YoungPetro - 1st Issue - Spring 2011

SPRING

ISSUE #1

An Official Publication of

The Society of Petroleum Engineers Student Chapter P o l a n d • www.spe.net.pl

2 Intro

Our future in our hands We are giving in your hands the first issue of SPEreview the magazine which allows young members from all over the world to publish results of their extraordinary scientific work.

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Contents 3

Contents Where the East met West Wojtek Stupka

Unconventional becomes conventional

4

Grzegorz Byrski, Tomasz Dziura

6

A comprehensive review on drill string vibrations, modeling and experimentation

9

Parimal A. Patil, Catalin Teodoriu, Kurt M. Reinicke

Expertimental study to analyze cement corrosion under CO2 environment

22

S. Manna, C. Teodoriu, K. R. Reinicke

Extended Reach Drilling (ERD) technology overview

31

Bartłomiej Kolasa

MWD Engineer Jacob Jagiełło, Daniel Dyndor

History of SPE Poland Section

51

Lukas Malinowski

54

Student Technical Conference – Wietze 2010

59

Paweł Wilaszek

Editorial Committee

Editor-In-Chief

Wojtek Stupka

Editors

Jacob Jagiełło

Lukas Malinowski

Agnieszka Olech

Kacper Malinowski

Cover Photo

Chris A. Fugiel

chrisfugiel.pl

Photos

Dawid Jach

Lukas Karda

Layout & Graphics

Marek Nogieć

4 East meets West

Wojtek Stupka

Where the East met West

From the beginning of the SPE Poland Student Chapter we have been dreaming about our own international event which would gather students from all over the world and allow them to show their ideas to representatives of industry.

Finally 8-9 April 2010 was the date when our dream came true. After tough months of planning and managing, the International Scientific Technical Conference “East meets West” took place in Krakow.

To be frank none of us could imagine that organizing such huge event can be even possible in such short time. So our astonishment was greater when we received over 60 abstracts and 15 confirmation of representatives’ arrival from companies such as Halliburton, Schlumberger, Weatherford, Baker-Hughes, RWE Dea, RAG, NOV, Smith and OGEC Krakow.

The conference was officially opened by 2011 SPE President Dr Alain Labastie and Rector of AGH Prof. Dr Hab. Inż. Zbigniew Kąkol. The main theme of the first day was presentations on the latest technological developments used in the oil and gas industry. Participants could also hear about Weatherford Student Internship Program.

Simultaneously to the presentations student’s poster contest took place, in which ten posters compete to win. As a winner jury have chosen David Kryzia – AGH student with his poster “Influence of the development of LNG technology on the natural gas market”. After interesting but long day all guest took part in official banquet. The second day started with lecture of Dr Serge Rueff - SPE Regional Director for Eastern, South and Central Europe and included the scientific part of conference during which 16 students presented their studies and achievements. The “Applica-

Where the East met West

tion of artificial neural networks is a formation permeability evaluation” by Peter Kurnik from AGH University turned out to be a winning presentation. To fulfill old polish tradition after official conference ending participants went to the after party in Baccarat Music Club.

During two days of “East meets West” we have been proud to host over 500 visitors, including representatives from Halliburton, Weatherford, RWE Dea, Schlumberger, Baker Hughes, BJ Services, Premier Oilfield Rentals Ltd, NOV, GEMS Survey Limited, OGEC Kraków, OGEC Jaslo, Geofizyka Kraków, students from Ukraine, Russia, France, Germany, Scotland and Greece. We are more than delighted with this statistics. It was real honor to met all this people and seen how big potential has this kind of events. The conference couldn’t happen without help from our

East meets West 5

generous sponsors who gave us financial and technical aid. From this place on behalf of all members of SPE Poland Students Chapter we want to thank all the people who give us support. Especially the Golden sponsor - Halliburton, the Silver - Weatherford and RWE Dea, sponsors of the residence of foreign students - RAG Austria company and Mr. Nasser Bashar, who is a graduate of the Faculty of Drilling, Oil and Gas at AGH University, the official partner of the conference - The Ignacy Lukasiewicz Foundation, which operating at PGNiG. Also words of gratitude are due to strategic sponsors - Mediashpere company and Baccarat Music Club We are glad that the conference ended with such great success and hope that 2011 “East meets West” - European Student Petroleum Congress will be equal to its predecessor or even better.

6 Papers

Grzegorz Byrski, Tomasz Dziura

Unconventional becomes Conventional

Reserves of natural gas in whole world are still decreasing what means increasing costs of fuels for industry needs and most of all for a single user. Most countries (including Poland) don’t have enough reserves to provide the energy autonomy and have to find new sources of energy.

That sources could be unconventional gas reservoirs. Unconventional gas reservoirs are reservoirs that cannot be produced at economic flow rates or that do

••Fig. 1

not produce economic volumes of oil and gas without assistance from massive stimulation treatments or special recovery processes and technologies. The main types of unconventional gas resources are : »» Tight gas sands (gas in low-permeability rock), »» Gas shale (gas held in shale reservoirs), »» Coalbed methane (natural gas within the structure of coal) »» Deep natural gas (gas that exists in deposits very far underground) »» Geopressurized Zones (formations that are under unusual high pressure for their depth) »» Methane Hydrates (lattice of frozen water, which forms a sort of “cage” around molecules of methane) In Poland the three most common types of unconventional gas are:

Unconventional becomes Conventional

Papers 7

••Fig. 2

»» Tight gas sands »» Gas shales »» Coalbed methane Unconventional gas has become an increasingly important source of natural gas in the United States over the past decade what shows graph (Fig.1).

In Poland huge gas reserves are locked in difficult-to-recover reservoirs. These resources are typically located in heterogeneous, extremely complex, and often poorly understood geologic systems, often easy to find but difficult to produce.

High gas prices and evolving technology will ensure the development of these reserves, but it will not be easy.

Polish Ministry of the Environment has issued 44 licenses (valid for 5 year) for the exploration of unconventional natural gas in Poland, including to ExxonMobil, Chevron, ConocoPhillips and Marathon. Main areas of interest for shale gas exploration are located in the northern and centraleastern parts of Poland (Baltic Depression and Lublin Trough) (Fig. 2).

••Fig. 3

The map (Fig. 3) presents northern centralwestern parts of Poland which contain the majority of perspective tight gas reservoirs in the country. Areas in eastern and southern Poland – Lublin Trough and Upper Silesian Coal Basin present coalbed methane (CBM) targets related to the presence of Carboniferous coal Geological.

Difficulties with production of gas from unconventional gas reservoirs are presented on the resource triangle (Fig. 4).

The large volume and long-term potential, attractive gas prices and unprecedented

••Fig. 4

8 Papers

interest in world markets, bring the unconventional gas into the forefront of our energy future.

Grzegorz Byrski, Tomasz Dziura According to huge demand even reserves that were unconventional yesterday become conventional today.

Literature 1. Dobrova H. , Gawenda P., Renevey P., Fressineau J., Unconventional Resources Potential in Continental Europe – Prospects and Developments. AAPG European Region Annual Conference. Conf mat.: Paris-Malmaison 23-24 November 2009.

2. Gliniak P., Poszukiwania złóż gazu w Polsce i na świecie. Gas summit. Conf. mat.: Warsaw 23-24 February 2010.

3. Hadro J., Strategie poszukiwań gazu w łupkach i ich uwarunkowania ekonomicznoprawne. Unconventional reservoirs In Poland– shale gas and tight gas Conf. mat.: Warsaw 27 January 2010.

4. Jezierski H., Zasoby gazu w Polsce, udzielanie koncesji poszukiwawczych. Gas summit.

Conf. mat.: Warsaw 23-24 February 2010.

5. Kalski M., Rola gazu ziemnego w polityce energetycznej państwa. Unconventional reservoirs In Poland – shale gas and tight gas Conf. mat.: Warsaw 27 January 2010.

6. Nawrocki J., Bilans zasobów gazu ziemnego w Polsce. . Unconventional reservoirs In Poland – shale gas and tight gas Conf. mat.: Warsaw 27 January 2010.

7. Poprawa P., Kiersnowski H., “Potential for shale gas and tight gas exploration in Poland”.

Bulletin PGI, 429: 145-152, 2008.

8. Perry K. , Lee J., Unconventional Gas Reservoirs – Tight Gas, Coal Seams, and Shales, The University of Texas February 21 2007.

9. Wójcik, Strategia Polskiego Górnictwa Naftowego I Gazownictwa w zakresie poszukiwań niekonwencjonalnych zasobów gazu ziemnego. Unconventional reservoirs In Poland– shale gas and tight gas Conf. mat.: Warsaw 27 January 2010.

10. www.pgi.gov.pl 11. www.pbg.com.pl 12. www.naturalgas.org

Papers 9

Parimal A. Patil, Catalin Teodoriu, Kurt M. Reinicke

A comprehensive review on drill string vibrations, modeling and experimentation Institute of Petroleum Engineering, Clausthal University of Technology, Germany e-mail: ppa@tu-clausthal.de

Abstract Pre-drilling analysis and real time analysis of drillstring dynamics is becoming a necessity for drilling oil/gas or geothermal wells in order to mitigate vibration related problems. Purpose of doing so is to design the complete drillstring assembly with bottom hole assembly (BHA) and operate it far away from its resonant frequency. Operating BHA and drillstring above or below the critical rotary speed will definitely reduce probability of premature failure or even catastrophic situation. The complexity of the phenomenon makes it impossible to define the worldwide acceptability of the derived model, although modeling and validating the mathematical results using laboratory experiments have been carried out since decades but still lack the preciseness. Most of the times, parameters affecting the model are either unknown or insufficiently studied during modeling. Following article reviews most of the information which needs to be considered while looking closer to complex drillstring dynamics.

Introduction Economic exploitation and feasible development of deeply buried underground resources is a common practice but critical

goal of oil/gas and geothermal industry. It is mainly controlled by interplay of certain set of complex parameters, viz. reservoir grade, geology, drilling parameters or drilling contractor’s experience, availability of equipments, surface facility and over-

10 Papers

Parimal A. Patil, Catalin Teodoriu, Kurt M. Reinicke

all operational process. Understanding the relative importance of each parameter through the development process, economic risks can be identified, analyzed and mitigated. Today’s challenge with a drilling engineering is to reach deeper target as fast as possible minimizing the cost without overlooking health, safety and environmental (HS&E) guidelines.

In order to help creating borehole, mechanical energy needs to be transferred from surface to the bit and at the same time drilled cuttings need to be transported from the bottom to surface using hydraulic energy. The mechanical energy is transferred to bit by rotating the drillstring by electric top drive motor on the surface. The drilling fluid is pumped down through the drillstring and flows back through the annulus between drillstring and wellbore to the surface; see Fig. 1. The drillstring is composed of slender tubes called as drill pipes and the Bottom Hole Assembly (BHA) screwed together by a tool joints. BHA is composed of thick walled tubular called as heavy drill collars, bottom hole measuring tools and a bit.

This section of a drillstring is put under compression in order to apply Weight On Bit (WOB). The length of this section is designed in such as way that the bottom of the drill pipe section has nearly zero axial load. This zero axial load point is called as ‘neutral point’ and usually lies in drill collar section. BHA is subjected to compression due to WOB and to torsion due to rotation and the cutting effect.

With increasing depths, it has become even more important for one to efficiently utilize the available energy. Drilling efficiently means drilling with optimum operational parameters such as weight on bit (WOB), rotations per minute (RPM), torque on bit (TOB), bit type, and bit hy-

••Fig 1- Typical Drilling Rig

draulic horsepower. This available input mechanical energy results in output parameters which are rate of penetration (ROP) and cost per foot. Low rate of penetration and reduced drilling efficiencies have always been a challenge to drilling industry. Inefficient drilling may cause due to the factors that influences performance drilling [1]. According to MensaWilmot et al., performance drilling is the process in which decisions and actions are needed to achieve maximum drilling efficiency and also detail data analysis is carried out at the end to help improving the learning curve process. Researchers in the past claim that drilling vibration is one of the major causes of inefficient drilling performance, and an addition to the overall well cost [2-6]. It is indeed a crucial task to understand the complex behavior of drillstring while rotating in order to better control the dysfuntioning of it and to improve overall performance.

A comprehensive review on drill string vibrations

Drillstring Dynamics Drillstring is under dynamic loading while drilling a hole which results in vibrations.

Vibration is defined as a movement to and fro. It is the manifestation of the oscillatory behavior in drill string. Combination of mass, stiffness and dynamic forces lead the system to vibrate. Drillstring has its own mass, certain stiffness and dynamic forces acting while in process, hence it vibrates. Since drilling a wellbore is a destructive phenomenon of cutting rocks, vibrations are unavoidable. Field observations have shown different vibration measurements in downhole and on surface, meaning bottom hole assembly undergoes severe vibrations. Vibration is the result of bit/formation and drillstring/ borehole non linear interaction. These non linear interactions act as excitation source and drillstring vibrates in 3 basic modes/directions: axial, lateral and torsional. When the drillstring moves up and down along its axis of rotation it is called axial vibration. When the drillstring moves laterally to its axis then it is lateral vibration. The drillstring when rotated from the surface twists along its axis which let the bit to rotate with different speeds causing torsional vibration. But in reality, drillstring vibrates more often as combinations of all these three basic modes which make the problem fairly complex to measure and investigate. Typically, drillstring vibration will generate high frequency noise which adds to the downhole measurement data and can lead to a dramatic deterioration of the transmitted data. Very often, by simply making adjustments to the WOB and RPM, it is possible to avoid critical torsional and lateral resonance. A number of vibration prediction programs are available which can estimate critical RPM for a given drilling assembly. Improv-

Papers 11 ing drilling efficiency by controlling drillstring dynamics has been a challenge in oil industry from past many years. The issue has been solved analytically as well as mathematically to predict the complex interaction between bit, drillstring and formation. Many varieties of mathematical models have been developed so far. However, in some cases the results derived from the mathematical models are not in agreement with the field recorded data.

Past Development Very first problem was tackled by developing dynamic models of the drillstring

by Bailey et al., later verifying it with experimental study [7-8]. Kyllingstad, Aarrestad and Halsey worked extensively on understanding and mitigating vibration both by developing mathematical models as well as verifying them with experimental results but with limited insight [9-10].

Axial vibration at the top of the drillstring is very dependent on damping along the drillstring and frequency of the excitation [9]. Hasley et al. conclude that lowest torsional frequency is very sensitive to properties of drill pipes and drill collars, and these frequencies are independent of rotations per minutes, weight on bit and damping effect, as long as the drillstring rotates freely [10]. It has been observed during drilling that the torque at the top drive fluctuates with time caused due to interruption of downhole tool rotation which starts and stops because of the downhole friction factor [11]. This situation occurs when the static friction coefficient is sufficiently high enough than the dynamic friction coefficient. As drillstring is rotated continuously on surface, it stores torsional energy. When this torsional energy exceeds static friction or when the bit can no longer withstand increasing

12 Papers

••Fig 2 - System diagram showing parameters considered for modeling by Brett et al. [17]

torque, the bit accelerates and rotates with maximum speed and unwinds drillstring. This phenomenon is called stick slip and can generate self excited vibrations. Later, stick-slip condition was also mathematically modeled by Hasley et al. assuming that the drillstring behaves like a simple torsional pendulum with one degree of freedom. The model could not predict occurrence of stick-slip under given sets of conditions. It was seen in model that with the increase in rotary speed there was a decrease in mean torque value, which was not explained by the theory presented [12].

Dunayevsky et al. studied drillstring dynamics as a function of drilling parameters. Finite element model was developed which consider continuous wall contact, representing at what critical rotary speed the axial vibrations may trigger transverse vibrations. With the parametric resonance model developed, it was possible to indicate the mode of failure but lack the

Parimal A. Patil, Catalin Teodoriu, Kurt M. Reinicke behavior of failure with respect to time.

It does not consider effects of whirl and stick slip [13]. Dykstra et al. evaluated interaction of drill bits and different types of formation extensively by performing laboratory and field experiments recommending operational deficiencies in order to reduce the downhole vibration [14]. Further work by Dykstra et al. presents numerical modeling which shows that the main cause of downhole lateral vibration is a result of mass imbalance of complete drillstring. Mass imbalance situation occurs when the axis of rotation of a drillstring does not coincide with central axis of a well. Developed model restricts one to determine only the deflection in a drillstring at different rotary speed. It does not predict drillstring dynamic behavior.

Experimentation was carried out to quantify the drillstring imbalance condition at different speeds of rotation on the surface but was evaluated visually [15].

Spanos et al. [16] worked extensively on the complex dynamic behavior of drillstring using frequency response models.

These models were unable to reproduce the observed dynamic phenomenon though it provides qualitative analysis of BHA performance. According to the sensitivity analysis by Spanos et al., understanding the critical BHA dynamic factors include damping which plays an important role to control response at excitation, drilling fluid density which alters the natural frequencies of BHA elements, and effect of weight on bit on the system.

The model also does not consider stiffness of components, excitation frequency of every BHA element, and mainly the experimental analysis. Brett et al. presented a model which shows that the bit-rock interaction initiated the torsional vibration in the system and could be eliminated by controlling gain in surface rotary system

A comprehensive review on drill string vibrations

Papers 13

••Fig 3 - Equivalent mechanical representation of a drillstring driven by an electric rotary drive & hydraulic top drive with an active damping system [20], [21]

[17]. Simple model uses two differential equations that were solved with RungeKutta simulation approach. Models developed consider the behavior of drillstring as a lumped mass with spring and the surface drive system. It assumes the standard relationships for drill pipe stiffness and the rotational inertial, constant drillstring friction torque and laboratory drilling data for the relationship between bit torque and rotary speed. Model also describes that the bit induced torsional vibration could be eliminated by overrunning the motor but was not field tested.

Later with the development of downhole measurement tools, analysis of downhole data was carried out to optimize drilling performance. Several operational recommendations were made in order to avoid rotating drillstring at critical frequencies. Integration of different approaches for preventing and eliminating severe dynamic dysfunctions were suggested [18]. The uses and limitations of developed models have well documents by Nicholson. According to him, analytical/

numerical models are not able to account for all drilling dynamics dysfunctions or expected downhole conditions such as: over gauged hole, friction interaction, etc.

The concept of active damping of self excited torsional drillstring vibrations with feedback control in the drive system originates from Halsey et al. [19]. Attempt to mitigate torsional drillstring vibration was done by Jansen et al. by developing active damping system for drillstring driven by electric rotary drive and drillstring driven by hydraulic top drive, as shown in Fig. 3 below. This system makes the top drive react to when it detects non-linear relationship between torque and angular velocity of the bit vibrations. As soon as bit starts experiencing the stick-slip condition, as explained above, the hydraulic top drive system gets activated. The drawback of both the systems is the drive system of the rig needs to be changed completely, meaning rig need to be modified in order to run the feedback control system.

14 Papers

Parimal A. Patil, Catalin Teodoriu, Kurt M. Reinicke

Kriesels et al. proposed further soft torque rotary system (STRS) [5] for electric and hydraulic drives for preventing torsional vibrations mainly stick slip. Increased rate of penetration and bit life was observed after development of this system. Use of vibration analysis software for BHA design and regular inspection of drillstring components also helped to improve overall drilling performance. STRS also need modification of rig top drive system. Possible damage to drillstring could answered with this system but it does not take into account the over gauge holes, inhomogeneous and hard formations.

tigate drilling system performance more completely. Finite element model by Heisig et al. [23] consider BHA in greater detail and same BHA was analyzed for linear analytical model, linear finite element model, and non-linear finite element model in order to validate more complex models in time domain. Understanding downhole forces, critical loads, critical rotary speeds, integrating newly developed technology with drilling system dynamic modeling and the formation modeling results in significant improvement in overall drilling performance of the system [24 – 28].

The work is furthered by Dykstra et al. [22] in which bit dynamic program is coupled with drillstring dynamic program to inves-

The research continued in this field and Menand et al. modeled the entire drillstring [29]. Soft string and stiff string mod-

••Fig 4 - Electrical and Mechanical representation of Soft Torque Rotary System (STRS) [5]

A comprehensive review on drill string vibrations els were used together to determine the torque and drag over the length of drillstring. The effect of temperature in case of high pressure/high temperature wells is also considered in model development.

The main advantage of the model developed by Menand et al. is it can be used in real time drilling operation as it does not use finite element analysis. Samuel et al. studied the dynamics of the drillstring based on forced frequency response analysis, which can predict and minimize occurrences of downhole equipment failures [30]. Further work derives ROP parameter which can be used as a guideline to eliminate undesired WOB-RPM pair. Eliminating these pairs will avoid vibration or near-vibration peaks according to Samuel et al. Developed model by Apostal et al. considered damping due to the presence of fluid, formation, friction and other effects. In addition viscous and structural damping mechanisms were also considered. Though the program has capability for computation of damping

Papers 15 and added mass effects, it assumes cyclic behavior of drillstring which is not a real situation downhole [31].

According to Bailey et al., the mind-set of industry is changing from considering drillstring dynamics as an analytical problem to avoiding of critical modes by optimally designing the drillstring and then predicting the best specific operating parameters. The efficiency of time domain frequency facilitates the characterization of drillstring dynamics and consideration of complex modeling systems [32]. There model seems to be simple as it cannot fit all of the field data, all of the time. Detail consideration needs to be given while developing models.

••Fig 5 - Schematic and Experimental representation of drillstring set up [34]

16 Papers

Regeneration of downhole condition in laboratory Advanced practical understanding of the influence of drillstring dynamics on bit life and overall performance have been investigated by the researchers focusing on particular drillstring problem and made some progress time to time. More and more complicated models came up with new theories and were validated with the field data. Still the effect of self excited oscillations in the drilling process due to finite delays or due to the wave propagation in the elastic drillstring has not been simulated. Other approach to study vibration closely in laboratory is by building a simulated drillstring setup and playing around it. Leine et al. studied extensively the behavior of stick slips and whirl interaction in a drillstring. According to Leine et al., finite element models provide quantitative information about the drillstring dynamics giving some practical recommendations. In order to understand the dynamics downhole, models need to be kept as simple as possible to give qualitative information [33]. Downhole friction

Parimal A. Patil, Catalin Teodoriu, Kurt M. Reinicke

••Fig 6 - Laboratory Simulation of drillstring dynamics using model based control approach [35]

induces negative damping, meaning leads to vibrations according to Mihajlovic et al. Mathematical model was developed and then analysis was carried out on the basis of theoretical stability analysis and numerical bifurcation analyses. In order to compare the model results with the experimental, following set up was built [34].

Raymond et al. developed a laboratory scaled drilling facility to gain practical understanding of downhole dynamics, and to develop the best operational parameters in order to eliminate drillstring vibrations. Rock/bit interaction together with drillstring dynamics can be reproduced in the laboratory. This experiment actually drills the rock formation in laboratory giving a good insight of response of drill bit/formation interaction and dynamics of drillstring, shown in Fig. 6. Two approaches were considered to simulate the conditions which are mechanical analog and model based control. In mechanical analog approach vibrations are introduced in the system while in model based control approach drillstring dynamics with change in weight on bit, rotations were predicted using numerical models

A comprehensive review on drill string vibrations

[35]. The experimentation is limited to the axial model of vibrations only.

Melakhessou et al. worked on modeling and experimenting non linear interaction between drilling and wellbore wall, Fig. 7 [36].

Coefficient of friction was taken into consideration and the initial string position too. Model was developed deriving equation of motions form Lagrange equations and were solved using Runge-Kutta algorithm. From the Fig. 7, it can be seen how opto electronic cameras were located.

Cameras measured the lateral displacement of the rod. The phenomenon takes into account the interaction between tool joints and wellbore and the drillstring and wellbore. Model takes into account only lateral displacement and not other modes of vibrations. Latest investigation in this field was done by Khulief et al [37].

Papers 17

••Fig 7 - Scheme of experimental set up and measurement system [36]

They studied impact of drillstring with wellbore and the dynamics of drillstring together which results in high frequency excitations. Impact model was developed considering the material properties, damping coefficients and was integrated with dynamic model of whole drillstring.

Lagrangen approach was used to derive the dynamic model of a drillstring. Model accounts torsional-bending coupling and axial-bending non linear coupling.

Time response of drillstring system was calculated. Further work by Khulief et al. includes laboratory investigation of drillstring dynamics. Test rig can simulate stick slip, string/wellbore contact, and drilling fluid interaction according to Khulief et al.

Magnetic tension brake was used to simulate the stick slip while shaker was used to axially excite the drillstring, shown in Fig. 8 [38].

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Parimal A. Patil, Catalin Teodoriu, Kurt M. Reinicke

Experimental setup consist of steel framework, DC motor, stainless steel vertical shaft as a drillstring , a Plexiglas pipe to contain the fluid surrounding the rotating shaft, magnetic tension brake, and a shaker. Length of a drill shaft was selected from the range of 1 to 2 m and the shaft diameter was selected between 0.3 and 1.0 cm. In reality, drillstring is a hollow pipe with certain wall thickness and stiffness factor, which is not considered by Khulief et al. [38]. Also, the experimentation does not consider the non-linear dynamic behavior of impact between BHA and wellbore.

Further Development in Drillstring Dynamics In the world of high drilling costs, drilling inefficiencies significantly influence by adding extra cost and making the development project marginal. Improving drilling efficiency or by optimizing downhole drilling parameters by reducing non productive time and maximizing ROP still remains the main challenge. Present methods rely on WOB, TOB and RPM measurements for optimizing ROP but not precise enough to consistently manage and optimize ROP and reduce dynamics dysfunctioning of drillstring.

In order to precisely replicate the downhole condition in laboratory, it is desirable to shrink the multiple thousands of meters of drillstring and other BHA components into a laboratory scale rig using law of similitude. By doing so experimental investigation could be carried out which will represent close to the actual in field scenario. This will also provide to simulate vast range of well depths with different diameters of the similitude drillstring that

••Fig 8 - Schematic of laboratory test rig by Khulief et al. [38]

too in a convenient environment. Lacking capabilities in previous studies need to be evaluated well keeping holistic approach.

Consideration of all the possible factors which affect drillstring dynamics without negligence should be done in future.

Conclusion Drilling vibration is one major challenge in oil/gas and geothermal drilling industry. Overall drilling performance depends on how one optimizes drilling parameters while drilling. In reality, there are many uncertainties. Complex geologies, formation dips, well paths, well parameters,

A comprehensive review on drill string vibrations drillstring/BHA dimensions, material properties, drilling fluid properties, temperature, etc. all cannot be simulated at once, though lots of efforts are involved over the years. Still it feels that extensive research in the area of drillstring vibration is required for advance practical understanding in areas like oil well and geo-

Papers 19 thermal drilling. But redefining the overall objectives and sticking close to reality, the lacking attributes of worldwide testing facilities could be improved. Monitoring and controlling of drillstring dynamics will also definitely assist to improve drilling performance, reduce invisible lost time and minimizing high drilling cost.

Acknowledgements This contribution was made possible by financial support by the Ministry of Science and Culture, Lower Saxony (NWK) and Baker Hughes, Celle within the research program “gebo” (Geothermal Energy and High Performance Drilling).

References 1. Mensa-Wilmot, G., Southland, S., Mays, P., Dumrongthai, P., Hawkins, D., and Iiavia, P.: “Performance Drilling – Definition, Benchmarking, Performance Qualifiers, Efficiency and Value”, SPE/IADC 119826, presented at SPE/IADC Drilling Conference in Amsterdam, The Netherlands, 17 – 19 March 2009.

2. Ersoy, A., and Waller, M. D.: “The application of PDC pins in rock coring bits”, 14th Mining congress of Turkey, ISBN 975-395-150-7, 1995.

3. Ersoy, A., and Waller, M. D.: “A critical review of factors influencing the wear of thermally stable diamond (TSD) rock drilling bits”, 15th Mining Congress of Turkey, ISBN 975-395216-3, 1997.

4. Dubinsky, V. S., Baecker, D. R.: “An interactive drilling dynamics simulator for drilling optimization and training”, SPE 49205, presented at SPE Annual Tech. Conf. and Exhhibiton in New Orleans, Louisiana, 27 – 30 Sept, 1998.

5. Kriesels, P. C., Keultjes, W. J. G., Dumont, P., Huneidi, I., Furat, Al, Owoeye, O. O., and Hartmann, R. A.: “Cost saving through an integrated approach to drillstring vibration control”, SPE/IADC 57555, presented at Middle East Drilling Tech. Conf. in Abu Dhabi, UAE, 8 – 10 Nov, 1999.

6. Guerrero, C., and Bobbie, K.: “Deployment of an SeROP predictor tool for real time bit optimization”, SPE/IADC 105201, presented at the Drilling Conf. in Amsterdam, The Netherlands, 20 – 22 Feb, 2007.

7. Bailey, J. J., and Finnie, I.: “An analytical study of drillstring vibration”, J. Eng. Ind. ASME Trans, 82(2), 122 – 128, 1960.

8. Finne, I., and Bailey, J. J.: “An experimental study of drillstring vibration”, J. Eng. Ind. ASME Trans, 82(2), 129 – 135, 1960.

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9. Aarestad, T. V., Tonnesen, H. A., and Kyllingstad, A.: “Drilling Vibrations: Comparison between theory and experiments on a full scale research drilling rig”, SPE/IADC 14760, presented at Drilling Conference in Dallas, USA, Feb 10 – 12, 1986.

10. Halsey, G. W., Kyllingstad, A., Aarrestad, T. V., and Lysne, D.: “Drillstring Torsional Vibrations: Comparison between theory and experiment on a full scale research drilling rig”, SPE 15564, presented at 61st Annual Tech. Conf. and Exhibition in New Orleans, USA, Oct 5 – 8, 1986.

11. Dawson, R., Lin, Y. Q., and Spanos, P. D.: “Drill string stick slip oscillations”, Spring conference of the Society for Experimental Mechanics in Huston, USA, June 14 -19, 1987.

12. Kyllingstad, A., and Halsey, G.W: “A Study of Stick-Slip motion of the Bit”, (1988), SPE 16659.

13. Dunayevsky, V.A, Abbasslan, F., Judzis, A.: “Dynamic Stability of Drillstrings under fluctuating weight on Bit”, (1993) SPE Drilling and Completion, SPE 14329-PA. 14. Dykstra, M.W., Chen, D.C.-K., Warren, T.M., and Zannoni, S.A.: “Experimental Evaluation of Drill Bit and Drillstring Dynamics”, (1994), SPE 28323.

15. Dykstra, M.W., Chen, D.C.-K., Warren, T.M., and Azar, J.J.: “Drillstring component mass imbalance: A Major Source of Downhole Vibrations”, (1996), SPE Drilling and Completion, SPE 29350.

16. Spanos, P.D., & Payne, M.L.: “Advances in dynamic bottomhole assembly modeling and dynamic response determination”, (1992), SPE Drilling conference, SPE 23905.

17. Brett, J. K.: “The Genesis of Torsional Drillstring Vibrations”, (1992), SPE Drilling Engineering, SPE 21943.

18. Nicholson, J. W.: “An integrated approach to drilling dynamics planning, identification and control”, SPE/IADC 27537, presented at Drilling Conference in Dallas, Texas, Feb 15 – 18, 1994.

19. Hasley, G. W., Kyllingstad, A., and Kylling, A.: “Torque feedback use to cure stick slip motion”, presented at 63rd Annual Tech. Conf. and Exh. In Houston, Texas, Oct 2 – 5, 1988.

20. Jansen, J. D., van den Steen, L.: “Active damping of self excited torsional vibration in oil well drillstring”, Journal of Sound and Vibration, 179, No. 4, 647, 1995.

21. Jansen, J. D., van den Steen, L., and Zachariasen, E.: “Active damping of torsional drillstring vibrations with a hydraulic top drive”, SPE 28911, Journal of SPE Drilling and Completion, Dec 1995.

22. Dykstra, M.W., Neubert, M., Hanson, J.M, and Meiners, M.J.: “Improving Drilling Performance by Applying Advanced Dynamics Models”, (2001), SPE/IADC Drilling Conference held in The Neatherlands, 27 Feb – 1 March 2001, SPE-67697.

23. Heisig, G., and Neubert, M.: “Lateral drillstring vibrations in extended reach wells”, SPE 59235, presented at SPE/IADC Drilling Conference in New Orleans, Lousiana, Feb 23 – 25, 2000.

24. Hood, J.A, Leidland, B.T., Haldorsen, H., Heisig, G.: “Aggressive drilling parameter management board on downhole vibration diagnostics boots drilling performance in difficult formation”, SPE Annual Technical Conference, Louisiana, 30 Sept – 3 Oct 2001, SPE – 71391.

A comprehensive review on drill string vibrations

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25. Aadnoy, B.S., & Huusgaard, P.P.: “Analytical models for design of well path and BHA”, SPE/ IADC Asia Pacific Drilling Technology, Jakarta, Indonesia, 9 – 11 Sept 2002, SPE – 77220.

26. Boyadjieff, G., Murray, D., Orr, A., Porche, M., Thompson, P.: “Design consideration and field performance of an Advanced Automatic Driller”, SPE/IADC Drilling Conference, The Neatherlands, 19 – 21 Feb 2003, SPE – 79827.

27. Maidla, E., & Haci, M.: “Understanding Torque: The key to slide drilling directional wells”, SPE/IADC Drilling Conference, Dallas, Texas, 2 – 4 March 2004, SPE – 87162.

28. Hill, T., Ellis, S., Lee, K., Reynolds, N., and Zheng, N.: “An innovative design approach to reduce drillstring fatigue”, SPE/IADC Drilling Conference, Dallas, 2 – 4 March 2004, SPE – 87188.

29. Menand, S., Sellami, H., Tijani, M., Stab, O., Dupuis, D., and Simon, C.: “Advancements in 3D drillstring mechanics: From Bit to the Topdrive”, SPE/IADC Drilling Conference, Florida, US, 21 – 23 Feb 2006, SPE – 98965.

30. Samuel, R.G., Schottle, G., & Gupta, D.B.: “Vibration analysis, model prediction and avoidance: A case history”, SPE/IADC Indian Drilling Technology Conference and Exhibition, Mumbai, India, 16 – 18 Oct 2006, SPE 102134.

31. Apostal, M.C., Haduch, G.A., and Williams, J.B.: “A Study to determine the effect of damping on finite element based, forced frequency response models for bottomhole assembly vibration analysis, SPE 20458, 1990.

32. Bailey, J.R., Biediger, E.A.O., Gupta, V., Ertas, D., Elks, W.C., and DUpriest, F.E.: “Drilling vibration modeling and field validation”, SPE/IADC Drilling Conference, Orlando, Florida, 4 – 6 March 2008, SPE 112650.

33. Leine, R. I., van Campen, D. H., and Keultjes, W. J. G.: “Stick slip whirl interaction in drillstring dynamics”, Journal of Vibration and Accostics, Vol 124, 209 – 220, April 2002.

34. Mihajlovic, N., van de Wouw, N., Hendriks, M. P. M., and Nijmeijer, H.: “Friction induces limit cycling in flexible rotor systems: An experimental drillstring set up”, Nonlinear Dynamics, 46, 273 – 297, 2006. DOI 10.1007/s1 1071-006-9040-z.

35. Raymond, D. W., Elsayed, M. A., Polsky, Y., and Kuszmaul, S. S.: “Laboratory simulation of drill bit dynamics using model based servohydraulic controller”, Journal of Energy Resources Technology, Vol. 130, 043103-1/12, Dec 2008.

36. Melakhessou, H., Berlioz, A., and Ferraris, G.: “A nonlinear well drillstring interaction model”, Journal of Vibration and Acoustics, Transactions of ASME, Vol. 125, 46 – 52, Jan 2003.

37. Khulief, Y. A., Al-Sulaiman, F. A., and Bashmal, S.: “Vibration analysis of drillstring with string-borehole interaction”, Journal of Mech. Eng. Sci., Vol. 222, No. 11, 2008.

38. Khulief, Y. A., and Al-Sulaiman, F. A.: “Laboratory investigation of drillstring vibrations”, Journal of Mech. Eng. Sci., Vol 223, April 2009.

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S. Manna, C. Teodoriu, K. R. Reinicke

Experimental study to analyze cement corrosion under CO2 environment TU Clausthal, Germany

Abstract Every century leaves a foot print in the history of mankind. In the beginning of the last century we have discovered oil and gas, which became the driving force of the world economy. As time passed by scientist and people round the world came to realize the importance of natural resources and the effects of their use in a wide scale. During the end of 20th century countries came up to curb down the emission of CO2 which according to the IPCC is the main contributor for global warming. During the end of the last century many technologies has been developed and successfully implemented such as, CCS, CSEGR, EOR etc.

The main eco-friendly and economical feasible technologies conducted in the developed world is Carbon capture and sequestration in the geo-strata. Many dry oil and specially gas fields are chosen to store up carbon dioxide rather leaving them onto the atmosphere.

It is the belief of the engineers that carbon dioxide can be stored inside the formation and leave it for thousand years without any leakage to the surface. To achieve this many hurdles has to be overcome such as, location of the reservoir, abandonment of the reservoir and proper plugging of the wellbore for leakage. In this paper we will discuss about the scenarios that has to be considered for an experimental analysis of cement corrosion.

It is important to build up a scenario at lab; that can be fairly comparable with the actual wellbore condition.

Experimental study to analyze cement corrosion‌

Introduction Oil and gas is still the primary source of energy in the developed and developing world. The wide availability and the comparative lower cost of its use made it the prior source of energy. As the demands are increasing the proven reserves of this energy is dwindling; according to US energy information administration United States net import of gasoline and blended product peaked in the year between 1997 and 2007 about a million barrels per day or 11 percent of US total energy consumption [1]. Burning any fossil fuels origin damage in the environment, as the byproduct carbon dioxide is the primary source for global warming.

Geological storage of CO2 in depleted reservoir is becoming an interesting op-

Papers 23 tion in the global market. This process is moderately cost effective and with a great advantage of recovering depleted oil and gas in the reservoir [2]. Feasibility studies have been going on different fields with respective countries. The major obstacle encountered in this technology is the well bore stability; cementation of the casing and the plugging of the wellbore during abandonment. Cementation is necessary to stabilize the casing in the formation, it also keep different zones separated from any damage due to the drilling work. In oil industry various classes (API recommended) of cements are used according to the depths. In lower depths Class A cements are used and in the deeper depths Class G cements are recommended. In many sulfur producing wells Class E cements are recommended as they are effective for high resistive of sulfur. Class G cements are used in the lower section of

••Fig 1: Stainless steel molds for cement block preparation (dimension 5x5x5 cm).

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S. Manna, C. Teodoriu, K. R. Reinicke

••Fig. 2: Autoclave used for the Cement corrosion experiment.

wellbore (near to the reservoir). Prolonged exposure to carbon dioxide cement starts to degrade, forming unstable zones in the cement sheath and to the plugging.

As carbon dioxide is constantly injected to the formation the pH level of the near wellbore area start to move in the acidic zone. This is due to the presence of aquifer in the reservoir; the aquifer contains a large amount of sodium ions, calcium ions and chlorine ions which makes it highly saline. As the life of the reservoir comes to an end the level of the brine increases; as carbon dioxide is injected constantly the brine solution starts to react with the gas forming carbonic acid. After settling in the borehole cement starts to harden and stays in a mere basic pH zone. As acid starts to build up the stability of the cement sheath is compromised following degradation of the cement.

According to Krilov [3] the cement used in oil wells, under hostile reservoir conditions can lose its mechanical and chemical integrity after a long term exposure (BHST > 180°C, 22% CO2 and 150 ppm of H2S). Some researchers also believe that cement degradation is caused due to the carbon dioxide leaching in the cement sheath. According to Asghari et al, in wells where CBL (Cement Bond Logging) have been conducted; casing cement degradation has been found behind 7” casing, after 15 years of well production period.

Usually carbon dioxide is sequestrated in a super critical (T= 304.1 K, P= 7.38 MPa) stage; some researchers such as Barlet Gouedard et al, Asghari et al conducted and presented research on the degradation of cement under super critical carbon dioxide environment. It is to be remembered cement degradation is a long term

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Experimental setup Four sets of experiments were carried out according to the date (5, 15, 30 and 45 days). A brine solution of 5% NaCl has been used; all the cubical cement blocks were pre-cured (atmospheric pressure, 22°C) under this solution for 24 hrs before placing them inside the autoclave.

••Fig. 3: Arrangement of the cement blocks inside the autoclave

process; it depends upon the injection rate and the environment surrounding the wellbore. Special cements such as cements with high alumina content can withstand harsh environment, but the high cost of these cements made operators chose simple Class G cements.

Researchers, such as Duguid et al [4] has already shown the effect of cement corrosion in carbon dioxide sequestrated abandoned wells. The result showed a complete disappearance of calcium hydroxide from the cement mold in 7 days. All of the experiments conducted by the researchers followed a pattern where the medium contains a pH range of 5-6 and 2-4. Under this condition it is quite obvious to get a high damage of cement in a shorter period of time. In this paper the author considered a more nominal scenario and checked out the effect of corrosion in the cement.

Up to the depth of 8000ft/2440m API recommended Class G cement is used for wellbore cementation. Class G cements were also used in this experiments, two additives were also used to compare its effect with Class G cement. Cement blocks were prepared in a stainless steel mould Fig 1, the mold contains nine chambers with a area dimension of 5x5x5 cm.

Cement slurry were prepeared according to API 10 B standard [5], the slurry were then placed inside the mold. The cements with additives (WFK 1/2 and WFK 6/2) were first mixed with Class G cement for 10 minutes and then the slurry was prepared according API specification. For each timeline experiment fresh brine solution and cement molds were prepared.

After 24 hrs of pre-curing the cement blocks were placed inside the autoclave Fig 2 and the brine solution was then introduced. The brine solution was kept in a way that all the cement blocks are submerged under the brine solution. Pressurised carbon dioxide is then introduced from the upper section of the autoclave, the intended pressure of the experiment is 18 MPa. After completing the brine fillup and carbon dioxide pressurization temperature is introduced and increased till 100°C. Before and after each experiment pH and salinity was analysed to see the

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S. Manna, C. Teodoriu, K. R. Reinicke

••Fig. 3: Compressibility test apparatus.

effect of carbon dioxide absorption in the brine solution Fig 3.

Results After completion of the experiment with its intended time period cement blocks were taken out from the autoclave and compressive strength of the blocks were analysed. To get a comparable result, cement blocks which were kept in the atmospheric conditions were also tested. The instrument which has been used to carry out compressibility test is shown in Fig 4.

Compressive strength of cement blocks in atmospheric condition (under 5% NaClbrine solution) increased with time, where as for cements from auto clave showed opposite trend.

Class G compared to the additive cements (WFK ½ and WFK 6/2) shows a higher a compressive strength with time. But WFK 6/2 results fairly shows a common characteristics as Class G cement.

It is important to get the changes in pH after each experiment. It indicates the amount of carbon dioxide getting absorbed in the brine solution. The reaction of carbon dioxide with fresh water is higher than that with brine solution. The Na+ ions present in the brine solution rejects the carbonic ions to interact with the water molecule.

CO2+H2O‹-›H2CO3‹-›H++HCO-3 (Eq. 1) Carbonic acid is a weak acid and only 1 % of dissolved CO2 exist as H2CO3. The solubility of CO2 is especially sensitive to pH

Experimental study to analyze cement corrosion…

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••Fig. 5: Compressive strength of cement blocks under atmospheric condition.

••Fig. 6: Compressive strength of cement blocks after corrosion experiment.

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S. Manna, C. Teodoriu, K. R. Reinicke

••Fig. 7: Comparison of pH after each experiment.

of the water. This in turn depends upon the composition of the fresh water. If it contains carbonate minerals (and many do) this will be in equilibrium with the dissolved CO2 and will absorb or release CO2 depending upon the pH. The presence of cations in the water that form insoluble carbonates (mainly Mg2+ and Ca 2+) removes CO2 from the water.

The initial pH of brine solution was in a normal range, but during experimental condition (P=18MPa, T=100°C) the pH moves towards acidic zone. It has to keep in mind the pH measurements were taken after the brine solution was normalized to room temperature and pressure. It is known that pH varies in temperature, so this might not be the actual pH that formed inside the autoclave. To visualize the corrosion in the cement blocks phenolphthalein test were carried out in the cement blocks.

The cement blocks were cut into equal two half’s and then polished in a sand paper polishing machine. The inner part of the cement blocks were then painted with the solution and kept for drying.

The white zones in the cement blocks indicates acidic invasion. The middle and the lower part of the cement blocks shows no corrosion. The corrosion in the cement blocks were radially influenced, the acidic invasion can be seen all through the outer layer of the cement blocks. Class G cement shows a high resistivity of cement corrosion than the other two add-mixture cements. WFK 1/2 has a high swelling tendency when hydrated, this cause a micro annulus in the cement sheath. The swelling rate of WFK 6/2 is lower than WFK 1/2 which makes less micro annuli in the cement blocks. XRD analysis also confirmed this analysis; the upper swelling part of the cement blocks shows high percentage

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••Fig. 8: Phenolphthalein test on corroded cement blocks

of calcium carbonate (CaCO3), which indicates cement corrosion.

It is known that when the percentage of calcium hydroxide level from the cement surface lowers down, corrosion starts occurring. Calcium hydroxide gives a protective layer to the cement surface to overcome any chemical attack to the cement.

CO2 + H2O ‹-› H2CO3 ‹-› H+ + HCO-3

(Eq. 1)

Ca(OH)2 + H + HCO3 -› CaCO3

(Eq. 2)

C - S - H + H + HCO3 ‹-› CaCO3 + Amorphous silica (Eq. 3) XRD analysis on the corroded cement also indicates cements with additive WFK 6/2

30 Papers have a fairly higher percentage of calcium hydroxide than pure Class G block in the upper layer.

Conclusion The experiment conducted above can clearly derive that cement degradation is a long and slow process. It all depends upon the rate of carbon dioxide dissolution in the brine solution. It has been seen that the compressive strength of the cement blocks increase in the first 10 days but it clearly starts declining after a longer

S. Manna, C. Teodoriu, K. R. Reinicke period of time. As this is a batch process it is hard to analyze the effect of cement corrosion in a continuous carbon dioxide injection process. It is well known from other authors work that pH of the brine solution increase when carbon dioxide is injected continuously, as it is much more obvious for a field’s perspective. This experiment simulates when the field is completely injected with carbon dioxide and plugging is performed for abandonment. But the shear drop in compressive strength of the cement indicates that there might be a plausible CO2 leakage from the cement plug and the casing interface.

References 1. http://tonto.eia.doe.gov/oog/info/twip/twip.asp 2. Experimental Study of Stability and Integrity of Cement in Wellbores Used for CO2 Storage by Jose Condora,b*, Koorosh Asgharib 3. Krilov, Z.; Loncaric, B.; Miksa, Z. Investigation of a Long-Term Cement Deterioration Under a High Temperature, Sour Gas Downhole Environment. Paper SPE 58771 presented at SPE International Symposium on 4. Formation Damage Control, Lafayette, Louisiana, 23-24 February 2000.

5. Duguid, A., Radonjic, M., Bruant, R., Mandecki, T., Scherer, G., Celia, M., Effect of CO2 Sequestration on Oil Well Cements; paper presented at GHGT7 Conference, Vancouver, Canada, 2004.

6. API Cementation Specification.

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Bartłomiej Kolasa

Extended Reach Drilling (ERD) technology overview

Abstract The purpose of this paper is to give a brief overview about ERD technology to the students.

This article is focusing on the most challenging and troublesome issues during the whole process of designing and drilling those type of wells. The aim is to familiarize students what are the hazards during ERD operations, and what are the measures and solutions which need to be implemented to successfully complete the extended reach well (ERW), reducing Non Productive Time (NPT) and costs in this process.

Introduction Extended Reach Wells (ERW) are those wells where the wellbore is kicked off from the vertical section near the surface, inclination is built to allow sufficient horizontal displacement from the surface to reach the target zone some distance away, and the angle is again built to near horizontal. Moreover ERD wells are those which horizontal displacement / TVD

(True Vertical Depth) ratio is greater than 2. Some wells are drilled horizontally from the first kick however long horizontal departure can cause series of problems in life cycle of well resulting in NPT (non productive time) or even abandonment.

Hazards and problems Using ERD technology is very difficult and almost impossible to apply conventional

32 Papers techniques and technologies to complete ERW. Taking under consideration drilling ERW several of factors need to be considered in order to achieve desire result. The majority of the ERD’s problems are related with: »» Hole cleaning; »» Drilling Fluids; »» Wellbore stability; »» High torque and drag; »» Not sufficient Weight On Bit (WOB); »» Casing Running; »» Well control; »» Stuck Pipe; »» Measurements while drilling; »» Trajectory Profile.

Hole cleaning Hole Cleaning Management In an inclined well-bore it is been found that at a certain deviation or sail angle, some of the drill cuttings being transported back to the surface by the drilling fluid and some of them fall out of the main flow and settle on the lower portion of the bore-hole. This phenomenon is more likely to occur in highly inclined section, especially greater than 65º and in long horizontal departures, like ERD. These cuttings interfere with the drilling process

Bartłomiej Kolasa and especially with the rotation of the rotating drillpipe which also lies on the low side of the bore hole.

RRS – Rotary Steerable System is technology that enables full three dimensional drilling controls to be performed while drilling with continuous drillstring rotation from surface and thus no slide drilling is necessary. A special Bottom Hole Assembly (BHA) component known as rotary steering device is necessary to perform the above-mentioned task. Rotary steerable systems offer the following advantages over the slide drilling: »» Fewer trips are required when using RSS. RSS uses fixed cutter bits unlike the other systems, which used tricone bits for directional control reasons. The longer life of fixed cutter bits results in more footage per bit and thus fewer trips for bit change; »» Continuous rotation at higher speeds results in very efficient hole cleaning; »» RSS can drill nearly all the required section trajectories using a single BHA design. Reduced tripping activity can be measured by comparing the footage drilled vs. the total amount of pipe tripped over the course of the project; »» Drilling with RSS results in a more ingauge hole than drilling with other systems. Thus, this results in lower volumes

••Fig. 1. Trajectory of 11-km ERD Well at Wytch Farm [9];

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••Fig. 2. Geo-pilot RSS System by Halliburton [22]

of drilled cuttings waste and lower drilling fluid losses. Thus, RSS offers an environmental benefit, which is a major reason of concern in ERD wells; »» Better Rate of Penetration (ROP) can be achieved with RSS due to less effect of torque and drag. In sliding drilling the most important is the mud motor must be oriented in a particular direction. In ERD wells to rotate the drillstring at the bottom several revolutions are to be made, hence it’s quite challenging to set the mud motor in place; »» Continuous pipe rotation, smoother trajectory due to less effect of torque and drag results in reduce stuck pipe and lost in hole (LIH) incidents; »» The sliding friction factor (FF) is usually in the range of 0.3 to 0.5. When the drillstring is rotated, the drag forces are greatly reduced and the friction factor is between 0.03 and 0.07 [4].

Cuttings Bed Impeller One of the biggest problem while drilling ERW is the hole cleaning issue, due to cuttings which are settled on low side of the well building the cuttings bed. To overcome this problem it is known to fit one or more cutting bed impellers to the drillpipe. The Cutting Bed Impeller (CBI) is a downhole drillstring tool intended for use in deviated wells where excessive buildup of cuttings causes drilling problems. The CBI is an integral drillstring component consisting of a short mandrel with

••Fig. 3. Cutting Bed Impeller by PDC Company with cross-section [23]

34 Papers no moving parts, shaped in such a way as to simulate any cuttings which have a tendency to settle out of the mud in the high angled sections of the wellbore. The high angled sections could be inside the casing or in open hole: the tool is adaptable to suit all borehole environments and only a small number of tools are required to successfully perform the task of maintaining a clean borehole free of cuttings debris and eliminate the risk of stuck pipe and casing.

Shown below is a typical case where cuttings have fallen out of the mud and have come to rest just below the build section.

This build up of cuttings beds can have serious effects on the drilling operation.

The most effective spacing of the CBI tools is normally between 90m and 150m throughout the tangent section, which will ensure that the cuttings are re-agitated and re-introduced to the mud flow.

Bartłomiej Kolasa typically only 15 to 20 CBI tools are required to manage the hole cleaning.

Near bit Reamers are concentric reaming tools that can be run anywhere in the BHA to increase the hole diameter.ERD technology often encounter a tight hole problem, meaning the drilling hole is smaller than bit, which is also known as undergauge hole. It has been also proved that enlarged hole prevent settling cuttings in the hole and help move them to the surface. NBR tool can be activated while drilling to enlarge the borehole up to 20% of the pilot hole diameter. It can be used behind the drill bit or further up to BHA in RSS system. A larger hole can improve circulation, allowing extra casing overcome swelling and moving formation problems.

The NBR tool operates solely on hydraulic bore pressure. A minimal increase in internal pressure acts on the flanges, breaks the shear pin and forces the pistons to move radially. Return springs close the pistons when flow decreases.

Drilling fluids The following factors should be considered while making a choice of drilling fluids for the ERD wells:

•• Fig. 4. Placement of CBI tools [23]

The Flow Pattern of the returning mud around the CBI tool annulus has been optimized to ensure maximum lifting of cutting debris from the low side of the hole.

The benefit to the operator is that only a small number of those tools are required to ensure effective hole cleaning throughout the entire hole section. For most wells

»» Equivalent Circulation Density (ECD) Management; »» Hole Cleaning; »» Torque and Drag; »» Borehole Stability; »» Lost Circulation.

Moreover, due to the stringent environmental conditions, the industry is going on for the development of more efficient water-based mud, in conjunction with

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••Fig. 5. Near Bit Reamer Tool by Halliburton [22]

some suitable lubricants, to replace the invert emulsion mud.

lations, then have been now replaced by the water based mud.

Invert emulsion mud had been the priority for drilling wells due to their greater lubricity and for preserving hole stability.

Moreover, lower torque, drag and ECD have been experienced by the use of invert emulsion mud. Thus, invert emulsion mud prove to be a good choice for ERD wells, but due to the environmental regu-

The most suitable water based mud currently available for ERD drilling, when shale inhibition is required, are potassium based, non dispersed, polymer mud containing glycol or silicates. When inhibition is not required, low solids polymer formulations or mixed metal silicates may be used [4] .

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Wellbore stability During planning ERD wells several of factors need to be considered, including casing seat depths, avoiding too long open hole sections. Long open hole sections lead to long-time open hole exposure to the circulated mud, which may lead to wellbore collapse. Also, the length of the open hole sections usually increases the risk of mud circulation losses.

ECD Management The simple principle of keeping the ECD below fracture gradient should be applied, but this can be more difficult than it sounds. To give an idea of the scale of the problem in Wytch Farm wells were typically drilled using 1.25 sg drilling fluid in 12 ¼" hole but as a result the ECD was high as 1.5 sg. Similarly 1.0 sg drilling fluid in 8 ½” hole results in ECD’s of 1.3 sg.

The number of factors affecting ECD is astounding and includes: drill pipe configuration, mud weight, mud rheology, flow rate, string RPM, hole cleaning efficiency and trip speed.

High torque and drag Torque management When the drill string is rotating, torque is seen at the surface. This torque is a function of the geometry of tool joints in the drill string and stabilizer blades in the BHA. The amount of drag from these components is accounted for in a rotating friction factor, which ranges from 0.15 to 0.35.

The torque of 58.3 kNm was used to drill the ERW in the Captain Field.

Bartłomiej Kolasa Sand Paper Effect ERD wells with long sections of casing at inclinations above 40º quickly acquire a thin layer of cuttings on the low side of the casing. The cuttings act like sandpaper, greatly increasing the friction factors.

The sand paper effect is dependent on the type of formation, occurring more in abrasive sands and less in shaly formations. It is quite probable that this sheath cannot be eliminated, but it could be effectively reduced. At the end of a bit run, circulating and/or back reaming should be used to clean the open hole.

To reduce the torque losses the following application should be considered: »» Mechanical tools to reduce torque/drag in casing, including sleeve, roller, bidirectional roller and non-rotating drillpipe protectors - mechanical torquereducing tools in cased hole. High side loading and abrasion of sand on the steel alloy need to be considered; »» Use of lubricants; »» Extra weight near the surface. The addition of drill collars at surface to provide extra weight for pushing power can be used for sliding drilling; »» Use of 4-in drill pipe near total depth (TD). Smaller diameter drill pipe may be used in the deeper, high angle sections of ERD wells to reduce torque, drag and ECD. Non-rotating sleeve type Spiro-Torq – Drilltech Group The Spiro-Torq®s tools were proved to reduce the torque during drilling ERW. Those tolls were placed (one tool per stand of drillpipe (~28m, 18m)) to cover the zones of high side forces, with additional tools placed above these zones to

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provide continuous coverage during the bit run.

especially important with chrome alloys in sour gas wells.

A distinct advantage of the NRST SpiroTorq®s was their ability to withstand the open hole environment without harm.

The long bit run necessitated movement of a portion of the tools into the open hole. Any other type of device would have required special trips to be made to displace tools away from the casing shoe (with consequent enormous wastes of rig time and money). The use of a low coefficient of friction chromium alloy bearing surface also precluded any limitation to rotary speed of the drillpipe, essential to ensure efficient operation of the Rotary Steerable System.

DSTR Tools are placed at every third joint at 30m intervals. In tripping out, the DSTR tool remains a part of the string and does not require removal, so the drill string is

In total 141 NRST Spiro-Torq®s were deployed in the string, with Torque reduction of around 23% observed.

•• Fig. 6. Non-rotating sleeve type Spiro-Torq [24]

Metal recovery at surface was reported to be negligible. Upon completion of drilling activity, a caliper tool was run, confirming wear on the 9 7/8-in of 10%. Pressure loss due to each tool in the annulus was measured at about 0.1 psi.

••Fig. 7. DSTRTM tool by Halliburton [22]

back-racked conventionally on the rig floor.

The DSTR tool is positioned between connections of the drill string, enabling freer rotation of the drill string by lifting it off the side wall at the radius section of the hole. The DSTR tool has provided torque reductions of up to 40%. Max side load capacity and friction coefficient of DSTR tool is equal respectively 3182 kg and 0.01.

High Torque Drill Pipes

Drill String Torque Reducer by Halliburton

Till now, ERD wells were drilled with either 5 ½ in. or 6 5/8 in. or a combination of both. But due to the problems, which arise due to the above drill pipes, the industry is now turning to 5 7/8 in. drill pipes.

The DSTRTM tool is a highly effective tool for reducing torque resistance in deviated holes. It allows freer rotation of the drill string at the dogleg, which adds power to the bit, increases rate of penetration and decreases fatigue of the drill string and rotary equipment. The DSTR tool also minimizes casing wear and casing failure,

The hydraulic performance of 5 ½ in. drill pipe becomes a major limitation in ERD wells resulting in poor cuttings removal, slow penetration rates and diminished control over well trajectory. On the other hand he 6 5/8 in. drill pipe is difficult to handle and requires more physical space on the rig.

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••Fig. 8. eXtreme Torque (XT) in the power-tight make-up position. The secondary torque stop increases the torsional strength compared to a standard API tool joint connection [16]

The 5 7/8 in. pipe provides 16% more ID flow rate than 5 ½ in. pipe, reducing pressure losses up to 28% [4].

Realizing the full potential of 5-7/8 in. drill pipe requires a high performance tool joint connection. A second-generation double-shoulder tool joint connection, optimized for 5-7/8 in. drill pipe, provides exceptional torsional strength combined with a streamline configuration.

When drilling ERW high torque need to be considered, and special drill pipes connections should be used in order to transmit and withstand the harsh conditions. For this high demands the special connection was design achieving the dimensional and performance objectives for the 5 7/8 in. drill pipes. The eXtreme Torque (XT) is a second generation double-shoulder connection. The eXtreme Torque connection design evolved from the design of the HIGH TORQUE (HT) connection. Figure

••Fig. 9. Comparison of eXtreme Torque (XT) and HI TORQUE. The flatter taper of XT increases the secondary shoulder area resulting in more torsional capacity [16];

Bartłomiej Kolasa 9 shows a comparison of XT and HT. The thread taper of the XT connection was flattened to increase the area of the secondary torque stop resulting in increased torsional capacity. HT provides an approximate 40% improvement in working torque compared to an API connection of the same OD and ID dimensions and XT provides approximately 30% more working torque capacity than HT connection [16] .

Not sufficient weight on bit (WOB) WOB Management Drilling shallow ERD horizontal wells in which the ratio of displacement to TVD is greater than 3:1 poses difficulties in maintaining enough weight to push the drill string down towards ultimate TD. The TVD component of the drill string trajectory supplies all the weight to push the bit out large displacements. If the drag forces are large, then more weight is needed. Drag forces are much higher when the drill string is not rotating. The sliding friction factor is usually in the range of 0.3 to 0.5.

The sliding friction factor when the drill string is rotating or translation FF is between 0.03 and 0.07.

To better understand this problem let’s consider this scenario: Well with TD of 3166 m with displacement/TVD ratio of 2.82. The horizontal 8 ½” section would be drilled with a steerable motor. The Torque and Drag (T&D) analysis indicated that a three-tier tapered drill string would be needed to effectively slide to TD with 2.3 tonnes of WOB. The tapered drill string from the bit consisted of 610 m of 5” 29 kg/m S drill pipe, 1220 m of 5 ½” 36.75

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Thrusters generate weight-on-bit by using drilling fluid hydraulics. The pumpopen behavior of thrusters de-couples the lower part of the bottom hole assembly from the drillstring, and in so doing provides a constant, controllable WOB that dampens out axial vibrations and shocks [4].

The idea behind the thrusters is to mechanically decouple the bit from the drillstring, so that WOB and thruster stroke length are independent from each other.

Such behavior can be found on a hydraulic cylinder as shown on the fig. 10.

••Fig. 10. Scheme of Thruster [17]

kg/m S drill pipe followed by 5 ½” 90.78 kg/m of heavy weight drill pipe (HWDP) to the surface. The sliding hookload or slackoff weight would approach the rig block/ top drive assembly weight of ~60 tonnes.

This meant that the entire drill string was in compression and that the neutral point was approaching the block. The block cannot be put in compression because damage will occur to the top drive main shaft bearing assembly. Friction factor were as followed: friction factor for casing 0.29 and friction factor for open hole 0.57 - 0.63.

••Fig. 11. Thruster Stages [18]

An increased pressure drop across the thruster leads to an increased WOB, and the WOB is proportional to the standpipe pressure. Relationship in case study proves that increasing Stand Pipe Pressure (SPP) by 6.9 MPa resulting in increasing WOB by 2 tonnes.

The piston is pressed downward by the thrust force Fthr, which is independent from the stroke length and a function of the pressure p and the cross sectional area of the piston A. The down thrust created by the system is only a function of pressure drop and geometry. As the pressure drop described the total pressure drop from the inside of the thruster to the outside (annulus), all components that are located below the thruster contribute to the down thrust. Depending on the movement of the sleeve towards the choke spear, the pressure drop across

••Fig. 12. Tandem Thruster [17];

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the thruster is larger or smaller, resulting in stages of more or less thrust force and therefore more or less WOB. Due to limited tool size, an increase of the sealing diameter (resulting in a more powerful thruster) is not possible. Therefore, a more powerful thruster version was realized by installing a second piston on top of the standard piston. At a given pressure drop across the system, such a tandem thruster generates about 50% more thrust than a single thruster.

When using a mud motor, high WOB need to be applied to the BHA, furthermore the all kinds of vibrations will appear due to lack of rotating. Thrusters significantly reduce the vibration, hence the life of string will extend, causing reduction in costs.

Other advantage is increasing ROP of drilling, thus reducing the time of drilling.

Case histories show us that optimized thruster systems lead to better drillstring dynamics, resulting in increased BHA life time (fewer round trips), better directional behavior and increased penetration rates.

Bartłomiej Kolasa

••Fig. 13. Example of thruster’s relation: Flow rate vs. WOB

Casing running Casing running limitations in ERD wells are well known and are related with high angle and enormous horizontal departure causing those problems. It is almost impossible to run the casing to the total MD – Measure Depth (e.g. 10 km) without the special measures. The high drag forces generated by running the casing efficiently reduce the hookload, eventually causing the “negative-weight”, which means that additional weight need to applied at the surface in order to complete the running process.

“Point” - Depth of No Return Depending on the magnitude of drag, there will be times when a particular length of casing is run into the well that cannot be pulled out without violating some design constraints. The Point of No Return is the length of pipe that first causes the Non Return Load Line to exceed the pipe yield strength (thread or

Extended Reach Drilling (ERD) technology overview

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••Fig. 14. Depth on No Return; Results were calculated using Microsoft Office Excel Software

body yield). It can be expressed graphically [see: Fig].

Casing Flotation Running 9 5/8” casing into the hole departure couple of kilometres became difficult.

It was analyzed that even with full weight from the travelling block, the drag would not allow to run the casing. Casing flotation is the method, which can get the casing to the total depth. In casing flotation, casing is not filled as each joint is run into the wellbore, as is done in typical casing operations. The goal is to have the casing close to the naturally buoyant, so it becomes virtually weightless in the mud, and drag is minimal. In a long extendedreach section, an entire air-filled casing string can become positively buoyant

and resist being pushed farther into the well. Thus, partial casing flotation should be considered, dividing the casing string into two sections; the upper section filled with mud and the lower section filled with air or nitrogen. Thus, double flotation collars should be used. The section filled with mud is in the vertical section of the well and provides weight to help push the lower, buoyant casing into the well.A shear-out plug separates the air-filled and mud-filled sections of casing. The plug holds the mud in the upper section but can be opened with applied pump pressure to circulate fluid through the entire casing string.

To handle positive casing buoyancy safely, a push-tool was installed below the topdrive on the rig. This tool engaged over

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••Fig. 15. Partially floated 9 5/8” casing. The bottom section of casing, containing air, remained neutrally buoyant to allow the casing to slide more easily along the well path. The mud-filled upper section provided the weight necessary to push the entire string to bottom. Once the casing was landed, pump pressure was applied to shear the plugs in the flotation collars and allow circulation [7];

the box connection of the casing and allowed the full weight of the topdrive and blocks to be applied to the string. A set of bi-directional, hydraulic, flush-mounted slips held the buoyed casing in the hole.

The slips were anchored to the rotary table and provided the necessary holddown force on the casing.

On the graph below we can identify the problem of “negative weight” (red curve) during tripping in, which in order to run the casing to the desired depth requires an additional weight on the surface of 17 tonnes. Without partial flotation the maximum depth which can be reached would be 8250 m instead of 9000 m.

Advantages: less drag and therefore possibility to run the casing to the desired depth;

Two additional blue curves represent the results and benefits of using partial flotation technology. If partial flotation would be applied in this case, putting 975 m of air in the bottom section of the casing, no additional weight on the surface would be necessary.

Disadvantages: no possibility to circulate and well control issues; Care: when designing for intermediate casings loads (using the load criteria), collapse should be checked; assure that hook load is always in tension, and above an acceptable limit while running the casing into the well [1].

Well control Gas kick is one of the most dangerous situations which can cause a blowout of the well. ERD wells are more prone to kicks and lost circulation due to the large

Extended Reach Drilling (ERD) technology overview

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••Fig. 16. Hook Load graph showing “negative weight” reduction due to partial flotation. ERW with horizontal displacement / TVD ratio equal 3; Results were calculated using Landmark Software - WellPlan™

distances up to, which they are drilled.

Though, ERD wells have some advantages when the well takes a kick because gas migration rates are slower. Gas migrates at a rapid rate when the inclination is 45° and its migration rate decreases as the well becomes horizontal. As long as the kick is in the horizontal section, the shut in casing pressure and shut in drill pipe pressure are about the same because hydrostatic pressure on both sides of the Utube is the same.

circulation replaces the old mud with the new kill mud [4].

Kick Volume. If kick occurs while drilling the horizontal interval, the kick volume will be several times greater than encountered while drilling vertically. When such a large kick volume reaches the vertical section of the well during kick circulation, the induced pressures on the casing shoe and the surface equipment could easily exceed the allowed pressures;

Driller’s method should be used to control the well. The driller’s method uses the old mud to circulate out the influx and requires two circulations to kill the well. The first circulation displaces the influx with old mud from the pits, and the second

Kick detection time. Unlike kicks in vertical wells, kick detection in horizontal wells can be delayed significantly owing to possible enlarged or wavy sections that allow the accumulations of gas pockets. Thus, the sudden increase in mud volume on

44 Papers the surface is not a true indication of the total gas influx into the annular space; Shut-in pressure. If gas kick is taken in vertical wells while drilling, the shut-in casing pressure is always greater than the shut-in drill pipe pressure owing to the gas influx that displaces part of the mud in the annular space. However, when a kick is taken during drilling into the horizontal section and the gas is contained within that section, the shut-in casing and drill pipe pressures will be the same [11].

Special consideration during flotation Casing flotation techniques may bring series of consequences, like causing a kick, due to leaks of flotation equipment.

When using casing flotation these leaks may cause a rapid drop in annulus fluid level as the casing fills though the leak.

The resultant loss of hydrostatic pressure may well induce a kick or result in hole collapse. Careful selection and pressure rating specification of float shoes, collars and casing joints are important for selective flotation.

Stuck pipe Stuck-pipe is one of the most important issues in the oil-industry. Drilling a well requires a drill string (pipe & collars) to transmit the torque provided at the surface to rotate the bit, and to transmit the weight necessary to drill the formation.

When the drill string is no longer free to move up, down, or rotate as the driller wants it to, the drill pipe is stuck. Sticking can occur while drilling, making a connection, logging, testing, or during any kind of operation which involves leaving the equipment in the hole. In other words, the drill string is stuck when the static

Bartłomiej Kolasa force necessary to make it move exceeds the capabilities of the rig or the tensile strength of the drill pipe. A stuck pipe can result in breaking a part of the drill string in the hole, thus loosing tools in the hole.

Generally the stuck pipe mechanisms can be divided in three groups: »» Hole Pack-Off (settled cuttings, shale instability, fractured formations, junk); »» Differential Sticking; »» Wellbore Geometry (key seat, undergauge hole).

In Extended Reach Wells the most serious and the most likely stuck pipe problems are related with settled cuttings, key seating, differential sticking and undergauge hole.

After borehole deviated above 60°, the borehole is unstable, easy to take a caved stuck. The drag friction force is heavy while long drill pipes weighted on horizontal borehole wall. The long section horizontal borehole concentrate pipe stuck risk, especially a differential stuck for in higher mud weight than common.

The drill pipes that deep in sands bed can absorb most jarring impact force though pipe joints can mitigate to be stuck in a degree. In a horizontal well pipe stuck, the jarring impact force can absorbed by hole wall quickly. If a short pipe freed in jarring, it still can get stuck again because it cannot be moved in enough clearance.

Key seating is caused by the drill pipe rotating against the bore hole wall at the same point and wearing a groove or key seat in the wall. When the drill string is tripped, the tool joints or the BHA are pulled into the key seat and become jammed. Key seating can also occur at the casing shoe if a groove is worn in the cas-

Extended Reach Drilling (ERD) technology overview

••Fig. 18. Cuttings Settling [20]

••Fig. 17. Key Seat [20]

ing. The best prevention action is to minimize the dogleg severity and performing reaming and/or wiper trips if a key seat is likely to be a problem.

In deviated wells cuttings and cavings settle to the low side of the hole and form layers called solids beds or cuttings beds.

The BHA becomes stuck in the solids bed.

There are several main reasons for solids not being cleaned out of the well bore.

These are: »» A low annular flow rate. »» Inappropriate mud properties. »» Insufficient circulation time. »» Inadequate mechanical agitation.

In 40-65 degree wells the cuttings bed will slide down the low side of the hole.

This can happen while pumping, not just when the pumps are off. In highly deviated wells of 65 degrees or more cuttings settle very quickly, in spite of high flow rates. This is known as avalanching [20].

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Jar Placement A drilling jar is a mechanical device used downhole to deliver an impact load to another downhole component, especially when that component is stuck. There are two primary types, hydraulic and mechanical jars. While their respective designs are quite different, their operation is similar.

Energy is stored in the drillstring and suddenly released by the jar when it fires. The principle is similar to that of a carpenter using a hammer. Kinetic energy is stored in the hammer as it is swung, and suddenly released to the nail and board when the hammer strikes the nail.

Jars can be designed to strike up, down, or both. In the case of jarring up above a stuck bottomhole assembly, the driller slowly pulls up on the drillstring but the BHA does not move. Since the top of the drillstring is moving up, this means that the drillstring itself is stretching and storing energy. When the jars reach their firing

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••Fig. 19. Placement of Jar in Extended Reach Wells [19]

point, they suddenly allow one section of the jar to move axially relative to a second, being pulled up rapidly in much the same way that one end of a stretched spring moves when released. After a few inches of movement, this moving section slams into a steel shoulder, imparting an impact load. In addition to the mechanical and hydraulic versions, jars are classified as drilling jars or fishing jars. The operation of the two types is similar, and both deliver approximately the same impact blow, but the drilling jar is built such that it can better withstand the rotary and vibrational loading associated with drilling.

Regarding the ERW drilling the accelerator is often used in conjunction with drilling jar to store energy that is suddenly released when the jar is activated. The energy provides an impact force that operates associated downhole tools or, in a contingency role, helps release a tool string that has become stuck. Depending on the operating mode, the energy in tension or compression can be stored by means of a mechanical spring or a com-

pressible fluid such as nitrogen gas. Accelerators should be selected on the basis of their compatibility with the jar to be used.

The accelerator incorporates a spring or compressible fluid to store energy for rapid release when the jar operates. The tool-string mass between the accelerator and jar is accelerated towards an impact that occurs at the end of the jar stroke. A weight bar can be included between the tools to adjust the characteristics of the impact force.

Measurment while drilling (MWD) MWD is a system developed to perform drilling related measurements downhole and transmit information to the surface while drilling a well. MWD systems can take several measurements like natural gamma ray, directional survey, tool face, borehole pressure, temperature, vibration, shock, torque etc. Some advanced

Extended Reach Drilling (ERD) technology overview MWD tools can even measure formation pressure and take formation samples (e.g.

GeoTap速 by Halliburton). The MWD also provides the telemetry for operating rotary steering tools (RSTs).

The measured results are stored in MWD tools and some of the results can be transmitted digitally to surface using mud pulsar telemetry through the mud or other advanced technology.

MWD tools are generally capable of taking directional surveys in real time. The tool uses accelerometers and magnetometers to measure the inclination and azimuth of the wellbore at that location, and they then transmit that information to the surface. With a series of surveys at appropriate intervals, anywhere from every 10 m to every 150 m, the location of the wellbore can be calculated.

Mud pulse telemetry This is the most common method of data transmission used by MWD tools. Downhole a valve is operated to restrict the flow of the drilling mud (slurry) according to the digital information to be transmitted. This creates pressure fluctuations representing the information. The pressure fluctuations propagate within the drilling fluid towards surface where they are received from pressure sensors. On surface the received pressure signals are processed by computers to reconstructs the transmitted information. The technology is available in three varieties - positive pulse, negative pulse, and continuous wave.

Positive pulse tools briefly close and open the valve to restrict the mud flow within the drill pipe. This produces an increase in pressure that can be seen at sur-

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face. Line codes are used to represent the digital information in form of pulses.

Negative pulse tools briefly open and close the valve to release mud from inside the drillpipe out to the annulus. This produces a decrease in pressure that can be seen at surface. Line codes are used to represent the digital information in form of pulses.

Continuous wave tools gradually close and open the valve to generate sinusoidal pressure fluctuations within the drilling fluid. Any digital modulation scheme with a continuous phase can be used to impose the information on a carrier signal.

The most widely used modulation scheme is continuous phase modulation.

Positive-pulse systems are more commonly used in current MWD and LWD systems, especially in ERW. This may be because the generation of a significant-sized negative pulse requires a significant pressure drop across the BHA, which reduces the hole-cleaning capacity of the drilling fluid system.

Drilling engineers can find this pressure drop difficult to deliver, particularly in the extended-reach wells for which the technology is best suited. Many different data coding systems are used, which are often designed to optimize the life and reliability of the pulsar, since it must survive direct contact from the abrasive, high-pressure mud flow.

Electromagnetic telemetry (EM Tool) In some cases, like underbalanced drilling, mud pulse telemetry can become unusable. This is because usually in order to reduce the equivalent density of the drilling mud a compressible gas is injected

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into the mud. This causes high signal attenuation which drastically reduces the ability of the mud to transmit pulsed data.

In this case it is necessary to use methods different from mud pulse telemetry, such as electromagnetic waves propagating through the formation or wired drill pipe telemetry.

EM Tools incorporate an electrical insulator in the drillstring. To transmit data the tool generates an altered voltage difference between the top part (the main drillstring, above the insulator), and the bottom part (the drill bit, and other tools located below the insulator of the MWD tool). On surface a wire is attached to the wellhead, which makes contact with the drillpipe at the surface. A second wire is

attached to a rod driven into the ground some distance away. The wellhead and the ground rod form the two electrodes of a dipole antenna. The voltage difference between the two electrodes is the receive signal that is decoded by a computer. The EM tool generates voltage differences between the drillstring sections in the pattern of very low frequency (212Hz) waves. The data is imposed on the waves through digital modulation.

Trajectory profiles Catenary Profile In the drilling industry, the length of the drillstring is much greater than its diam-

••Fig. 21. Typical Catenary Profile; Trajectories were calculated using Landmark Software - COMPASS™

Extended Reach Drilling (ERD) technology overview eter. The bending rigidity of the entire string is so negligible that it can be regarded as a flexible rope, cable, chain, or any other line of uniform weight that is suspended between two points assumes a shape called a catenary. In this case, the string itself assumes a catenary shape.

Theoretically, if the operator drills a well with the same catenary shape, a drillstring inside the well will have no contact with the borehole wall. Instead, the drillstring will tend to stand off the borehole wall, and the drag and torque applied on the drillstring or casing can be minimized.

A typical catenary profile is shown below.

It consists of four well sections: a vertical section to the kick-off-point (KOP), an initial buildup section to the start of catena-

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ry section, the catenary section itself, and a straight sail section to the target.

The first section can be inclined, as a slant rig may be used for land drilling. Generally, it is a vertical section. The initial buildup section is required because the catenary section cannot begin vertically. If a slant rig is used, this section can be eliminated and the rig must mast should be positioned at the exact inclination to enter the catenary smoothly.

It has been proven that most of the friction during drilling ERW is consumed by the very long horizontal section. Comparing those frictions to the friction generated by the catenary profile is minor, hence the overall benefits of applying a catenary wellpath for ERW is marginal.

References 1. Linton Jaffe, Eric Maidla, Rosemary Irrgang, Werner Janisch – “Casing Design for Extended Reach Wells”, SPE 38617; 2. Michael J. Economides, Larry T. Watters, Shari Dunn-Norman – “Petroleum Well Construction” 3. G. Rae, W.G. Lesso – “Understanding Torque and Drag: Best Practices and Lessons Learnt from the Captain Field’s Extended Reach Wells”, SPE/IADC 91854; 4. Adit Gupta – “Planning and Identifying Best Technologies for ERD Wells”, SPE/IADC 102116 5. M.L. Payne, D.A. Cocking, A.J. Hatch – “Critical Technologies for Success in Extended Reach Drilling”, SPE 28293; 6. M.L. Payne, Fereidoun Abbassian – “Advanced Torque-and-Drag Considerations in Extended-Reach Wells”, SPE Drilling & Compeltion, March 1997;# 7. Frank Alllen, Paul Tooms, Greg Conran, Bill Lesso, Patrick Van de Slijke – “Extended-Reach Drilling: Breaking the 10-km Barrier”, Oilfield Review; 8. Johan Eck-Olsen, Rune Haugom, Geir Loklingholm, Hakon Sletten – Statoil uses flotation of 10 ¾ liner to reach beyond 10 km in Gullfaks Field , Special Marine Edition; 9. Tony Meader, Frank Allen – “To the Limit and Beyond – The Secret of World-Class ExtendedReach Drilling Performance at Wytch Farm”, IADC/SPE 59204; 10. B.S. Aadnoy, V.T. Fabiri, J. Djurhuus – “Construction of Ultralong Wells Using a Catenary Well Profile”, IADC/SPE 98890;

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11. J.J. Azar, G. Robello Samuel - “Drilling Engineering”; 12. Xiushan Liu, Robello Samuel – “Catenary Well Profiles for Extended and Ultra-Extended Reach Wells”, SPE 124313; 13. Ma Shanzhou, Huang Genlu, Zhang Jianguo and Han Zhiyoung – “Study on Design of Extended Reach Well Trajectory”, SPE 50900; 14. R.T. McClendon, E.O. Anders – “Directional Drilling Using the Catenary Method”; 15. Chan L. Daigle, Donald B. Campo, Carey J. Naquin, Rudy Cardenas, Lev M. Ring, Patrick L. York – “Expandable Tubulars: Field Examples of Application in Well Construction and Remediation”, SPE 62958; 16. Michael J. Jellison, Mike L. Payne, Jeff S. Shepard, R. Brett Chandler – “Next Generation Drill Pipe for Extended Reach, Deepwater and Ultra-deep Drilling”, IADC 2002; 17. Matthias Reich, Friedhelm Makohl – “Drilling Performance Improvements Using Downhole Thrusters”, SPE/IADC 29420; 18. Bernd Schmalhorst – “Dynamic Behaviour of a Bit-Motor-Thruster Assembly”, SPE/IADC 52823; 19. AMOCO EPTG Drilling Technology Company – Training to Reduce Unscheduled Events; 20. Colin Bowes, Ray Procter - “1997 Guidelines & Drillers Stuck Pipe Handbook”; 21. Self Learning Course Anadrill - “Stuck Pipe Prevention”; 22. http://www.halliburton.com 23. http://www.pdc-uk.com 24. http://www.drilltech.com 25. http://www.glossary.oilfield.slb.com

Carrer Paths 51

Jacob Jagiełło, Daniel Dyndor (Sperry Drilling)

MWD Engineer

MWD is a shortcut from Measurement While Drilling. It is quite modern measurement technique, which can be launched without stopping drilling unit work, what saves time and finally – money. Man responsible for measurements and equipment is MWD – Engineer, of whom the article is. So what criteria you have to meet to get this work?

First of all – education.

Easiest way is obviously is majoring in petroleum or drilling engineering but can also finish the geology or some fuel and energetic faculty. Some companies require work experience in the oil industry in addition to or sometimes instead of diploma. However, work in the oil industry begins immediately after graduation with a long, arduous training that brings many benefits, theoretical and practical knowledge. Of course, initially starting as a field engineer generally and gradually appren-

ticed to the position of MWD Engineer, because you must know at least the basics when it comes to engineering principles and measurement while drilling. There is nothing surprising, considering that you will be entrusted with worth tens to hundreds of thousands of dollars measuring equipment.

Next stage – language.

Do not think that your national language will matter anywhere outside your country. Oh no! Without English you can basically forget about such work. It is one simple reason for that. Most of the time you will spend abroad and even if not, almost all business is dealt in English. But even if you are native speaker of English you should start to learn foreign languages.

German is very useful, especially in northwest Europe, Russian in middle-east region or Spanish and Portuguese in Latin America which presently is world richest

52 Carrer Paths area in crude oil. Unfortunately (or maybe oppositely?) employer likes to hire widely and highly educated employee, so that he will probably send you to the place, in which none of known to you languages will give you an opportunity to fluent communication. You will have to learn a new one. Hurray! It is a simple math. Language skills certificates primarily technical and business, depends from company position are very valuable additives to your resume.

Another vital skill is fluent computer dexterity, but nowadays that should not be a problem. Almost everyone got bigger or smaller contact with computer. It turns out to be very helpful for you in learning the handling quite complex and extensive software for receiving, analyzing the readings from the downhole equipment. You have to remember that presently every device is supported by computer, so if you are wet behind the ears when it comes to computers, better start to train.

Self-reliance is essential in this profession.

And I do not mean selfishness at work but the ability to cope with problems, solving them. As you know, not always have someone to help and sometimes befall you different problems or ambiguous readings. Then you better know what to do, whom to report, how to interpret and whether it is desirable to further drilling and that sort of thing. Unfortunately without your own accurate analysis, is rather hard to keep you on such a responsible position.

Stress resistance. Any job in drilling industry is full of stress while drilling, tough decisions, where each of them may become, financially, very expensive mistake. So you always have to think soberly, keep cool and not act impulsively. You better consid-

Jacob Jagiełło, Daniel Dyndor (Sperry Drilling) er longer or twice (but still very fast) decisions taken rather than lead to a situation that you would better prefer not to think about. Now you should definitely learn to master stress, which can often lead you to the inner panic, resulting improper decisions.

The employee of any drilling rig have to be independent, it also applies to the MWD Engineer. Remember however hierarchy in the company, the platform or rig. You work there in a group and thus, you are responsible for others. Please remember that you can consult decisions with more experienced workers or bosses, however, keep in mind the above mentioned independence. You cannot harass your superior with every small uncertainty.

What are the duties MWD Engineer?

The responsibility of the directional service engineer should be directional testing, assembly, installation of the collar and the provision of detection devices that is in the BHA. Day labor MWD Engineer – work in the directional service requires 100% of flexibility, because it is linked with frequent travel to the residence on the rigs where the customer orders the service or is it just DWD (Directional While Drilling) sensors that are additional to the family of FE (Formation Evaluation): Resistivity, Gamma, PWD (Pressure While Drilling) ect. As an engineer after reaching the rig you have to do so. Rig Up – run the computers (sometimes everything from scratch: monitors

MWD Engineer of boxes, cables, additional equipment that allows connecting computers with MWD-system), there are always two computers (main and back up). Then you start the submission and testing MWD – sensors, and other parts depending on the system. Two popular data transmission systems currently used by the services Positive Pulse is where the data are transmitted by the drilling fluid – pulser sends a pulse sequence that causes the change of pressure in the pipe drilling muds – and between the pumps and top drive (or kelly), you mount Tranducers, that enable recive pressures changes. Transucers are connected to the computer, which has the ability to detect external signals, and thus obtained the information from the bottom during drilling. The downside of such a system is that, in order to have the info you need to pump the mud.

The second system is ElectroMagnetic EM, which transmits electrical signals via the rock – in this system are used Antenna (two) one to send data, the other for the reception – plus is that, you do not have to pump muds (another way of transmission) and frequency, even a dozen times faster comparing to Positive Pulse.

After assembly and tested in the MVD installs sinker (They are most often non-magnetic weights special NMDC – Drill Collar NonMagnetic) and venture into wire rig.

Start of drilling is beginning of detection.

In directional drilling, measurements of the drill bit location are getting every connection that is often at about 20 meters (two pipes the so-called stand (in Polish belt.) Sending information to the MWD in order to sent us the measurement (socalled Full Survey) is made by switching on and off pumps ( for Positive Pulse) or send downlink (to EM). In the directional measurement you get inclinations and az-

Carrer Paths 53 imuth, and depth of the type on which the measurement was made (depth survey).

Shift on the rig takes 12 hours. You work together with the DD (Directional Driller).

The so-called Rig Crew DD is 2 and 2 MWD Engineers.

What’s after work and not only?

You live in a hotel near the rig, employer cares only about what you do during working hours (means, do you work efficiently), but when 12 hours of an interesting struggle end, do what you want. Visit places, there is a possibility you will be located in a privileged location, say, Malaysia or Norway. You can use earned money, spend it on parties, travel, brand-name stuff either... submitted to the socks, save for some worthy cause, which you plan to make after returning home permanently.

But who, after such hard work put aside everything to your account and does not want to for example – swim a scooter or skydive? And if you have a family, you take them to an entertainment center, gourmet restaurant, wherever you want. Now you can afford it. The pay rates you can find in 2010 SPE Salary Survey and I think every young man who realizes the money is necessary for living will be satisfied. Your salary will be divided in two sections base pay and daily rate for every day you will spend on rig! In addition to twelve-hour work day you have an average of 15 days a month off (work in 2 : 2 mode) which gives near 180 free days a year and you are entitled to annual holiday. Are you considering what you will be doing at this time? Calmly, strike a happy medium. Rest from work, but also take care of your retirement, in the end the job ends someday and you will run out of such huge monthly money amount. Think about your own business, funds already have.

Conference 59

Student Technical Conference – Wietze 2010 Pawel Wilaszek

This year in October together with my friend Anna Ropka I had a chance to attend a Student Technical Conference organized by German Section SPE. The conference took place from 7th till 8th of October in Wietze, Germany. Wietze is a small town located nearby Hanover. After a long journey and a couple of adventures we finally reached our destination. We stayed at Buskes Hotel, which was located just 20 minutes of walking from the Oil Museum, where the conference took place.

The conference was great chance for students to present results of their research.

Presenters and poster authors came from five different countries like Germany, Poland, Denmark, Hungary and Romania.

Our presentations concerns drilling mud.

Anna was speaking about flocculation software and I gave a presentation about drill-in mud. I must personally admit that

every work presented there was well prepared and very interesting what made this conference standing on a really high level.

Except of giving presentations we were able to talk to industry representatives from such companies like Weatherford, Exxon Mobil or Baker Hughes. First day of the conference ended with official dinner which allows us to meet with all the conference guest and talk to them in very friendly atmosphere. The second day of the conference brought very interesting lecture concerning unconventional gas, what is really important to us considering future production of gas from shale in Poland. To summarize – we are both very satisfied with the conference – we brought back new experiences, made their new friends and convinced ourselves once again that drilling industry is the best way for our future.