned vertical till 680 m MD. The 9 5/8”casing setting depth is planned to be at 550 m MD in the vertical section. From 680 m MD to about 880 m MD, the inclination will be built up with a dogleg of 3°/30 m to 20°. After the building section, the inclination will be held till to the end depth, which is assumed to be at 3145 m MD, 3000 m TVD.



5.3 Torque and Drag simulation

The input parameters for the Torque and Drag simulations are displayed in Table 1.

Input parameter 8 ½” stabilized rotary BHA

Calculation Depth 3.000 m MD

Weight on Bit (Rotary / Sliding Mode) 15 to / n.a.

Torque at Bit (Rotary / Sliding Mode) 4.000 Nm / n.a.

Friction Factors (Cased Hole / Open Hole) 0,3 / 0,4

Tripping (Speed / RPM) 18 m/min / 0 rpm

Table 1 – Input parameters for Torque & Drag Simulations

The general results of the T&D simulations are shown in Table 2. Figure 30, Figure 31, Figure 32 and Figure 33 show plots of the simulated effective tension, hook load, torque and stress during drilling.

Results 8 ½” stabilized rotary BHA

POOH (Tripping Out) 134 t

RIH (Tripping In) 95 t

Torque (Drilling) 17 385 Nm

Torque (Rotating Off Bottom) 15 175 Nm

Drag (Pick Up / Slack Off) 21 t / 17 t

Margin of Overpull @ 90% of Yield 63 t

Table 2 – T&D simulations results



Figure 30 – Effective Tension plot

Figure 31 – Hook load plot



Figure 32 – Torque plot

Figure 33 – Stress during drilling plot



5.4 Hydraulic simulation

Hydraulic simulations have been performed using the RED standard K2CO3-Polymer drilling fluid, which parameters are presented in Table 3.

Input parameters 8 ½” stabilized rotary BHA

Mud Weight 1,10 kg/l

Rheology (Fann Readings)

Θ600 rpm 63 cP

300 rpm 41 cP

200 rpm 30 cP

100 rpm 22 cP

3 rpm 8 cP

6 rpm 6 cP

Total Flow Area (TFA) 0,746 in² (3x 18/32 in standard nozzles)

ROP 10 m/h

Cuttings diameter 0,125 in

Cuttings density 2,5 kg/l

Rotary speed 80 RPM

Table 3 – Hydraulic simulations input parameters

The general results of the Hydraulic simulations are shown in Table 4. Figure 34, Figure 35, Figure 36 and Figure 37 show plots of the simulated effective tension, hook load, torque and stress during drilling.

Results 8 ½” stabilized rotary BHA

Hydraulic Horse Power per Inch² 2.2 @ 2 000 l/min

Minimum Flow Rate (to avoid hole cleaning issues) 1 040 l/min @ 10 m/h

Stand Pipe pressure @ 1 800 l/min @ 3 000 m MD 130 bar



Bit Nozzle Velocity 69.3 m/s

Table 4 – Hydraulic simulations results



Figure 34 – Minimum flow rate plot



Figure 35 – Circulation pressure plot

Figure 36 – Pump rate plot



Figure 37 – Component pressure losses



6. FMECA - Failure Mode, Effects an Criticality Analysis

6.1 Failure Mode, Effects and Criticality Analysis description

The FMECA is developed based on a well-defined operational context. It may be that some functions, failures or effects only occur, or occur in a different manner, in certain operational scenarios. The FMECA should clearly indicate when functions, failure modes or effects are dependent on specific circumstances, environments, or mission phases.

The FMECA starts with the equipment partition. The partition shows the relationship of each item to other items and to higher or lower levels of indenture. It is important that, prior to beginning the development of the FMECA, the ground rules and assumptions discussed are established and well understood.

6.2 Methodology

The FMECA shall be performed according the following steps:

1. Describe the equipment to be analysed, by providing: a) functional descriptions, b) interfaces, c) interrelationships and interdependencies of the items which constitute the

product, d) operational modes, e) mission phases.

2. Identify all potential failure modes for each item and investigate their effect on the item under analysis and on the equipment and operation to be studied.

3. Assume that each single item failure is the only failure in the equipment. 4. Evaluate each failure mode in terms of the worst potential consequences and assign a

severity category. 5. Identify failure detection methods. 6. Identify existing preventive or compensating provisions for each failure mode. 7. Provide for identified critical risks corrective design or other actions (such as operator

actions) necessary to eliminate the failure, or to mitigate or to control the risk. 8. Document the analysis and summarize the results and the problems that cannot be

solved by the corrective actions. 9. Record all critical items into a dedicated table as an input to the overall project critical

item list.

6.2.1 Function

A function is the intended purpose of an item as described by a required standard of performance. It is not necessarily what the item is capable of doing. A complete function description should include any specific performance limits (upper and/or lower bounds).

Although most equipment is designed to perform a specific or single function, many systems may perform multiple functions or have secondary functions. Some functions are "demand" driven, while others operate continuously. Care must be taken to ensure functions are not overlooked, and that the function statement is clear, including any operating context notations.

Virtually all systems have primary and secondary functions. Secondary functions are often less obvious than the primary function, but may have more severe consequences if they fail.

Functions should not be combined if failure consequences are different for each function.



6.2.2 Functional Failure

A functional failure is defined as the inability of an item to perform a specific function within the specified limits. A functional failure may not necessarily be a complete loss of the function.

Proper functional failure descriptions are based on the function description. Functional failures will likely result in either reduced performance or total loss of the system. Separate functional failures should be listed where the effects of less than total loss of the function are different from total loss.

Information for determining functional failures can be drawn from sources such as maintenance manuals, drawings, and discussions with design engineers, operators and maintainers.

Proper functional failure descriptions include parameters such as upper and lower limits of the failure regime, if different than the function description.

6.2.3 Failure Mode

A failure mode is a specific physical condition that can result in a functional failure. The failure mode statement should include a description of the failure mechanism (e.g. fatigue) in addition to the specific condition whenever possible.

Failure mode statements should be as descriptive as possible to eliminate confusion over what the failure mode is and where it occurs, to avoid listing redundant failure modes, to readily relate in-service data to the failure mode, and to aid in the development of the appropriate failure management strategy. A lot of effort could be expended in imagining all the ways something might fail, however, only failure modes that are “reasonable” should be identified.

Failure mode identification on new designs is more difficult. Failure modes have to be inferred from knowledge of the hardware design, general knowledge of how things fail, and experience with similar equipment in similar applications. Data sources will include technical data (publications, drawings) and failure data sources mentioned above for similar equipment in similar usage. The context in which the equipment is operated should be carefully considered.



Table 5 – Failure modes examples

6.2.4 Failure Cause

A failure cause is defined as the presumed cause/s associated to a given failure mode.



Table 6 – Failure causes examples

6.2.5 Failure Effects

Failure effect is described as the result of a functional failure on surrounding items, the functional capability of the end item, and hazards to personnel and the environment. In other words, it is the impact that a functional failure has on the item under analysis, the surrounding environment, and the functional capability of the end item.

Failure effects should describe any physical damage, including both primary and secondary damage that may occur, and any actions required to restore system function. They should identify the effects on personnel, environment and system safety, the drilling equipment and schedule, the physical asset(s), and include any unplanned operator or maintainer actions required to restore functional capability.

Failure effects are described as if no preventive maintenance task is in place to prevent or find the failure and will be used in the process to determine the consequences of failures and to assess the severity.



Often, effects vary under different process phases and this must be carefully evaluated and documented. In these cases, it may be necessary to list different effects based on the process scenario.

6.2.6 Failure Detection

Failure detection is the means by which functional failures become evident and how their failure modes are identified.

The methods used to detect functional failures will vary from failure mode to failure mode due to the different secondary damage that can be caused by each failure mode. They include visual warning signals and operational effects (e.g., pressures, flows, vibrations, noises).

Table 7 – Detection methods examples

6.2.7 Severity Classifications

Severity classifications are assigned to failure modes based on the impacts of their failure effects at the end level. Classifying failure modes in this manner provides a primary source for



determining the priority under which each should be addressed, and may also be used to establish the acceptable probability level for failure modes based on categories of effects.

For the ThermoDrill project a risk matrix classification system has been defined considering a Failure-consequence classification and a Probability classification. Both concepts have been adapted to the specific conditions of the project.

For that purpose, the Failure-consequence classification shown in the Table (extracted from ISO 14224) has been rescaled to the following cost references:

1. Minor: less than 25.000 EUR. It corresponds with the scenario of tripping out the drill string and the BHA and fixing, setting or replacing items.

2. Moderate: less than 100.000 EUR and more than 25.000 EUR 3. Severe: less than 300.000 EUR and more than 100.000 EUR 4. Catastrophic: more than 300.000 EUR. It corresponds with the scenario of losing the

system, fishing it from the hole and cementing.

Consequence level SN Description

Catastrophic 4

more than 300.000 EUR. It corresponds with the scenario of losing the system, fishing it from the hole and cementing

Severe 3 less than 300.000 EUR and more than 100.000 EUR

Moderate 2 less than 100.000 EUR and more than 25.000 EUR

Minor 1

less than 25.000 EUR. It corresponds with the scenario of tripping out the drill string and the BHA and fixing, setting or replacing items

Table 8 – Severity classification

Then, a probability classification has been defined considering the expected lifespan of a normal drill bit (around 40 working hours) and the expected lifespan of the ThermoDrill bit (around 80 working hours).

Probability level PN Description It might happen

in…

Frequent 5 Occurs often, continuously experienced

less than 20h

Likely 4 Occurs several times around 20h

Occasional 3 Occurs sporadically around 40h

Seldom 2 Unlikely, but could occur at some time

around 80h

Unlikely 1 It is not expected to

occur more than 80h

Table 9 – Probability classification

The combination of both concepts can be seen in the following risk matrix.



Severity category

SN

Probability level

PN

1 2 3 4 5

Catastrophic 4 4 8 12 16 20

Severe 3 3 6 9 12 15

Moderate 2 2 4 6 8 10

Minor 1 1 2 3 4 5

Table 10 – Criticality risk matrix

6.3 Assumptions

The FMECA for ThermoDrill project has been performed according to the following assumptions:

1. The analysis is developed for the different equipment parts, it means those equipment parts that are specific or different from the conventional drilling techniques.

2. The analysis is developed at the equipment level, considering the failure of the components.

3. For the different equipment parts to be considered the analysis includes the components whose failure has an impact in the functionality of the equipment.

6.4 ThermoDrill taxonomy and equipment partition

6.4.1 Taxonomy

The ThermoDrill project facilities and equipment components can be classified according to the taxonomy displayed in Figure 38.



Figure 38 – ThermoDrill project taxonomy

For the levels of the equipment units, the taxonomy for the ThermoDrill drilling facilities is the following:

Section/system Equipment unit

1.Structural 1.1. Derrick

2.Rotative power

2.1. Turntable

2.2. Kelly

2.3. Engines

3.Mud treatment

3.1. Mud line

3.2. Shale shaker

3.3. Waste storage

3.4. Mud Tank

3.5. Mud chemical dosing

4.Fluid pumping

4.1. Fluid pumping system

4.2. Fluid filtering system

4.3. Stand pipe

5.Well equipment 5.1. Casings

5.2. Blowout preventer

6.Well drilling

6.1. Drill pipe

6.2. Drill Collar

6.3. Downhole pressure intensifier

6.4. Drill Bit

6.5. Drilling/jetting fluid

Table 11 – ThermoDrill specific equipment unit details

Geothermal

Geothermal well drilling

Thermodrill drilling installation

Thermodrill drilling plant

Structural Rotative power

Mud treatment

Fluid pumping

Well equip.

Well drilling



As already indicated in the paragraph 6.3, the FMECA analysis is developed for the different equipment units, it means those equipment units that are specific or different from the conventional drilling techniques. Those different equipment units are the following:

6.3. Downhole pressure intensifier (DPI)

6.4. Drill bit

6.5. Drilling/jetting fluid

For those different equipment units, two further partitions are developed until the component level. For the FMECA analysis it is necessary to develop the taxonomy until the component level, because is the lowest level to be used in the analysis.

6.4.2 FMECA work frame

The FMECA has been performed on each component presented in the paragraph 6.4.1 using the framework presented in Table 12.

Table 12 – FMECA framework

6.5 ThermoDrill FMECA results

The ThermoDrill FMECA has been carried out within WP6. The results have a strong impact on the DPI Design. Therefore, the results of the FMECA are confidential and are reported in deliverable D3.4.

Failure Modes Effects and Criticality Analysis (FMECA)

Equipment: Project: System/Subsystem/Equipment:

Prepared by: Approved by: Date:

Document: Issue: Page of

Component Function Failure mode

Failure cause

Phase/ Operation

mode

Failure effects a. Local effects b. End effects

Severity Failure detection

method/ observable symptoms

Compensation

provisions

Severity Sn

Probabability PN

Criticality CN

Corrective

actions

Remarks



7. SWOT analysis

SWOT is the acronym of Strengths Weaknesses Opportunities and Threats. The SWOT analysis is a widely used decision-making and strategic tool to evaluate the principal internal and external parameters that are favourable and unfavourable to achieve an objective. It can be carried out to evaluate a company, a product, a place, an industry, or a person.

More practically, the SWOT analysis details two internal parameters: the Strengths and the Weaknesses, and two external parameters: the Opportunities and Threats.

Strengths: characteristics of the business or project that give it an advantage over others.

Weaknesses: characteristics of the business that place the business or project at a disadvantage relative to others.

Opportunities: elements in the environment that the business or project could exploit to its advantage.

Threats: elements in the environment that could cause trouble for the business or project.

For the ThermoDrill project, a SWOT analysis matrix has been constructed and is presented in the Table 13.

Table 13: SWOT analysis matrix for the ThermoDrill project.

Inte

rnal

Strengths Weaknesses

Innovative technology No directional drilling

Drill hard and hot rocks faster: Larger filtration system:

- reduction of rig time - place and costs issues

- reduction of acoustic emissions Reliability to be proved:

- reduction of carbon emissions - obstruction of nozzles (HP and LP)

Increase of drill bit lifespan : - efficiency dependent on stand-off distance

- less trips Complexity increase:

- savings - risk of failure or dysfunction

- less wear - development necessary

Conventional drilling still possible without HP system - material overcost

Better filtration system Overall efficiency/rentability to be proved

Better hole cleaning due to more efficient mud system

Less wear on entire drill string

Exte

rnal

Opportunities Threats

Market of high temperature and hard rock drilling Small application field (scope)

Potential market of soft rock Low price of conventional energy

Encourage deep geothermal projects Development of other alternative drilling technologies

R&D prospects (i.e. directional drilling) Lack of development of deep geothermal projects

Patent deposition Discouraging complexity



7.1 Strengths

The strengths linked to the ThermoDrill technology are listed and detailed below:

The concept and the technology are innovative. ThermoDrill is based on conventional drilling techniques and jetting tests performed in the past for the oil and gas industry, but it has never been entirely developed for very deep and hot hard rocks. Every part of the technology will benefit from the latest techniques, technologies and state of the art manufacturing.

The increase of drilling speed linked with the ThermoDrill technology will have many helpful impacts on the ecology and economy of a deep drilling project. The high drilling speed will lead to a lower rig time, which infers lower costs, lower acoustic emissions and lower carbon emissions.

As the drilling process will be shared by conventional roller cone technology and jetting technology, the roller cone should have a longer lifespan. This will lead to savings, the reduction of the trips (tool replacements) and wear.

The ThermoDrill technology is not a replacement of the existing one. It means that conventional rotary drilling is still possible if needed or if the ThermoDrill high pressure system fails.

The ThermoDrill technology needs a better filtration system to increase the lifespan of the high pressure components. This filtration will also be profitable for the rest of the drilling process and technology, increasing for example the quality of hole cleaning due to a more efficient mud system.

The filtration, the mud quality and the reduction of the number of trips will lead to an overall reduction of wear on the entire drill string.

7.2 Weaknesses

The weaknesses linked to the ThermoDrill technology are listed and detailed below:

Today, the development of high pressure parts does not allow for directional drilling components in the BHA. This point can be a prospect of development but is currently an important limitation of the technology.

The better filtration system needed to preserve the high pressure components is money and rig site space consuming.

The system still has to prove its reliability. It has not been completed and never been tested at the time of this report and the obstruction of nozzles, or issues with the standoff distance could lead to a loss of efficiency.

The whole system is more complex than a conventional one. It will increase the risk of failure or dysfunction. All the ThermoDrill parts are not designed and manufactured yet, so the use of the technology will need further developments and the different ThermoDrill equipment parts will cause extra costs.

The project infers savings and extra costs that are not yet clearly known regarding that the potential efficiency of the ThermoDrill technology is still to be proved.

7.3 Opportunities

The opportunities linked to the ThermoDrill technology are listed and detailed below:

The current development of deep geothermal is promising and the hard rock and high temperature drilling market can help the development of the ThermoDrill technology.

The laboratory tests showed a very high effectivity of the jetting on soft rocks. The market of soft rocks drilling could also be targeted by ThermoDrill.



The faster and cheaper deep hard rock drilling will boost deep geothermal projects and increase the pertinence of the technology.

The proof of concept of this new technology will boost the R&D on the topic, e.g. for directional drilling.

The final technology can lead to the deposit of a patent.

7.4 Threats

The threats linked to the ThermoDrill technology are listed and detailed below:

The application field of the ThermoDrill technology is currently small.

The low prices of conventional energy are slowing down the deep geothermal market, reducing the potential use of the ThermoDrill technology.

Many other new drilling technologies are in development today and those technologies could prove to be more attractive for hard rock drilling.

Deep geothermal projects develop slowly and the lack of deep geothermal projects can compromise the profitability of ThermoDrill developments.

The drilling industry is already complex and drilling operations are sometimes risky. The ThermoDrill technology increases the complexity of the drilling techniques which can be prohibitive for drilling companies.

7.5 SWOT analysis results

The main identified weaknesses are related to reliability, complexity and directional drilling issues.

Firstly, the reliability issues will be clearly identified during the testing phase of the project, and further developments and learning phases will help to minimise these weaknesses.

Secondly, the complexity of the technology must be put into perspective. Drilling itself is already a very complex process and the ThermoDrill technology will just be a small part of it. Figure 27 shows that the final impact of ThermoDrill equipment on the drill site is quite small with respect to the whole drilling facilities, so its integration seems manageable.

The main threats don’t really depend on ThermoDrill characteristics, which make them difficult to estimate. The success of the final onsite test of the ThermoDrill prototype will have a decisive impact on its chance to be more industrially developed in the future.

As a result, the strengths and opportunities are promising, and most weaknesses are manageable or could be overcome with further development. The technology is supposed to enhance the drilling capacities in terms of drilling speed and equipment lifespan, which most probably will be very welcomed by the hard rock but also soft rock drilling markets.



8. Conclusions

This integration plan gives an overview of the entire ThermoDrill process. It focusses on the connections between the different system parts, on the integration of the ThermoDrill process in a conventional drilling process and on the specific additional operations needed by the ThermoDrill system.

Concerning the integration of the different system parts and the connections between these elements, the following conclusions can be delivered:

A simple BHA (Bottom Hole Assembly) should be able to run the ThermoDrill system.

The main difficulty identified in the connections is the connection between the Downhole Pressure Intensifier and the Bit itself. As of today, the exact design of this connection has not been defined.

Concerning the integration of the ThermoDrill process in a conventional drilling process, the following conclusions can be delivered:

The only additional processes needed by the ThermoDrill process are located in the mud cleaning process (mainly additional filtering).

The integration of these additional cleaning process on a drill site is not problematic, as the additional space estimated is limited (around 50 m2).

Concerning the specific operations needed by the ThermoDrill system, the following conclusions can be delivered:

The ThermoDrill system should be easy to implement on site, as the identified specific operation regarding the ThermoDrill system maintenance or operation mode are limited.

Few additional parameters need to be monitored when operating a ThermoDrill system (it is suggested to monitor the particle size distribution of the mud injected into the well).

The reliability of the additional filtering process and the operations needed by the maintenance of this process is still unknown and will be quantified during the tests.

As a result, one of the main threats identified by the SWOT analysis, consisting of a drastic increase of the drilling complexity because of the ThermoDrill system on-site operation, could be kept at an acceptable level through the proposed integration plan.



9. References

Darley 1988 H. C. H. Darley, G. R. Gray, “Composition and Properties of Drilling

and Completion Fluids” Gulf Publishing Company, 1988.

IADC, 2015 International Association of Drilling Contractors IADC Drilling Manual,

12th edition, IADC 2015



10. Glossary

acidizing The pumping of acid into the wellbore to remove near-well formation damage and other damaging substances. This procedure commonly enhances production by increasing the effective well radius. When performed at pressures above the pressure required to fracture the formation, the procedure is often referred to as acid fracturing.2

air drilling A drilling technique whereby gases (typically compressed air or nitrogen) are used to cool the drill bit and lift cuttings out of the wellbore, instead of the more conventional use of liquids.2

annulus The space around a pipe in a wellbore.

API American Petroleum Institute. A trade association and standards organization that represents the interests of the oil and gas industry. It offers publications regarding standards, recommended practices, and other industry related information.3

BHA Bottom-Hole Assembly. An assembly composed of the bit, stabilizers, reamers, drill collars, various types of subs, etc., that is connected to the bottom of a string of drillpipe.

BHT Bottom-Hole Temperature. The temperature measured in the borehole at total depth.

BHCT The temperature of the circulating fluid (air, mud, cement or water) at the bottom of the wellbore after several hours of circulation.2

BHST Bottom hole static temperature. The temperature of the undisturbed formation at the final depth in a well. The formation cools during drilling and most of the cooling dissipates after about 24 hours of static conditions, although it is theoretically impossible for the temperature to return to undisturbed conditions. This temperature is measured under static conditions after sufficient time has elapsed to negate any effects from circulating fluids.2

bit The tool used to crush or cut rock. Everything on a drilling rig directly or indirectly assists the bit in crushing or cutting the rock. The bit is on the bottom of the drill string and must be changed when it becomes excessively dull or stops making progress. Most bits work by scraping or crushing the rock, or both, usually as part of a rotational motion. Some bits, known as hammer bits, pound the rock vertically in much the same fashion as a construction site air hammer.2

bit record A report that lists each bit used during a drilling operation.3

BOP Blowout Preventer. A large valve at the top of a well that may be closed if the drilling crew loses control of formation fluids.2

brine A geothermal solution containing appreciable amounts of sodium chloride or other salts.4

BSCW Basic support for cooperate work. The shared-workspace-system used in ThermoDrill.

casing Steel pipe placed in an well to prevent the wall of the hole from caving in, to prevent movement of fluids from one formation to another and to aid in well control.3

casing shoe A short, heavy, cylindrical section of steel filled with concrete and rounded at the bottom, which is placed at the end of the casing string. It prevents the casing from snagging on irregularities in the borehole as it is lowered.3

CBL Cement Bond Log. An acoustic survey or sonic-logging method that records the quality or hardness of cement used in the annulus to bond the casing and the formation. Casing that is well bonded to the formation transmits an acoustic signal quickly; poorly bonded casing transmits a signal slowly.3

2 Schlumberger Oilfield Glossary. URL: http://www.glossary.oilfield.slb.com. 19.10.2015. 3 Oil and Gas Well Drilling and Servicing eTool. URL: https://www.osha.gov/SLTC/etools/oilandgas/glossary_of_terms/glossary_of_terms_a.html 4 DOE Geothermal Glossary. URL: http://energy.gov/eere/geothermal/geothermal-glossary



CEL Coupled Eulerian-Lagrangian, a numerical combining Eulerain and Lagrangian formulations.

CDP Concrete Damaged Plasticity, a damage model for concrete and other quasi-brittle materials.

CET Cement Evaluation Tools. Cement evaluation tools measure the bond between the casing and the cement placed in the wellbore annulus between the casing and wellbore. This real-time measurement is made with acoustic sonic or ultrasonic tools. Hydraulic isolation between reservoir layers is essential to avoid potential reservoir problems such as crossflow between reservoir zones behind the casing. The detection of poor cement, or the absence of cement, makes it possible to conduct remedial action before the well is completed to avoid potential production problems and their associated costs.5

circulation loss

The loss of drilling fluid to a formation, usually caused when the hydrostatic head pressure of the column of drilling fluid exceeds the formation pressure. This loss of fluid may be loosely classified as seepage losses, partial losses or catastrophic losses, each of which is handled differently depending on the risk to the rig and personnel and the economics of the drilling fluid and each possible solution.2

CT Coiled Tubing. A long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 610 to 4,570 m or greater length.2

CTU Coiled Tubing Unit.

coring The process of cutting a vertical, cylindrical sample of the formations encountered as a well is drilled.3

criticality Combined measure of the severity of a failure mode and its probability of occurrence

cuttings The fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried cuttings samples are analyzed by geologists to obtain information about the formations drilled.3

DC Drill Collar. Thick walled pipe or tube designed to provide stiffness and concentration of weight at the bit.6

DD Directional Drilling. The intentional deviation of a wellbore from the path it would naturally take. This is accomplished through the use of whipstocks, bottomhole assembly (BHA) configurations, instruments to measure the path of the wellbore in three-dimensional space, data links to communicate measurements taken downhole to the surface, mud motors and special BHA components and drill bits, including rotary steerable systems, and drill bits. The directional driller also exploits drilling parameters such as weight on bit and rotary speed to deflect the bit away from the axis of the existing wellbore.2

DDR Daily Drilling Report. A record made each day of the operations on a working drilling rig and, traditionally, phoned, faxed, emailed, or radioed into the office of the drilling company and possibly the operator every morning.3

dogleg The abrupt change in direction in the wellbore, frequently resulting in the formation of a keyseat.

DP Drillpipe. The heavy seamless tubing used to rotate the bit and circulate the drilling fluid. Joints of pipe are generally approximately 9 m (30 feet) long are coupled together by means of tool joints.3

drilling mud Drilling Fluids. Any of a number of liquid and gaseous fluids and mixtures of fluids and solids (as solid suspensions, mixtures and emulsions of liquids, gases and solids) used in operations to drill boreholes into the earth. One classification scheme is based only on the mud composition by singling out the component that clearly defines the

5 Schlumberger, URL: hht://www.slb.com/services/drilling/cementing/cement_evaluation.aspx 6 IADC Drilling Lexicon. URL: http://www.iadclexicon.org

http://www.iadclexicon.org/drill-collar/



function and performance of the fluid: (1) water-base, (2) non-water-base and (3) gaseous (pneumatic).2

drilling rig Equipment and machinery assembled primarily for the purpose of drilling or boring a hole in the ground.6

drillstring The drillstring is the mechanical assemblage connecting the rotary drive system of the drilling rig on the surface to the drilling bit. It includes drill pipe and drill collars as well as ancillary equipment like stabilizers, shock absorbers and crossover subs.7

effect Consequence of an assumed item failure mode on the operation, function, or status of the product under investigation and its interfaces

EGS Rock fracturing, water injection, and water circulation technologies to sweep heat from the unproductive areas of existing geothermal fields or new fields lacking sufficient production capacity.4

elastic deformation

A temporary change in shape caused by applied stress. The change in shape is not permanent and the initial shape is completely recovered once the stress is removed.

EOS Equation Of State, a thermodynamic equation relating state variables which describe the state of matter under a given set of physical conditions.

ESP Electric Submersible Pump.

Failure cause Presumed causes associated to a given failure mode

Failure effects Consequence of an assumed item failure mode on the operation, function , or status of the item

FMEA Failure Mode and Effects Analysis: Analysis by which each potential failure mode in a product (or function or process) is analysed to determine its effects

FMECA Failure Mode, Effects and Criticality Analysis: FMEA extended to classify potential failure modes according to their criticality

Failure propagation

Physical or logical event caused by failure within a product which can lead to failure(s) of products outside the boundaries of the product under analysis.

filter cake The residue deposited on a permeable medium when a slurry, such as a drilling fluid, is forced against the medium under a pressure. Filtrate is the liquid that passes through the medium, leaving the cake on the medium. Drilling muds are tested to determine filtration rate and filter-cake properties.2

FEA Finite Element Analysis, an analysis using Final Elements Method.

FEM Finite Element Method, a numerical method for solving engineering and mathematical physics problems. It is typically used in structural analysis, heat transfer, fluid flow, mass transport, etc.

fish Anything left in a wellbore. It does not matter whether the fish consists of junk metal, a hand tool, a length of drillpipe or drill collars, or an expensive MWD and directional drilling package. Once the component is lost, it is properly referred to as simply "the fish." Typically, anything put into the hole is accurately measured and sketched, so that appropriate fishing tools can be selected if the item must be fished out of the hole.2

FIT Formation Integrity or Formation Competency Test. Application of pressure by superimposing a surface pressure on a fluid column in order to determine ability of a subsurface zone to withstand a certain hydrostatic pressure.6

fluid loss The leakage of the liquid phase of drilling fluid, slurry or treatment fluid containing solid particles into the formation matrix.2

formation pressure

The force exerted by fluids or gas in a formation, recorded in the hole at the level of the formation with the well shut in. Also called reservoir pressure or shut-in bottomhole pressure.2

7 Nguyen, Jean-Paul (1996): Drilling. Oilfield and Gas Field Development Techniques. Paris (Editions Technip).



fracturing A method of breaking down the formation by pumping fluid at very high pressures.6

functional description

Narrative description of the product functions, and of each lower level function considered in the analysis, to a depth sufficient to provide an understanding of the product and of the analysis

geothermal gradient

The rate of increase in temperature per unit depth in the Earth. Although the geothermal gradient varies from place to place, it averages 25 to 30 °C/km. Temperature gradients sometimes increase dramatically around volcanic areas. It is particularly important for drilling fluids engineers to know the geothermal gradient in an area when they are designing a deep well. The downhole temperature can be calculated by adding the surface temperature to the product of the depth and the geothermal gradient.2

GL Ground Level

G&G Geology and Geophysics.

GR Gamma-Ray. High-energy, short wavelength, electromagnetic radiation emitted by a nucleus, which is penetrating and is best attenuated by dense material like lead or tungsten. The energy of gamma-rays is usually between 0,010 MeV and 10 MeV.6

HDR The so-called Hot Dry Rock research aimed ultimately at extracting useful heat from rock formations which possess insufficient natural permeability to allow extraction of heated natural groundwater at the required rate.8

hook load The weight of the drill stem and associated components that are suspended from the hook.2

HTHP High temperature and high pressure.

HWDP Heavy-Weight Drill Pipe. Pipe with thick wall used in transition zone to minimize fatigue and as bit weight in directional wells.6

hydrostatic pressure

The normal, predicted pressure for a given depth, or the pressure exerted per unit area by a column of freshwater from sea level to a given depth.2

IADC International Association of Drilling Contractors. A trade association that represents the interests of members of the drilling segment of the oil and gas industry. It offers publications regarding recommended industry practices and training materials.2

induced seismicity

Induced seismicity is earthquake activity resulting from human activity that causes a rate of energy release, or seismicity, which would be expected beyond the normal level of historical seismic activity. In addition to the subsurface stresses, fluid pressures play a key role in causing seismicity.9

injection The process of returning spent geothermal fluids to the subsurface. Sometimes referred to as reinjection.4

jet nozzle The passageway through jet bits that causes the drilling fluid to be ejected from the bit at high velocity. 2 The purpose of fluid streams is to keep the bit cones clean, cool down the bearings and to sweep formation cuttings towards the annulus.

kelly The square or hexagonal shaped steel pipe connecting the swivel to the drill string. The kelly moves through the rotary table and transmits torque to the drill string.6

keyseat A small-diameter channel worn into the side of a larger diameter wellbore. This can be the result of a sharp change in direction of the wellbore (a dogleg), or if a hard formation ledge is left between softer formations that enlarge over time. In either case, the diameter of the channel is typically similar to the diameter of the drillpipe. When larger diameter drilling tools such as tool joints, drill collars, stabilizers, and bits are pulled into the channel, their larger diameters will not pass and the larger diameter tools may become stuck in the keyseat.2

8 Garnish, John D. (1991): Research and development on geothermal energy in Europe. Proceedings of the Ussher Society, 7,

309-315. 9 Lawrence Berkeley National Library. Induced Seismicity. URL: http://esd1.lbl.gov/research/projects/induced_seismicity/



LCA Life cycle analysis is a systematic set of procedures for compiling and examining the inputs and outputs of materials and energy and the associated environmental impacts directly attributable to the functioning of a product or service throughout its life cycle. This goal is accomplished by taking the following steps: compiling an inventory of relevant inputs and outputs of a system, evaluating the potential impacts associated with those inputs and outputs and interpreting the results of the inventory and impact phases in relation to the objectives of the study.10

LCM Lost Circulation Material. Solid material intentionally introduced into a mud system to reduce and eventually prevent the flow of drilling fluid into a weak, fractured or vugular formation. This material is generally fibrous or plate-like in nature, as suppliers attempt to design slurries that will efficiently bridge over and seal loss zones. In addition, popular lost circulation materials are low-cost waste products from the food processing or chemical manufacturing industries. Examples of lost circulation material include ground peanut shells, mica, cellophane, walnut shells, calcium carbonate, plant fibers, cottonseed hulls, ground rubber, and polymeric materials.2

LOT Leakoff Test. A test to determine the strength or fracture pressure of the open formation, usually conducted immediately after drilling below a new casing shoe. During the test, the well is shut in and fluid is pumped into the wellbore to gradually increase the pressure that the formation experiences. At some pressure, fluid will enter the formation, or leak off, either moving through permeable paths in the rock or by creating a space by fracturing the rock. The results of the leakoff test dictate the maximum pressure or mud weight that may be applied to the well during drilling operations. To maintain a small safety factor to permit safe well control operations, the maximum operating pressure is usually slightly below the leakoff test result.2

lubricant A mud additive for lowering torque (rotary friction) and drag (axial friction) in the wellbore and to lubricate bit bearings if not sealed. Lubricants may be solids, such as plastic beads, glass beads, nut hulls and graphite, or liquids, such as oils, synthetic fluids, glycols, modified vegetable oils, fatty-acid soaps and surfactants.2

LWD Logging While Drilling. The measurement of formation properties during the excavation of the hole, or shortly thereafter, through the use of tools integrated into the bottomhole assembly.2

MD Measured Depth. The length of the wellbore, as if determined by a measuring stick. This measurement differs from the true vertical depth of the well in all but vertical wells. Since the wellbore cannot be physically measured from end to end, the lengths of individual joints of drillpipe, drill collars and other drillstring elements are measured with a steel tape measure and added together. Importantly, the pipe is measured while in the derrick or lying on a pipe rack, in an untensioned, unstressed state. When the pipe is screwed together and put into the wellbore, it stretches under its own weight and that of the bottomhole assembly. Although this fact is well established, it is not taken into account when reporting the well depth. Hence, in virtually all cases, the actual wellbore is slightly deeper than the reported depth.2

mud additive A material added to a drilling fluid to perform one or more specific functions, such as a weighting agent, viscosifier or lubricant.2

mud circulation

The movement of drilling fluid out of the mud pits, down the drill stem, up the annulus, and back to the mud pits.2

mud weight A measure of the density of a drilling fluid expressed as pounds per gallon, pounds per cubic foot, or kilograms per cubic meter. Mud weight is directly related to the amount of pressure the column of drilling mud exerts at the bottom of the hole.2

MUL Montanuniversitaet Leoben.

multilateral Pertaining to a well that has more than one branch radiating from the main borehole.2

10 Madu, Christian (2001): Handbook of environmentally conscious manufacturing. Springer Science-Business Media, New

York.



NDT Non-Destructive Test. Test used to detect internal, surface and concealed defects or imperfections in materials, using techniques that do not damage or destroy the items being tested.6

O&M Operations and Maintenance.

PAC Polyanionic cellulose. A cellulose derivative similar in structure, properties and usage in drilling fluids to carboxymethylcellulose. PAC is considered to be a premium product because it typically has a higher degree of carboxymethyl substitution and contains less residual NaCl than technical grade carboxymethylcellulose, although some PACs contain considerable NaCl.2

PDC bit A drilling tool that uses polycrystalline diamond compact (PDC) cutters to shear rock with a continuous scraping motion. These cutters are synthetic diamond disks about 1/8 inch thick and about 1/2 to 1 inch in diameter.2

permeability The capacity of a substance (such as rock) to transmit a fluid. The degree of permeability depends on the number, size, and shape of the pores and/or fractures in the rock and their interconnections. It is measured by the time it takes a fluid of standard viscosity to move a given distance. The unit of permeability is the Darcy.4

porosity The ratio of the aggregate volume of pore spaces in rock or soil to its total volume, usually stated as a percent.4

protection device

Device designated to perform a specific protective function

reamer A tool used in drilling to smooth the wall of a well, enlarge the hole to the specified size, help stabilize the bit, straighten the wellbore if kinks or doglegs are encountered, and drill directionally.2

RED Rag Energy Drillin

redundancy Redundancy wherein all means for performing a required function are intended to operate simultaneously.

reservoir A naturally occurring underground body of liquids, such as water or steam.

RKB Rotary Kelly Bushing. Bushing that sits on top of the rotary table. It transmits torque from the rotary table to the kelly and is commonly used as a reference for vertical measurements from the drill-floor.6

roller cone bit A tool designed to crush rock efficiently while incurring a minimal amount of wear on the cutting surfaces. The roller-cone bit has conical cutters or cones that have spiked teeth around them. As the drillstring is rotated, the bit cones roll along the bottom of the hole in a circle. As they roll, new teeth come in contact with the bottom of the hole, crushing the rock immediately below and around the bit tooth. As the cone rolls, the tooth then lifts off the bottom of the hole and a high-velocity fluid jet strikes the crushed rock chips to remove them from the bottom of the hole and up the annulus. As this occurs, another tooth makes contact with the bottom of the hole and creates new rock chips. Thus, the process of chipping the rock and removing the small rock chips with the fluid jets is continuous. The teeth intermesh on the cones, which helps clean the cones and enables larger teeth to be used. There are two main types of roller-cone bits, steel milled-tooth bits and carbide insert bits.2

ROP Rate of Penetration. A measure of the speed at which the bit drills into formations, usually expressed in feet (meters) per hour or minutes per foot (meter).2

rotary drilling A drilling method in which a hole is drilled by a rotating bit to which a downward force is applied. The bit is fastened to and rotated by the drill stem, which also provides a passageway through which the drilling fluid is circulated. Additional joints of drill pipe are added as drilling progresses. 2

rotary table Device used to apply torque to the drill string during drilling and normally located in the centre of the drill floor.6

RPM Revolutions per minute.



RSS Rotary Steerable System. A tool designed to drill directionally with continuous rotation from the surface, eliminating the need to slide a steerable motor. Rotary steerable systems typically are deployed when drilling directional, horizontal, or extended-reach wells. State-of-the-art rotary steerable systems have minimal interaction with the borehole, thereby preserving borehole quality.2

shut-in To close the valves on a well so that it stops producing. To close in a well in which a kick has occurred.2

sidetrack A secondary wellbore drilled away from the original hole. It is possible to have multiple sidetracks, each of which might be drilled for a different reason (multilateral).

SL or MSL Sea level or Mean sea level.

SPH Smoothed Particle Hydrodynamics, a meshless numerical method used for simulating the dynamics of continuum media, such as solid mechanics and fluid flows.

stabilizers They are included in the drill string, more precisely at drill collar level, to control the bit and keep it on the right trajectory, whether vertical or deviated. The shapes and makes vary depending on the formation, the abrasiveness and the service required.7

stress The force applied to a body that can result in deformation, or strain, usually described in terms of magnitude per unit of area, or intensity.2

sub A short, threaded piece of pipe used to adapt parts of the drilling string that cannot otherwise be screwed together because of differences in thread size or design. A sub (a substitute) may also perform a special function. Lifting subs are used with drill collars to provide a shoulder to fit the drill pipe elevators; a kelly saver sub is placed between the drill pipe and the kelly to prevent excessive thread wear of the kelly and drill pipe threads; a bent sub is used when drilling a directional hole.2

SWOT Strengths, weaknesses, opportunities, and threats.

taxonomy Systematic classification of items into generic groups based on factors possibly common to several of the items

TCI bit Tungsten Carbide Insert bit.

TD Total Depth.

THP Tubing Hanger Pressure. The pressure in the production tubing.

TDS (top drive) A top drive system (frequently also referred to as a power swivel) is a piece of equipment that serves the following functions: rotating the drill string (formerly undertaken by the rotary table); providing a conduit for drilling mud (formerly undertaken by the rotary swivel); disconnecting/connecting pipe (formerly undertaken by the iron roughneck); closing in the drill pipe by an integrated kelly valve (formerly undertaken by the kelly valve in connection with the rotary table); lifting/lowering drill string by use of standard elevator (formerly undertaken by the hook by using same kind of elevator). Top drives may be either electrically or hydraulically driven. If they are hydraulically driven, several hydraulic motors are normally used. Elevator links and elevators are not regarded as a part of the top drive (standard drilling equipment).6

torque The turning force that is applied to a shaft or other rotary mechanism to cause it to rotate or tend to do so. Torque is measured in foot-pounds, joules, newton-meters, and so forth.2

Tubing Hanger Component used to support the downhole completion tubing string. It is also typically used to seal and contain the completion annulus from the environment.6

TUM Technische Universitaet München.

TVD True Vertical Depth. The vertical distance from a point in the well (usually the current or final depth) to a point at the surface, usually the elevation of the rotary kelly bushing (RKB). This is one of two primary depth measurements used by the drillers, the other being measured depth.2

UBI Ultrasonic Borehole Imager. See ultrasonic measurements.



UCS Unconfined compressive strength, uniaxial compressive strength. A measure of a material’s strength. The unconfined compressive strength (UCS) is the maximum axial compressive stress that a right-cylindrical sample of material can withstand under unconfined conditions, the confining stress is zero.2

ultrasonic measurements

In the context of borehole logging, measurements of acoustic signals that are in the hundreds of kilohertz to the low-megahertz range. Such ultrasonic instruments are mostly of the pulse-echo type, and are used in the borehole televiewer, and in various cased-hole devices to determine corrosion and cement-bond quality.2

USIT Ultrasonic Imaging Tool. See ultrasonic measurements.

VES Vertical Electrical Sounding.

VSP Vertical Seismic Profile. A class of borehole seismic measurements used for correlation with surface seismic data, for obtaining images of higher resolution than surface seismic images and for looking ahead of the drill bit.2

WOB Weight on bit. The amount of downward force placed on the bit.

well logging Assessing the geologic, engineering, and physical properties and characteristics of geothermal reservoirs with instruments placed in the wellbore.4

well stimulation

A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near-wellbore area.2

WL Water level or Wireline in the Oil and Gas Industry.