Teesside University

Teesside University School of Science and Engineering MSc. Petroleum Engineering

Enhancing Directional Drilling Using Wired Drill Pipe Telemetry By: Nithin Mankara Sadanandan Student No: P4223558 Supervisor: Dr Sina Rezaei Gomari A thesis submitted in partial fulfilment of the requirements For the award of Master of Science Degree in Petroleum Engineering September 2014

Teesside University

Enhancing Directional Drilling using WDP

Declaration of originality This is to certify that the work is entirely my own and not of any other person, unless explicitly acknowledged (including citation of published and unpublished sources). The work has not previously been submitted in any form to the Teesside University or to any other institution for assessment for any other purpose.

Signed _________________________________________________

Date ___________________________________________________

Teesside University


Dedication I dedicate my dissertation work to God Almighty, family, and friends.

ABSTRACT A telemetry system is used to make bi-directional communication between downhole tools such as RSS, MWD and the surface, which assists to make real-time decisions and mitigate problems. Apparently, directional drilling involves several problems as they are implemented in high angle, harsh and extended reach environments. Even though RSS and MWD can deliver high performance, the total performance of the system depends on the speed of the telemetry system. Currently, mud pulse telemetry system is being used which provides only low bandwidth and has several other drawbacks as well, which makes it incapable of mitigating the problems encountered. Hence, a new high speed telemetry system is required to lessen these problems. Wired drill pipe telemetry system, which uses a wired coaxial cable embedded into the conventional drill pipe delivers approximately 1000 times faster data rate. The main aim of the study was to demonstrate how wired drill pipe became a drilling enabler in harsh environments. For this purpose, four case studies were examined having different scenarios where wired drill pipe telemetry was employed in order to eliminate the problems associated with MPT and enhance drilling which in turn will reduce the non-productive time (NPT) associated. Based on the case studies discussed, the conclusion can be drawn that, wired drill pipe telemetry demonstrated good performance and mitigated severe challenges when used in combination with drilling tools and logging systems. However, the reliability of wired pipe is still an issue and hence has to be used in conjunction with mud pulse telemetry to provide back-up and hence attain full telemetry redundancy.

I

Teesside University


Table of Contents ABSTRACT................................................................................................................... I List of Figures .............................................................................................................. V 1. INTRODUCTION .................................................................................................. 2 2. LITERATURE REVIEW ...................................................................................... 5 2.1. Directional Drilling ................................................................................................ 5 2.1.1 Principles of Directional Drilling ........................................................................ 6 2.1.2 Reasons for directional drilling............................................................................ 7 2.1.3 Techniques in directional drilling ...................................................................... 11 2.1.3.1 Whipstock Method .......................................................................................... 11 2.1.3.2 Jet Deflection Method ..................................................................................... 12 2.1.3.3 Steerable Motors ............................................................................................. 13 2.1.3.4 Rotary Steerable Systems ............................................................................... 16 2.2. Measurement While Drilling ............................................................................... 19 2.2.1 Formation Evaluation MWD ............................................................................. 20 2.2.1.1 Natural Gamma Ray ....................................................................................... 20 2.2.1.2 Formation Resistivity...................................................................................... 21 2.2.1.3 Neutron Porosity ............................................................................................. 21 2.2.1.4 Formation Density .......................................................................................... 21 2.2.2 Drilling Performance MWD .............................................................................. 22 2.2.2.1 Inclination ....................................................................................................... 22 2.2.2.2 Azimuth .......................................................................................................... 22 2.2.2.3 Toolface .......................................................................................................... 22 2.2.2.4 Pressure Transducer ........................................................................................ 22 2.2.2.5 Temperature .................................................................................................... 22 2.2.2.6 Downhole Torque on Bit/ Weight on Bit........................................................ 22

II

Teesside University

Enhancing Directional Drilling using WDP 2.3.1 Mud Pulse Telemetry ......................................................................................... 24 2.3.1.1 Surface System and Sensors ........................................................................... 27 2.3.1.1.1 Sensors ......................................................................................................... 28 2.3.1.1.2 Surface Systems ........................................................................................... 29 2.3.1.2 Mud Pulse Signal Generation ......................................................................... 29 2.3.1.2.1 Negative Pulse Generation........................................................................... 30 2.3.1.2.2 Positive Pulse Generation ............................................................................ 30 2.3.1.2.3 Continuous Wave Generation ...................................................................... 31 2.3.1.3 Characteristics of Mud Channel ..................................................................... 32 2.3.1.3.1 Signal Attenuation ....................................................................................... 32 2.3.1.3.2 Noise in the Mud Channel ........................................................................... 35 2.3.1.3.3 Interference of Pressure waves .................................................................... 36 2.3.1.3.4 Signal-to-Noise Ratio .................................................................................. 37 2.3.2 Wire Pipe Telemetry System ............................................................................. 38 2.3.2.1 Components of Wired Pipe Transmission Line .............................................. 38 2.3.2.1.1 Top Drive Swivel ......................................................................................... 39 2.3.2.1.2 Wired Telemetry Drill Pipe ......................................................................... 40 2.3.2.1.3 Signal Repeaters .......................................................................................... 43 2.3.2.1.4 Interface Sub ................................................................................................ 43 2.3.2.2 Advantages of Wired Pipe Network ............................................................... 44 2.3.2.2.1 Real Time Imaging ...................................................................................... 44 2.3.2.2.2 Drilling Parameters Optimization ................................................................ 44 2.3.2.2.3 ROP improvement ....................................................................................... 44 2.3.2.2.4 Improved Shock, Vibration and Stick-Slip Management ............................ 45 2.3.2.2.5 Hole Quality and Wellbore Stability Management ...................................... 45 2.3.2.2.6 Hidden Non-Productive Time Reduction .................................................... 46 III

Teesside University

Enhancing Directional Drilling using WDP 2.3.2.2.7 Lost Circulation Event ................................................................................. 46 2.3.2.2.8 Pore Pressure Prediction .............................................................................. 46 2.3.2.2.9 Reservoir Navigation ................................................................................... 46 2.4. Downhole Communication (Current Methods) ................................................... 47 2.4.1 Operation ........................................................................................................... 47 2.4.2 Survey ................................................................................................................ 48 2.4.3 Downlink ........................................................................................................... 49 2.4.4 Drilling Parameters Optimization ...................................................................... 49 2.4.5 Reservoir Navigation ......................................................................................... 50 2.4.6 LWD Formation pressure test ............................................................................ 51 2.4.7 Well control operations ...................................................................................... 51 2.4.8 Trouble Shooting ............................................................................................... 52 3. CASE STUDIES .................................................................................................... 53 Case Studies on Wireless Drill Pipe deployment in different fields........................... 54 3.1 Case study 1: Occidental of Elk Hills, Inc. (OEHI) in kern County, California (Allen et al., 2009)…. ................................................................................................. 54 3.2 Case Study 2: Offshore Trinidad Fields in Trinidad and Tobago (Edwards et al., 2013)………………………………………………………………………………....60 3.3 Case Study 3: Troll fields in Norway (Wolter et al., 2007) ................................. 64 3.4 Case Study 4: Southern Mexico (Dorel et al., 2013) ........................................... 65 4. CONCLUSIONS AND RECOMMENDATIONS.............................................. 68 5. REFERENCES...................................................................................................... 70

IV

Teesside University


List of Figures Figure 01: Using BHA to build or drop angle through calculated installation of drill collars and stabilizers……………………………………………………………………7 Figure 02: A directional well drilled underneath a salt dome………...…………….......8 Figure 03: Directional wells drilled underneath unreachable locations…………….......9 Figure 04: Multilateral wells drilled from a fixed platform………...……..……………9 Figure 05: Horizontal drilling……………………………………………………….....10 Figure 06: The method by which a whipstock enters the hole and starts drilling the slanted hole. The whipstock is removed when the drill bit is withdrawn………….......11 Figure 07: Jet bit for hole-deflection……..…………………………………………....12 Figure 08: Steerable motors…….………….………………………………………….14 Figure 09: Comparison of borehole quality created by steerable motor and RSS….....16 Figure 10: Push-the-bit RSS representing how the trajectory change is accomplished…………………………………………………………………………..17 Figure 11: Cross section of RSS showing movement of pad…………………………17 Figure 12: Drive shaft at offset angle to collar………………………………………..18 Figure 13: Evolution of directional drilling…………………………………………...19 Figure 14: Basic MWD system......................................................................................20 Figure 15: Gamma ray response based on formation …………………………………21 Figure 16: A typical mud pulse telemetry system. The mud-pulser is similar to the transmitter in the communication system, the mud filled drill pipe to the channel, and transducer mounted on the stand pipe to the receiver…………………………………...26 Figure 17: Block diagram of mud pulse telemetry system depecting the downhole and surface components……………………………………………………...……………..28 Figure 18: Generation of negative mud pulse signal…………………………………..30 Figure 19: Generation of positive pulse………………………………………………..31 Figure 20: Continuous wave signal generation…………………………………………32

V

Teesside University

Enhancing Directional Drilling using WDP Figure 21: Signal attenuation Vs depth for high frequency and low frequency telemetry………………………………………………………………………………..35 Figure 22: Reflection and transmission of pressure waves at a change in pipe crosssectional area…………………………………………………………………………...36 Figure 23: signal waves reflecting back due to the change in drill string diameter resulting in the production of echo which can interfere with the subsequent main signal………..37 Figure 24: Components of wired drill pipe telemetry system………………………….39 Figure 25: Top drive swivel sub………………………………………………………..40 Figure 26: Non-contact line coupler coils transferring data by induction………………41 Figure 27: The location of the conduit in the drill string……………………………….42 Figure 28: Double-shouldered pin tool joint cutaway view…………………………….42 Figure 29: fitment of inductive coils inside the shallow grove inside the secondary torque shoulder of the tool joint………………………………………………………………..43 Figure 30: Operating sequence for the survey clearly depicting the general time required for a survey taken by MPT……………………………………………………………..48 Figure 31: Plot of log image attained via wired drill pipe telemetry while using foam as drilling fluid…………………………………………………………………………….56 Figure 32: Downlink efficiency comparison during the project employing MPT and WDP in the same field………………………………………………………………….57 Figure 33: MWD log showing no damage vibration……………………………………58 Figure 34: MWD log showing damaging vibration…………………………………….58 Figure 35: Mud pulse telemetry and wired drill pipe measurement comparison……….59 Figure 36: Unpredictable ECD measurements shown precisely by WDP……………..60 Figure 37: Gamma ray image logged using MPT while the WDP was unavailable……62 Figure 38: LWD images acquired during re-drilling of an equivalent interval which was lost……………………………………………………………………………………...63 Figure 39: Illustration of high local dogleg (HLD…………………………………….64

VI

Teesside University


List of Tables Table 1: Challenges before implementing WDP and benefits after implementing WDP based on the case studies considered……………………………………………………67

VII

Teesside University


ACKNOWLEDGEMENTS I would like to thank God Almighty for granting me wisdom and guiding me to complete my dissertation work on time. I thank Him for always being my source of strength and inspiration. I thank my dear parents for believing in me and always encouraging me to chase my dreams. I thank my father for his words of wisdom and his faith in my abilities. I thank him for providing me with the opportunity to study in such a reputed university and further my career. I thank my mother for always being at my side and for being my pillar of strength in times of need. I thank her for her love and for her selfless nature. I thank my brother and sister-in-law for their support and for enriching my life with joy and laughter.

I would like to extend my sincere gratitude and appreciation to my course leader and project supervisor Dr. Sina Rezaei Gomari. Dr. Sina thank you for your time and effort that enabled me to carry out a more thorough analysis of my research topic than I initially planned. Dr. Sina your valuable inputs and insight has guided me and allowed me to review each topic in depth. Thankyou Sir for your kindness and pleasant nature that made every conversation a pleasure. A special mention should go to my girlfriend Geetanjali for helping me to survive all the stress and not letting me give up.

Finally, I would like to thank my dear friends Amal, Anjum, Govind, Nikhil, Sachin and Sanjoe. Thank you guys for all the wonderful memories and for being there for me in times of need. Thank you for making my stay at Middlesbrough and my time at Teesside University a fun filled and rewarding experience.

VIII

Chapter 1 Introduction

1

Teesside University


1. INTRODUCTION Presently, unconventional drilling methods such as high angle, extended reach drilling are essential to access remote hydrocarbon locations. Hence, directional drilling is inevitable for the successful completion of these wells. Lately, there has been significant improvement in directional drilling assisting techniques such as Rotary Steerable Systems (RSS) and Measurement While Drilling (MWD). The former technique is the downhole system on which drill bit and trajectory control mechanisms are present, whereas the latter is used to measure drilling parameters and formation evaluation. A bi-directional communication (telemetry) system is necessary to send commands to the downhole RSS from the surface and to carry the measurement data from MWD to the surface. This data is used by the engineers at the surface to make real-time decisions and changing particular drilling parameters or make trajectory control to avoid certain problems occurring downhole. MWD system has evolved and it is capable of recording high resolution data and images, which are significantly high in size and requires a high bandwidth telemetry system to deliver them in real-time and full quality. Now, mud pulse telemetry system is used as the telemetry technique which has considerably low bandwidth and data rate. To be able to send the data through mud pulses to the surface, this system has to compress the data, which will reduce the quality of the data and hence jeopardize the decisions made by the engineer. Occasionally, in order to retrieve high density data set, the bottom hole assembly (BHA) have to be tripped-out from the hole to get the data stored in the memory. Wired drillpipe telemetry has recently evolved and is capable of transferring data at high speed and high resolution in both direction without the need of tripping out the BHA. The network presently can deliver a data rate of up to 57,000 bits per second. The report examines how wired telemetry system enables directional drilling in specific environments based on relevant case studies and literature review. Dissertation Structure: Chapter 2: consists of literature review relevant to the topic. Chapter 3: consists of four case studies where WDP has been employed. The challenges and the accomplishments obtained are discussed and inferred.

2

Teesside University

Enhancing Directional Drilling using WDP Chapter 4: Based on literature review and case studies presented in chapter 2 and 3, the drawn conclusions are presented with some recommendations. Chapter 5: Contains the references used for preparing the dissertation.

3

Teesside University


Chapter 2 Literature Review

4

Teesside University


2. LITERATURE REVIEW 2.1. Directional Drilling Directional drilling is defined as the practice of deviating or guiding a well precisely through a predefined path to reach a predetermined subsurface target or targets. There has been a significant improvement in directional drilling in the recent years. Directional drilling permitted driller’s better control in reaching the definite targets. Further improvements depended on the advancements in precise surveying or measurement systems and other downhole equipment’s (Downton et al., 2000). The practice of directional drilling originated in the nineteenth century. At the time when rotary drilling techniques were introduced replacing the old cable-tool rigs, slight effort was made to stabilize the drill string so that the path of the well bore could be controlled. The surveys taken in the borehole after a few years exposed that the vertical wells that were drilled were considerably away from being vertical (Inglis, 1987). In early years, the non-vertical wells were considered as a disadvantage due to the following difficulties associated. a) As the well is not vertical, more footage has to be drilled to reach the target. In other words, a non-vertical well was uneconomic and time consuming. b) In a deviated well bore, the true vertical depth (TVD) could not be resolved precisely, which made the planning of upcoming wells further challenging. c) The wear on the drill string was increased due to the curved shape of the well bore, which made the failure more likely. d) Legal actions could be taken against drilling operator who has trespassed into a different operator’s property. So it was necessary to control the track of the wellbore as there were legal and practical inevitabilities. In the early 1930s, a well was intentionally deviated to reach a target at Huntington Beach, California. Then it was a common practice to construct a drilling rig on a jetty to produce oil from underneath shallow coastal waters. A different strategy was decided by an enterprise driller to build the rig on the shore and drill a slanted hole to reach the target under the sea-bed. This is known to be the directional drilling as it is familiar today. Additional uses of directional drilling were then realized. In 1934, a deviated well was drilled in order to kill a blow-out on the Conroe Field in East Texas. Another rig was set 5

Teesside University

Enhancing Directional Drilling using WDP up a few distance away from the blow-out well and the relief well was drilled to meet the blow-out well. Heavy mud was forced down the relief well to kill the blowout well (American Oil & Gas Historical Society, 2015). Directional drilling plays a vital role in current drilling scenario. 2.1.1 Principles of Directional Drilling Almost all directional wells start as vertical well bores and at a particular allocated depth called as the Kickoff point (KOP), the well path is deflected by the directional driller by escalating well inclination to commence the build section. The direction of the tool face and the bit are taken by surveys during the drilling process. The trajectory measurements of the wellbore is frequently monitored by the directional driller and is constantly adjusted as required to reach the next target along the well path. Primarily, directional drilling associated an uncomplicated rotary bottomhole assembly (BHA) and parameters such as weight on bit (WOB), BHA geometry and rotary speed were adjusted to accomplish the anticipated trajectory. Variations in BHA stiffness, stabilizer placement and gauge, rotary speed, WOB, hole diameter, hole angle and formation characteristics all affect the directional capability and drilling efficiency of a BHA (Mantle, 2013). The side forces acting on the bit and BHA can be varied by adjusting the stabilizer location on the drillsting which will cause it to increase, maintain or decrease inclination which is generally known as building, holding or dropping angle respectively. 

To build angle- bottom hole assembly with a full gauge near-bit stabilizer should be used, an additional stabilizer should be placed 15 to 27 m above the first and a third stabilizer should be placed about 9 m above the second. This assembly exerts a positive side force at the bit and hence the BHA acts as a fulcrum.



To drop angle- bottom hole assembly with the first stabilizer 9 to 27 m behind the bit should be used. This assembly exerts a negative side force on the bit and hence the BHA acts as a pendulum.



To hold angle- bottom hole assembly with 3 to 5 stabilizers, placed 9 m apart should be used. This packed BHA exerts no net side force (Mantle, 2013, p.54).

6

Teesside University


Fig 1: Using BHA to build or drop angle through calculated installation of drill collars and stabilizers (Mantle, 2013). Numerous elements must be considered during well planning to resolve the appropriate trajectory, specifically dogleg severity (DLS) which is the rate of change in the wellbore trajectory, calculated in degrees per 30 m [100 ft.]. Geologic features such as formation changes and faults should be considered with great caution; for instance, extremely soft formations might limit the build rates, and formation dips might cause a bit to drift laterally. To determine the precise lead angle required to reach the target, the directional driller must know the local understanding of the drilling behavior. The skill of a directional driller is based on a certain situations under which he has to decide what course to take to reach the target. 2.1.2 Reasons for directional drilling There are several reasons for directional drilling. Some of these reasons can be grouped as follows. a) To avoid geological barriers There are occasions in which petroleum reservoirs are accompanied by salt dome structures. The salt dome structures may be directly above the reservoir. In such conditions, to reach the target well the vertical well would have to penetrate through the salt formation which will introduce definite drilling 7

Teesside University

Enhancing Directional Drilling using WDP problems such as lost circulation, corrosion and large washouts. In such situations, instead of drilling through the salt overhangs, the wells can be directionally drilled as shown in the Fig 2 (Inglis, 1987, p.6).

Fig 2: A directional well drilled underneath a salt dome (Inglis, 1987, p7)

b) Directing vertical wells or straight hole drilling Straight hole drilling is a directional drilling process where effort is made to keep the hole vertical. This technique can be used to prevent the hole crossing the lease boundaries and also to stay within the well spacing requirements.

c) Inaccessible locations There are occasions in which the reservoirs are located directly under towns, rivers, mountains or under production facilities. In some areas permission might not be granted to drill as it might affect the environment. In such cases directional drilling can be employed to drill the inaccessible location as shown in figure 3.

8

Teesside University


Fig 3: Directional wells drilled underneath unreachable locations (Inglis, 1987, p.8) d) Drilling multilateral wells Many of the large oil and gas reservoirs are located offshore. To drill many individual wells at different locations of the large well is uneconomic and impractical. In such situations directional wells can be drilled from a fixed platform located on the seabed. These wells are known as multilateral wells and are used to increase production with less capital costs. The production cost is less as only a single centralized production facility is required, from which oil can be carried via tankers or pipelines.

Fig 4: Multilateral wells drilled from a fixed platform (Inglis, 1987, p.9) 9

Teesside University

Enhancing Directional Drilling using WDP e) Horizontal Drilling In conventional directional drilling, wells are drilled to an inclination of around 60°. Drilling beyond an inclination of 60° creates several drilling problems which significantly increases the cost of the well. However, there are several advantages, which will outweigh the cost for drilling horizontal wells. Some of these advantages as suggested by Inglis (1987) are as follows: 

The drainage area of the platform can be increased.



Gas coning and water coning problems can be prevented.



Penetration of the production formation can be increased.



The efficiency of enhanced oil recovery (EOR) technique can be improved.



Several vertical fractures can be intersected which will improve the productivity in fractured reservoirs.

Fig 5: Horizontal Drilling (Mantle, 2013) Horizontal drilling will increase the productivity, as the well will be having more area of contact with the reservoir and hence the additional cost required for drilling horizontal well will be justified.

10

Teesside University

Enhancing Directional Drilling using WDP 2.1.3 Techniques in directional drilling Steerable motor assemblies (or positive displacements motors [PDMs]) and rotary steerable systems [RSS] are the most common types of directional drilling techniques or deviation tools being used presently. Whipstock method and jetting assembly method of directional drilling are seldom used today. However, casing whipstocks are sometimes used to sidetrack out of previously cased wells. 2.1.3.1 Whipstock Method Open-hole whipstocks were the first method employed for directional drilling and were used from 1890s to sidetrack around stuck fish. Whipstock is basically a wedge shaped tool which can deflect the bit when lowered along the tapered side of the wedge. Later, whipstocks were used to kick-off directional wells with the assistance of directional survey tools to examine the alignment of the tapered edge. The bottom portion of the whipstock is chisel-shaped to avoid movement once the drilling has been commenced. As the drill bit hits the tapered concave area of the whipstock, there are chances for high amount of wear and hence the facing of the whipstock is made hard to reduce wear. At the highest point of the whipstock is a collar that is utilized to withdraw the tool after the first segment has been penetrated. A shear pin is used to join the whipstock to the drill string.

Fig 6: The method by which a whipstock enters the hole and starts drilling the slanted hole. The whipstock is removed when the drill bit is withdrawn (Stimson, 1950, p.161). 11

Teesside University

Enhancing Directional Drilling using WDP The drill can begin after shearing off the shear pin (as shown in Fig 6). Initially a small diameter hole is drilled to a distance of a round 15 ft. beneath the toe of the whipstock. This rat-hole is then surveyed, subsequently the whipstock and drill string is tripped out followed by reaming the rat-hole to a full size by means of a hole opener. The sidetrack is then continued by running a rotary building assembly. Whipstock can be a reliable and effective tool for deflection objectives if they are being used properly. However, there are several disadvantages which are discussed below. a) A new BHA should be run in order to ream out the initially drilled rat-hole. b) There are probabilities for the whipstock to rotate while drilling which might cause the drill bit to drift away from the intended path. c) There might be a fall in inclination as the drill bit drills away from the whipstock. As a consequence of these disadvantages whipstock method has been replaced by other deflection techniques. 2.1.3.2 Jet Deflection Method The jet deflection method was developed and applied for minimizing the cost for deflection of a wellbore. The basic concept of this method is based on the remarkable energy available in a fluid jet system. Pockets of formations are eroded from the hole bottom utilizing the hydraulic power of the drilling fluid and initiates deflection.

Fig 7: Jet bit for hole-deflection (Dwyer, 1959).

12

Teesside University

Enhancing Directional Drilling using WDP A uniquely altered bit with three nozzles where, one of the nozzles is much larger than the other two is being utilized for the job. To create the deflection, the large nozzle is aligned in the desired direction. A very high rate of circulation is used to wash out the formations while the drill string is not being rotated. The drill pipe is reciprocated until a small pocket is washed away from the formation. Subsequently, the drill string is rotated to ream the pocket further and start building the angle by providing more weight on bit. From the survey, if it is noticed that the well is not pursuing the planned trajectory, the large nozzle can be reestablished and jetted along the new path. The main advantages of this technique are as follows. a) From the initial stage, a full gauge hole can be obtained unlike whipstock technique. b) It is not required to trip the drill string for commencing trajectory. However, there are some disadvantages associated. a) The technique is restricted to a particular range of formations. Too soft and hard formations cannot be drilled by this technique. b) Careless jetting might result in severe dog-legs. c) Some minor rigs may not have enough pump capacity to erode the formations. If jet deflection technique is used for suitable geological formations with excellent observation, highly cost-effective trajectory control can be obtained. 2.1.3.3 Steerable Motors In the early 1960s, a considerable breakthrough in directional drilling occurred when a BHA with a fixed bend of nearly 0.5° was combined with a downhole motor to power the drill bit (McMillian, 1999) (McMillian, 1999) . The hydraulic power supplied by the drilling mud to the motor turned the bit. This motor was called as mud motor. The rotation of the drill bit was enabled without the rotation of drill string, unlike the conventional rotary drilling technique. The directional control offered by the motor and bent sub provide better directional control than the previous BHAs, at the same time, it considerably increased the angle of curvature that can be built. Additionally, it did not needed a trip to change the angle of inclination like previous assemblies. The bit offset required to initiate and maintain the variations in path directions was provide by the bent sub and were operated on the tilt angle principle. There are three main

13

Teesside University

Enhancing Directional Drilling using WDP geometric contact points such as a stabilizer above the motor, a near-bit stabilizer, and the bit (Allen et al., 1997) .

Fig 8: steerable motors (Felczak et al., 2012) .

A positive displacement motor (PDM) is formed either by the aid of a downhole turbine or a helical stator rotor combination. A PDM with bent sub assembly was commonly used in steerable motors. The new generation steerable motors uses surface adjustable bent housing which is represented in Fig 8. The rotor is turned by pumping drilling mud which inturn rotates the bit and the drive shaft. An angle of approximately 0° to 4° can be set for the adjustable bent housing that can be adjusted from the surface. This deflection is crucial to the rate at which angle can be built. The angle of the well bore depends not only 14

Teesside University

Enhancing Directional Drilling using WDP on the angle to which the bent sub is adjusted to, but also on the outer diameter and length of the motor, location of the stabilizer and the drill collar size. Two modes are required for drilling with steerable motors such as: slide mode and rotary mode. During rotary mode, the entire drill string is rotated to turn the bit, but in slide mode, the drilling mud flow is deflected to the downhole mud motor to rotate the bit without rotating the drill string. The slide mode is used to change the trajectory of the well bore. During the rotary mode the, as the drill string is rotating, the bend is pointed equally in all direction and thereby a straight path is drilled. The sliding mode is commenced after stopping the drillstring rotation and then the downhole motor (or tool face) is pointed in the desired direction by adjusting the bend. The torsional forces acting on the drillstring can lead to spiraling of the drill string. To avoid this the drillstring must rotated with slight increments referring to the MWD measurements until the correct tool face adjustment is accomplished. Now, the driller can start the downhole motor to begin drilling in the adjusted tool face direction. However, the tool face direction can be reoriented due to the reactive torque produced while the bit cuts hard formation. The rotating mode and sliding mode has its own challenges. During the rotary mode, the bend in the drillstring is slightly offset from the BHA and hence the borehole created is larger and spiral shaped. This will result in low quality borehole and lead to high torque and drag. Spiral boreholes will influence poorly the response of logging tool. During slide mode, as the drillstring is not rotating, it can result in clogging of cuttings at the low side of the borehole as it cannot be removed by the drilling mud. This, in turn can cause stuck pipe condition. The rate of penetration (ROP) is also decreased due to the reduction in horsepower available for the bit to turn and also due to the sliding friction formed. This sliding force can build up in extended reach drilling resulting in inadequate axial weight to overcome the drag enforced by the drill string on the borehole. Subsequently, it can be impossible to perform the drilling. Moreover, as for making the trajectory, the steerable motor has to be switch to slide mode from rotary mode; this can result in undulations or local doglegs (abrupt well bore direction change) that can increase the well bore tortuosity and hence increase the friction during drilling and running casing.

15

Teesside University

Enhancing Directional Drilling using WDP 2.1.3.4 Rotary Steerable Systems In 1990s, the problems associated with steerable motors were addressed by rotary steerable systems. The most important advantage with rotary steerable system (RSS) is its capability to make trajectories without the need to slide the drillstring, i.e. it allows for rotation of the drillstring continuously. Moreover, they provided nearly closely instantaneous trajectory control from the surface through the telemetry system. Earlier, they were used particularly in extended reach drilling, as it was not possible for the steerable motors as discussed earlier. Later, RSS was realized for its ability to provide better ROP, hole cleaning abilities, smoother wellbore and accurate wellbore trajectories. The figure below represents the comparison of borehole quality between RSS and steerable motor.

Fig 9: Comparison of bore hole quality created by steerable motor (top) and RSS (bottom) (Felczak et al., 2012) .

Rotary steerable systems have advanced substantially since their introduction. Earlier, drilling mud actuated pads and stabilizers were employed to change the trajectory, which depended on the contact with borehole wall to initiate the change in direction. Hence the performance of the tool was reduced by borehole washouts and tortuosity. 16

Teesside University

Enhancing Directional Drilling using WDP Two concepts were later introduced that depended on the bend sub to make the trajectory control and thus reduced the impact of well bore quality on trajectory control performance. The two newly created concepts were known as push-the-bit and point-thebit (Schaaf, Pafitis and Guichemerre, 2000) . Push-the-bit system initiates the trajectory by pushing the pads against the borehole wall. A bias unit consisting of three actuating pads are placed near the bit to apply the lateral force against the formation. To build and drop the angle, the mud actuated pads are pushed against the low side of the wall to build angle and are pushed against the high side to drop angle. The pad is actuated by the commands sent from the surface by the driller through telemetry system.

Fig 10: Push-the-bit RSS representing how the trajectory change is accomplished (Felczak et al., 2012) .

Independently controlled blades. The pad forces itself to the wellbore to orient the drill string in the opposite direction.

Blades extended equally in all direction for centralizing the tool for a straight wellbore.

Fig 11: Cross section of RSS showing movement of pad (Moody, Jones and Leonard, 2004) . 17

Teesside University

Enhancing Directional Drilling using WDP Fig 11 represents the cross section of the RSS. Each pad can be individually controlled by means of hydraulics. The extension with which the pad has made can be measured by means of a measuring tool attached to it. The point-the-bit system contains mainly three parts such as, electronic and sensor section, steering section and power generation section. The steering section employs a bend (universal joint) which is located internally to offset the positioning between borehole axis and tool axis to yield a directional trajectory (Bryan et al., 2009) . The bend is located inside the drill collar of the tool which is placed above the drill bit. The trajectory is changed by changing the tool face in the required direction. The orientation of the bend is regulated by a servo motor, which rotates at the same rate as that of the drill string but in the opposite direction. Hence the collar can be rotated without rotating the tool face in other words, keeping the tool face geo stationary. (Al Yami et al., 2008) . The sensor and electronics assembly monitors the rotation of collar and motor through sensors. The input, feedback, full inclination and direction are provided by these sensors. Power turbine and alternator assembly provides the power required.

Drive shaft at offset angle to drilling collar Drilling Tendency

Collar axis Fig 12: drive shaft at offset angle to collar

(Schaaf, Pafitis and

Guichemerre, 2000) . Now, Rotary steerable systems (RSSs) are mostly used for directional drilling replacing the steerable motors which has several problems. Fig 12 represents the evolution of directional drilling techniques pointing their advantages and disadvantages.

18

Teesside University


2.1.4 Evolution of Directional Drilling Whipstock Method - Limited control - Missed targets

Jet Deflection Method - No trip required for commencing trajectory -Only limited formation types can be drilled -High pump capacity required

Steerable Motors - Rotary and slide mode controlled at surface -Better directional control -Tortuosity from slide drilling

Rotary steerable Systems - Continuous rotation -Excellent directional control - Improved borehole quality -Highly efficient - Increased rate of penetration (ROP)

Fig 13: Evolution of directional drilling

2.2. Measurement While Drilling Measurement while drilling (MWD) is a system used to measure: (1) formation properties such as natural gamma ray, porosity, resistivity, (2) well bore geometry such as azimuth and inclination, (3) drilling tool orientation such as tool face and (4) the mechanical properties of the drilling process while drilling (Baker Hughes, 1997) . The measurements are done using sensors located on the drill string. The measured signals are carried by the telemetry system to the surface. Hence, a practical telemetry system is essential for the successful operation of MWD. 19

Teesside University


Fig 14: Basic MWD system (Gravley, 1983) .

MWD system consists of three main components such as: (1) Downhole sensors, (2) a telemetry system for sending information, and (3) equipment at the surface to receive the data as represented in Fig 14. The information retrieved from downhole can be divided into two categories such as: drilling performance and formation evaluation. The information included in these and the sensors used to measure them are discussed below. 2.2.1 Formation Evaluation MWD 2.2.1.1 Natural Gamma Ray Gamma ray log provide the natural radioactivity measurement of the formation being drilled, which shows varying range of radioactivity. These measurements are basically used to evaluate the shale content in the sedimentary rocks. Based on the number of gamma rays radiated per unit time, the formation type can be analyzed. Fig 15 depicts the gamma ray response based on formation type.

20

Teesside University


Fig 15: Gamma ray response based on formation (Baker Hughes, 1997) . 2.2.1.2 Formation Resistivity Electrical resistance is used to discover the presence of hydrocarbon content in the formation. The formation is generally considered as a pure insulator and does not allow current to pass through. Saltwater is the main conductor in formations that stick to the rock formations. Conductivity in the formation can be used to detect the presence of hydrocarbon. 2.2.1.3 Neutron Porosity Neutron porosity data is required to calculate the volume of hydrocarbon present in the formation. High energy neutrons emitted from a chemical source is bombarded with the formation. The presence of hydrocarbon can be detected by the loss in energy of the neutron. The amount of energy lost by the neutron is directly proportional to the amount of hydrocarbon present in the formation. 2.2.1.4 Formation Density Formation density tools are used to find the porosity of the formation just like neutron porosity measurement. Both the methods assume several parameters to calculate the porosity. Formation density tools requires fewer assumptions than neutron porosity and hence is more accurate. Generally, both methods are used to find the porosity as it is an

21

Teesside University

Enhancing Directional Drilling using WDP important part for the evaluation of any formation. The rock density and fluid density is used to calculate the filled fluid density. 2.2.2 Drilling Performance MWD These are information used to enable and improve drilling. The data aids to: 

Directional control



Reduce survey downtime



Reduce dogleg severity



Differential sticking risk reduction

2.2.2.1 Inclination Degree of deviation from a vertical orientation is the inclination. The angle is 0° when it is vertical and 90° when it is horizontal (Schlumberger, 2015). 2.2.2.2 Azimuth The angle between the vertical projection of a line of interest onto a horizontal surface and true north or magnetic north measured in a horizontal plane, typically measured clockwise from north (Schlumberger, 2015). 2.2.2.3 Toolface The alignment of the tool relative to a fixed axis should be known when a directional trajectory is made. This orientation of the tool is termed as tool face. 2.2.2.4 Pressure Transducer These are electromechanical devices used to measure pressure based on Wheatstone bridge principle. They detect the hydraulic pressure and convert them into either current or voltage. 2.2.2.5 Temperature Temperature sensors that can measure temperature over a extent of 233 to 448 °K. 2.2.2.6 Downhole Weight on Bit The rate of penetration is affected by the reduction in downhole weight on bit which is caused by the drag force of drill string components. Measuring the weight on the bit can 22

Teesside University

Enhancing Directional Drilling using WDP mitigate this problem. Increasing the surface weight on bit to increase the downhole bit may not be always successful. Hence the downhole weight on bit has to be continuously monitored while increasing the surface weight on bit.

23

Teesside University


2.3. Telemetry Techniques Maximizing production from hydrocarbon reservoirs that are located very deep requires real-time bidirectional communication for downlinking and up-linking. Data from sensors located downhole near the bit can be classified as: drilling data and formation evaluation data. Telemetry channels are required to maintain a constant contact with the down hole environment while drilling. Generally, a telemetry channel is used for carrying information from the surface to the BHA to make necessary trajectory control or steering the tool and carrying the information from the sensors located near to the bit to the surface for a better understanding of the formation and to make sure that the well bore is following the previously defined well path. Apparently, the speed at which the telemetry system can carry information is a critical parameter for improving drilling efficiency. Telemetry techniques can be mainly classified into two categories such as wired telemetry and wireless telemetry. M ud pulse telemetry (MPT) is the widely used wireless telemetry technique now. However, wired drill pipe (WDP) technique provides outstanding data transfer speed compared to other telemetry techniques and so it is possible for WDP to be common in the near future. Hence, MPT and WDP are discussed extensively in this chapter while a brief study of electromagnetic telemetry and acoustic telemetry is discussed. 2.3.1 Mud Pulse Telemetry 1n 1964, a mud valve was suggested to transmit data up the mud column. In the 1970s, transmission of data from tools in the BHA to the surface was achieved. This technique was called mud pulse telemetry (MPT) and it made use of pressure pulses generated in the down hole tools which were transmitted to the surface through the continuous drilling fluid column where they were identified by the pressure transducers and then decoded (Bybee, 2008). (Spinnler, Stone and Williams, 1978) defined mud pulse telemetry as “Mud pulse telemetry is a method of transmitting information through a flowing column of drilling mud. In this process, the pressure on the flowing mud column at a point downhole is periodically modulated by mechanical means, and the resulting periodic pressure pulses appearing at the surface end of the mud column are detected by a pressure transducer conveniently located in the stand pipe. Information can be conveyed by the presence or absence of pulses, or by the relative duration of the pulses in a sequence”. 24

Teesside University

Enhancing Directional Drilling using WDP This was a breakthrough in directional drilling industry which provided the directional driller with real-time information on steering system performance, and geometric position of the well bore. The efficiency and accuracy of directional drilling was considerably increased while reducing the risk. Formation evaluation tools were later added on to the BHA recognizing the value of MPT. The transmission of formation evaluation data to the surface in real-time allowed the well trajectory to be monitored with respect to the geological features. Later, Natural gamma ray and basic resistivity devices were brought in followed by several other sophisticated devices. Mud pulse telemetry is still the most widely used and reliable method for transmitting data from downhole sensors to the surface while drilling (Hutin et al., 2001). The mud pulse telemetry techniques has been in the measurement while drilling scene for quite a while. An MWD system that employed a plunger valve for producing discrete mud pulses was defined by Arps and Arps (1964). This system could achieve a data rate below 1 bits/second. A Mobil MWD system was described by Patton et al. (1977). This system employed a rotating valve mechanism to generate continuous-wave telemetry making use of phase shift key modulation. This method achieved a data rate of up to 3 bits/second. The environment in which the mud pulse telemetry system works is very harsh. The downhole tools will have to encounter intense conditions including high pressure stretching to 25000 psi, high temperature greater than 350 °F, and vibration and shock forces which can be hundreds of times greater than the gravitational force. Thus, the electrical and mechanical systems used to generate the mud pulses in these harsh environments should be robust enough. A typical mud pulse telemetry system is depicted in Fig 16. A transmitter and a receiver is essential in any communication system. In the same way, a telemetry system requires the same. Downlinking and up-linking are the two main processes executed by a telemetry system. In up-linking, the transmission of data is done through MWD tool in the BHA by generating pressure pulses in the mud stream with the aid of a pressure generating device known as the mud-pulser. At the surface, the sensors present in the receiving system assess the pressure variations and the measurements are interpreted by signal processing units which is called as decoding.

25

Teesside University

Enhancing Directional Drilling using WDP Downlinking, which is normally done for trajectory control or steering operation is accomplished either by creating periodical variations in the flow rate of the mud in the system, or by periodically varying the rate of rotation of the drill string. The sensors (for example, magnetometers to detect variation in rotation) located in the downhole MWD system recognizes and responds to either of the flow rate variation or rate of rotation.

Fig 16: A typical mud pulse telemetry system. The mud-pulser is similar to the transmitter in the communication system, the mud filled drill pipe to the channel, and transducer mounted on the stand pipe to the receiver (Jianhui et al., 2007).

26

Teesside University

Enhancing Directional Drilling using WDP 2.3.1.1 Surface System and Sensors The transmitter located downhole is only one of several components of a mud pulse telemetry system. The other components being the surface receiver, transmission channel, and additional downhole and surface processing units. The downhole and surface components are designed so as to acquire the maximum reliability and data rate. The surface system consists of some extra components to compensate for the distortions in the signal while transmission. The data acquired in the MWD tool is compressed and converted into a particular format. Subsequently, the formatted data is encoded and this carrier signal is modulated depending on the pulser. This final waveform is then carried to the transmitter with some synchronization overhead as this is the slowest process and hence the most important. The transmits the signal to the mud channel in which it is distorted and attenuated due to various noise elements in the mud, and is sensed by the receiver at the surface. The receiver consists of several sensors whose number, type, and complexity depends on the downhole tool used and the parameters being measured. From the receiver the data is transferred to the noice cancellation unit where the noice components and distortions are removed. From this point, the downhole processes are reversed; the data is demodulated and then synchronized. Consequently, the synchronized data is decoded and the bit errors are decoded and corrected. Finally, the data is decompressed and sent to a data base where it is permanently stored. The downhole to surface telemetry system is depicted in Fig 17.

The surface system is different for different MWD service companies as the mudpulsers are available in different designs depending on the service company. The systems can be differentiated depending on the speed of transmission and the efficiency and accuracy by which the data can be extracted from the signals at the surface. De-coding is the crucial element in determining the efficiency of the whole telemetry system. The surface system mainly consists of sensors for detecting the signals, units for conditioning and digitizing the signals, and a digital signal processing unit for processing these measurements.

27

Teesside University


Data in

Compression

Modulation

Receiver

Encoding

Channel

Transmitter

Noice cancellation

De-coding

Channel Equalization

Decompression

Demodulation

Data out

Fig 17: Block diagram of mud pulse telemetry system depicting the downhole and surface components.

2.3.1.1.1 Sensors Sensors are mainly used on the surface to detect and measure the pressure pulses. Pressure transducers are used for this purpose and is mounted on the standpipe. Three types of pressure transducers are generally used depending on the existing conditions such as static, dynamic, and differential. Static transducers are designed to measure from 0 psi to a defined maximum pressure. The standard rating of these transducers are 5, 10 or 15 kpsi respectively on a full scale. The dynamic pressure transducers are designed to react only to dynamic elements in the signal and can be restricted to a specific measurement bandwidth. These transducers are capable to provide better sensitivity and signal resolution as it has to measure only along a dynamic range in amplitude, instead of a complete static range. Annular pressure sensors, flowmeters are also employed to increase the efficiency and accuracy of the measurement.

28

Teesside University

Enhancing Directional Drilling using WDP 2.3.1.1.2 Surface Systems The pressure signals detected by the pressure transducers are sent to the surface systems where it is conditioned of distortion and digitized. The extracted and decoded signal from the mud-pulser is stored and displayed. The complexity of de-coding escalates as the well gets deeper and with increasing amount of data and data rate. The newer generation surface system is capable of detecting very small signals from the pulser which are highly distorted due to pressure noise. To be able to extract those small distorted signal, highly sophisticated noise cancelling equipment and pump stoke counters are used. Pump stroke counters counts the total accumulated mud pump strokes and helps to monitor the mud pumps which will provide the ability to compensate for the pressure signals generated by the mud pumps, which is a main source of noise (Hdigauges, 2015) . High resolution digital processing units, Digital Signal Processing units (DSPs), and real time processing systems makes it possible to deliver accurate and reliable data rates at deep depths. The surface platform performs noise cancellation and advanced digital processing, referred to as channel equalization.

2.3.1.2 Mud Pulse Signal Generation Various methods are used for generating mud pulse signals. Mud pulse signals are created either by venting part of the flow to the annulus or by limiting the flow of drilling mud in the drill string (Hutin, Tennent and Kashikar, 2001) . This is the case in downlinking. During uplink, the mud pulses are generated by mud-pulsers. The mud pulses created are different depending on the type of mud pulsers used. The mud-pulsers can be differentiated by the type of mud pulses generated: discrete pulses or continuous wave signals. The discrete pulses are either negative or positive classifying the mud-pulser to positive and negative pulsers. Continuous wave signals are generated by rotary valve pulsers. Shear valve pulser can generate both discrete and continuous wave signals.

29

Teesside University

Enhancing Directional Drilling using WDP 2.3.1.2.1 Negative Pulse Generation Negative pulses are created by instantly decreasing the pressure in the drill string. This is achieved through a dump valve which will divert the mud from inside of the drill string to the annulus. Consequently, the pressure inside the drill string is reduced. When the dump valve is closed, the pressure is restored to the original value. The pressure drop beneath the tool is the factor that regulate the magnitude of the pulse. The generation of mud pulse is illustrated in Fig 18.

Fig 18: Generation of negative pulse signal (Hutin, Tennent and Kashikar, 2001) . The drill pipe and Pressure Vs Time graph is depicted. Binary codes are created according to the wave signal created.

Negative mud pulsers does not function in direct opposition to the mud flow, hence it is not essential to assist the pulser hydraulically. Furthermore, the power requirement of negative pulsers are less than fully enclosed positive pulsers that makes it more power efficient and higher data rates transfer capable. These pulsers are less prone to plugging by lost circulation materails due to the shearing action of the valve. 2.3.1.2.2 Positive Pulse Generation Positive pulses are created by instantly and partially obstructing the flow of mud through the drill string. As a result of restriction of mud inside the drill string, the hydraulic pressure inside the drill string is increased and when the obstruction to the flow is removed, the pressure is restored to the original state as depicted in Fig 19. 30

Teesside University

Enhancing Directional Drilling using WDP Positive mud pulsers can be characterized based on the method used to open the valves. One method uses mud pressure to open the valve, i.e. a ‘hydraulically assisted’ valve and the other method requires a power mechanism to open the valve and it is completely isolated from the drilling fluid. The hydraulically assisted pulsers are very cost effective and can accomplish a data rate of up to 12 bits/second. However, the hydraulically assisted pulsers are prone to plugging by lost circulation materials (LCMs) whereas the second method is not affected by LCMs. The data rate that can be achieved by the second method is lesser than that of the hydraulically assisted method.

Fig 19: Generation of positive pulse (Hutin, Tennent and Kashikar, 2001) 2.3.1.2.3 Continuous Wave Generation The previously described pulsers can generate only a train of discrete pulses. Continuous wave signals can be generated by pulsers of rotary and shear valve design at a given frequency. Two slotted disks positioned one above the other perpendicular to the mud flow is present in these type of pulsers. One of the disks is installed in such a manner that it is free to rotate and the other disk is restricted to rotate. The frequency of the continuous wave created depends on the speed of rotation of the rotor. Shear valves are the type of valves which can control the aperture of both the disks by oscillating the rotor. In general, shear valves can generate discrete as well as continuous wave signals whereas rotary valves can generate only continuous wave signals.

31

Teesside University

Enhancing Directional Drilling using WDP Coherent signal detection techniques can be employed with continuous waves as the data is modulated onto a carrier wave. It has less signal to noise ratios compared to the demodulation of discrete pulse form of data transmission using either negative or positive pulses. Coherent detection can achieve lesser rate of bit errors at the same signal to noise ratio compared to pulse type modulation.

Fig 20: Continuous wave signal generation (Hutin, Tennent and Kashikar, 2001)

2.3.1.3 Characteristics of Mud Channel 2.3.1.3.1 Signal Attenuation The attenuation of the signal as they transmit through the mud channel depends on the distance through which the mud pulses have to travel and the characteristics of the mud used. Desbrandes (1988) defined experimental and theoretical data on signal attenuation based on Lamb’s law for pressure wave attenuation in mud-filled pipes. The attenuation of mud pulses increases exponentially with respect to distance. 32

Teesside University


P(x) = P0e -x / L…………………………………………..………………………Eq. (1) With,

L=

𝑑𝑖 𝑐 2

√

2 𝑣𝜔

…………………………………..………………………………….Eq. (2)

Where, P(x) = amplitude of pressure wave at a distance x from the source in Pa or psi. P0 = amplitude of pressure wave at the source in Pa or psi. ν = kinematic viscosity in m2/s or ft2/s. ω = angular frequency in radians/s. di = internal diameter of the pipe in m or ft. c = wave velocity in m/s or ft/s. Neglecting pipe modulus effects, the wave velocity can be expressed as: 𝐵

c =√ …………………………………………..……………………………….Eq. (3) 𝜌

Where, B = bulk modulus of the mud (inverse of compressibility) in pa. ρ = density in kg/m3. Substituting Equation 3 in Equation 2

L=

𝑑𝑖 2

2𝐵

√𝜂𝜔……………………………………………………………………....Eq. (4)

Where, η = plastic viscosity (=ρν) in centipoise.

From equation 4, it is clear that the signal attenuation increases as the pipe diameter decreases, higher compressibility, greater viscosity and greater frequencies. The amplitude of signals reaching the surface from a smaller hole will be less that that received from a larger hole. Moreover, if there is any gas or air entrapped in the mud due 33

Teesside University

Enhancing Directional Drilling using WDP to certain problems such as pumps malfunctioning etc., partial removal of gases entering the mud from the formation, or injection of nitrogen into the mud for underbalanced drilling causes the increase in compressibility of the mud which will result in an increase in signal attenuation. Also, if highly viscous mud such as synthetic oil based mud is used as drilling fluid in deep water drilling applications, it will result in reduction in amplitude of the signal. The viscosity of a liquid decreases with increases in temperature and so for the mud. In deep water environment, the temperature of water near the sea floor can be substantially low compared to the temperature at the surface. This result in an increase in viscosity which will affect the amplitude of the signal being transmitted to the surface. Therefore, the viscosity of the mud decreases first and increases again as the well goes deeper and deeper. The compressibility of drilling mud and hence the bulk modulus is affected by both temperature and hydrostatic pressure. As the well is drilled deeper and deeper, the temperature and pressure increases and so the variation in amplitude is significant as the bulk modulus of the mud varies. Equation 1 holds good only for high frequency telemetry system (>10 Hz). For low frequency telemetry system, an alternative equation has been defined as given in Equation 5. 1

P(x) = P0(1 − 𝑒 𝑅𝐶 )…………………………………………..……………………Eq. (5)

With, 𝑃

R = 𝑄 ………………………………………………………………...…...………..Eq. (6) 𝑉

C = 𝐵 …………………………………………………….………………...………Eq. (7)

Where, R = mechanical resistance in Pa or m3/s. C = mechanical compliance in m3/Pa. P= mud pressure in Pa. 34

Teesside University

Enhancing Directional Drilling using WDP Q = volumetric flow rate in m3/s. V = volume of mud above MWD tool in m3. B = bulk modulus of the mud in Pa. Fig 21 depicts the signal attenuation as the depth increases for high frequency and low frequency telemetry methods. From the graph, it can be noted that the signal attenuation for low frequency telemetry (1 Hz) is less severe than that for high frequency telemetry (12 Hz). Therefore, to be able to achieve reasonably high signal amplitude and thus good telemetry quality at extremely high depth, it might be necessary to transfer data on the low frequency component of the spectrum.

Fig 21: Signal attenuation Vs depth for high frequency and low frequency telemetry (Hutin, Tennent and Kashikar, 2001) . 2.3.1.3.2 Noise in the Mud Channel The signal travelling from downhole to the surface have to travel through a harsh environment which induces noise into the signal. The primary source of noise during transmission is from the mud pumps and the noise produced by the drilling process can be neglected as it is small compared to the primary source. The noise in the source increases as the size and strokes per minute of the pump increase (Jianhui et al., 2007) .

35

Teesside University

Enhancing Directional Drilling using WDP The mud pulses travelling from the bottom of the hole becomes attenuated as they have to travel thousands of meters to reach the surface. However, the amplitude of noise created by the mud pumps at the surface would be significantly greater than the telemetry signal reaching the surface. This will result in low efficient detection of the telemetry signals. To guarantee safe transmission of mud signals without the interference of noise, it is advisable to send the mud signals through a part of the spectrum which cannot be interfered by the noise signal. For instance, the mud pulse signal can be transmitted at a frequency less than that which can be interfered by the noise signal (normally within a 12 Hz to 24 Hz range). If the signal transmission is carried out in the range below the noise signals from the mud pump, care should be taken not to interact with the noise from the drilling process which is associated with noise from interaction of drill bit with the formation, stalling of the mud motor or stick slip phenomena. Generally, the noise caused by drilling process will be having very high amplitude and has to tendency to fall in very low frequencies of less than 0.5 Hz. 2.3.1.3.3 Interference of Pressure waves The change in cross sectional area of the drill pipe during the propagation of the wave through the drill will cause the some quantity of the wave to reflect back towards the source of the wave. The amount of waves reflected depends on the change in cross sectional area encountered by the signal.

Fig 22: Reflection and transmission of Pressure waves at a change in pipe cross sectional area (Hutin, Tennent and Kashikar, 2001) . The drilling equipment’s such as pulsation dampners, swivel, rotary hose, mud pumps etc. can act like acoustic reflectors. The reflected waves may interfere with the signal travelling from downhole to the surface and may result in constructive or destructive interference depending on the phase of the noise signal which may lead to severe

36

Teesside University

Enhancing Directional Drilling using WDP distortion of the signal. Fig 23 depicts how the change in drill string diameter will bring about the distortion in the signal. The main signal travelling to the surface reach some time earlier than the echo, which are the reflections of the main signal. These echo signals (noise) will interfere with the following main signals which will lead to the detection of the main signals harder.

Fig 23: signal waves reflecting back due to the change in drill string diameter resulting in the production of echo which can interfere with the subsequent main signal (Hutin, Tennent and Kashikar, 2001) . 2.3.1.3.4 Signal-to-Noise Ratio The ratio of signal strength to noise strength within the bandwidth of the signal is the most important factor for good quality telemetry (Taub and Schilling, 1986) . To improve the signal-to-noise ratio, it is necessary to reduce the noise as the signal amplitude is fundamentally constant. The mud pump noise can be reduced by maintaining the pump properly. Poorly maintained pump will produce more noise. Hence, the conditions of the mud pump will affect the quality of the real time telemetry data.

37

Teesside University

Enhancing Directional Drilling using WDP 2.3.2 Wire Pipe Telemetry System First used in 2003, the new-wired pipe telemetry system provides high-speed substitute to conventionally used mud pulse telemetry and electromagnetic telemetry system. The new system employs drill strings tubular, which are individually modified to provide high bi-directional data rate of up to 57,000 bits per second (bps) (Bybee, 2008). Such high data rates provides high bandwidth for the transfer of data acquired from sensors located down hole and along the string at high data rates, so that the data can reach the surface instantaneously to make real-time decisions. The main component of the wired drill pipe telemetry system is the coaxial cable embedded on the drill string itself. The high strength coaxial cables and low-loss inductive coils are embedded within double shouldered connection in each tubular joint to convey information (Hernandez et al., 2008). The wired drill pipe will be discussed further later. The inductive couplings, which are embedded on the male part of one joint and on the opposing box end of the female subsequent joint, transfer the data through electromagnetic induction phenomena and hence the coils do not need to touch to transfer the data. However, over plenty of connections made, there is a chance for loss of signal strength. Therefore, signal repeaters are placed at about 1500 ft. apart all along the drills string in order to ensure that the signal-to-noise ratio is maintained at an acceptable level. Moreover, these sensors located on different parts of the drill string assists to acquire measurements at different points. An important benefit with WDP is that the system maintains the same data rate independent of data volume, depth and distance. 2.3.2.1 Components of Wired Pipe Transmission Line Generally, the wired drill pipe telemetry system is composed of four components such as top drive swivel, telemetry pipe, signal repeaters and data sub.

38

Teesside University


Fig 24: Components of wired drill pipe telemetry system (Allen et al., 2009) .

2.3.2.1.1 Top Drive Swivel This device delivers interface between rotating and stationary environments installed on the bottom end of the top drive assembly it is usually installed by replacing a saver sub. It consists of a sub through which the network traffic travels and into the swivel, which is connected to the surface data retrieval system via cable.

39

Teesside University


Fig 25: Top drive swivel sub (Reeves et al., 2005) .

2.3.2.1.2 Wired Telemetry Drill Pipe The wired drill pipe is the most important part of wired drill pipe telemetry system which act as a carrier of the signal from bottom hole to the surface and vice versa. To be able to do so, the conventional drilling tubular is altered to incorporate high speed coaxial cables all along the length of the drill pipe. This cable terminates at an induction coil located at the end of the drill pipe. These induction coils are installed in a pin and matching box shoulder box. The data is transmitted through these induction coils without necessarily making any contact by electromagnetic induction. The double shoulder connection present on the pipe offers a perfect location for the placement of the coil, i.e. 40

Teesside University

Enhancing Directional Drilling using WDP each coil is installed in a protective groove in secondary torque shoulder. When two drilling tubulars are connected together, the box end of one joint comes in close proximity of the pin end coil of the other.

Fig 26: Non-contact line coupler coils transferring data by induction (Jellison et al., 2003) .

The signal conductor can be stretched inside the pipe wall or it can be embedded into the drill pipe. The first method enables the easy access to the cable for maintenance purpose but is prone to high rate of wear and data loss. The data cable is enclosed inside a sealed stainless steel conduit which passes through the body of the tool joint and then enters into the internal diameter of the drill pipe at the internal upset (Reeves et al., 2005) . The following figure represents the location of the conduit in the drill pipe.

41

Teesside University


Fig 27: The location of the conduit in the drill string (Reeves et al., 2005)

Fig 28: Double-shouldered pin tool joint cutaway view. Location of the inductive coil is clearly shown (Jellison et al., 2003) .

42

Teesside University


Fig 29: fitment of inductive coils inside the shallow grove inside the secondary torque shoulder of the tool joint (Jellison et al., 2003) .

2.3.2.1.3 Signal Repeaters Even though the possibility of signal loss is relatively low, it cannot be completely avoided. Hence battery powered signal repeaters are employed generally every 1500 ft distance. Commonly, they are called as booster assemblies that will boost the signal to ensure acceptable signal-to-noise ratio and reduce data loss. The booster joint is a 1.2 meter long sub which is powered by a lithium-ion battery. The lithium-ion batteries will drain after typically around 90 days and it has a temperature limitation of 150° C. Additionally, these signal repeaters can provide standalone measurements such as pressure and temperature at its location. 2.3.2.1.4 Interface Sub The interface sub links the wired drill pipe to the MWD/LWD and RSS tools to permit communication of logs and commands.

43

Teesside University

Enhancing Directional Drilling using WDP 2.3.2.2 Advantages of Wired Pipe Network The most important advantage of wired pipe telemetry is the high bandwidth, which is drastically higher than the current technique. WPD can deliver a data rate of up to 57,000 bits per second which is 1000 times faster than MPT, which makes it capable of transferring data logs from down hole to surface and commands from surface to downhole in real time. This will increase the quality and quantity and of data available while drilling which will reduce the non-productive time and consequently increase drilling efficiency. Another main advantage with WDP telemetry is that it can work regardless of the fluid environment. It can even work in water, air or foam which will enable underbalanced drilling. 2.3.2.2.1 Real Time Imaging Two types of imaging tools are currently being used with LWD tool such as: azimuthal density (gamma ray) and resistivity imaging. Azimuthal gamma ray tools are basically not used for the purpose of imaging, rather they are used to measure the density of the formation. Hence they are run quite often in the reservoir, probably at every few inches depending on the ROP. Even though these images are not useful for thorough geological interpretation, they can be used to analyze the variation in hole size due to the difference in density between mud and rock. Hence, they can be used to identify hole stability and geometry issues (Wilson, 2013) . 2.3.2.2.2 Drilling Parameters Optimization When using WDP, the downhole parameters are available in higher resolution which will enable broader visualization of the downhole drilling environment. This will enable to monitor drilling dynamics variables in real time. The variation in any parameters downhole can be detected with high accuracy and possible actions can be executed instantaneously by the drilling engineer to mitigate the problem. For example, the change in vibration downhole can be detected in real time and the mud weight can be adjusted to mitigate this problem. 2.3.2.2.3 ROP improvement The parameters which will affect the ROP such as weight on bit (WOB) can be continuously monitored by WDP. For example, if there is a tendency for the drill string

44

Teesside University

Enhancing Directional Drilling using WDP to hang up due to inappropriate WOB, this condition can be immediately recognized and rectified with minimal impact on the ROP. Furthermore, the distance drilled will be high when ROP is high and hence more data will be acquired by the MWD tool. To send all the data acquired by the MWD tool, the quantity of the data has to be decreased by reducing the ROP. Gamma ray images cannot be transferred or may have to be transferred at low quality when MPT is employed. 2.3.2.2.4 Improved Shock, Vibration and Stick-Slip Management WDP can deliver stick-slip, axial and torsional vibration data at high resolution which will allow the driller to adjust the drilling parameters such as mud weigh to mitigate the vibration. The improved vibration management will deliver better drill bit cutting action and reduce the possibility of tools and formation damage. 2.3.2.2.5 Hole Quality and Wellbore Stability Management When drilling through extremely interbedded formation where the strength of the formation vary rapidly, the drill bit has the tendency to follow the least resistant path which can result in high local dog leg inside the hole. If this problem is not rectified immediately, it can lead to the damage of the drill string components. BHA bending moment, which is the measure of side forces acting on the BHA, can be used to recognize the local dog legs. The time taken to decrease the severity of such doglegs are significantly high. However, if the dogleg can be detected quickly at the beginning of the course, necessary action can be taken to reduce it. To be able to do it, the data rate has to be high for sending the log data to the surface and for controlling the trajectory downhole. The use of short gauge drill bits with active cutting structures can result in cyclically drilled holes (Hernandez et al., 2008) . This is commonly known as hole spirally and should be avoided to maintain the hole quality and well bore stability. The hole spiraling can be detected only from down hole images or from BHA bending moment data. When using MPT, these data are only accessible after tripping out the BHA. With WDP, these data is available in real time and can be referred to change the drilling parameters to mitigate the problem.

45

Teesside University

Enhancing Directional Drilling using WDP 2.3.2.2.6 Hidden Non-Productive Time Reduction There are some operation which will not contribute to the non-productive time directly, however the time required for these operations can be significantly higher and must be reduced. 

Survey: the time saving could exceed three minutes per successful survey. Shallow hole testing (Manning et al., 2008) .



Downlink: commands to control downhole tool trajectory can be done instantly which will ensure good trajectory control and reduced time for sending data.



Controlling ROP: regulation of ROP is not required due to low density images.



Troubleshooting of downhole tools: tool diagnostic data can be retrieved using MPT. If WDP is being used, a trip is necessary for retrieving the data stored in the memory of the BHA.

2.3.2.2.7 Lost Circulation Event Wired drill pipe telemetry is not affected by lost circulation materials (LCM) as it is insensitive to narrowing of the path. 2.3.2.2.8 Pore Pressure Prediction Pore pressure is predicted by analyzing acoustic measurements which requires high bandwidth to transfer them to the surface. Hence, in MPT these measurements are interpreted in the LWD logging tool and then send to the surface. The LWD tools often calculate incorrect formation velocities as it lacks the guidance of an interpreter. This will result in inaccurate prediction of pore pressure. 2.3.2.2.9 Reservoir Navigation Reservoir navigation is the process of geosteering the well based on LWD measurements in real time. Therefore, the geosteering through the defined target will be better when accurate LWD measurements are obtained at the surface for interpretation. A complete set of LWD set of data would consist of resistivity images (multiple propagation and deep-reading), nuclear porosity images and measurements, Gamma day (density) measurements and images. These images are high in size and have to be compressed to send to the surface through conventional MPT, which will sacrifice the resolution of the images. Sometimes, other measurements such as near-bit inclination, azimuth, downhole 46

Teesside University

Enhancing Directional Drilling using WDP dynamics, borehole caliper and even annular pressure have to be sacrificed or send uphole less frequently to send these images. The high bandwidth and data rate of WDP will enable the transfer of these images to the surface in real time.

2.4. Downhole Communication (Current Methods) A significant number of wells currently being drilled are using mud pulse telemetry (MPT) as the downhole communication technique. However, there are some unconventional situations such as under balanced drilling (UBD) where electromagnetic telemetry system (EMT) is being used as the telemetry technique. The procedures that are currently being used assuming that mud pulse telemetry system is employed are as follows. 2.4.1 Operation The MWD tools are examined and programmed at the surface before tripping into the hole. The tools are programmed as required by the client to send different kinds of data, which will be unique for different client and the characteristics of the well will also be considered. When the well advances closer and closer to the reservoir, the data required gets larger and larger. Hence the data rate should be increased as the well advances closer to the well to be capable of receiving high-resolution data. A large amount of data is essential for drilling the well at its best. The resolution of the MWD logs is very important while geo-steering in the well. However, the drilling performance parameters and formation evaluation parameters are equally important for the directional driller. The rate at which the mud-pulser can send data to the surface is limited. To increase the quantity of data received at the surface per meters drilled, the rate of penetration (ROP) has to be limited. Hence, the rig time consumed for drilling/logging is more than actually necessary. However, reducing the ROP would only improve the data density of the parameters that are dependent upon the position of the tool in the well such as parameters of the formation. The parameters that varies with time such as strain, vibration and pressure, will be sent to the surface and saved in the memory with the same data density irrespective of the ROP.

47

Teesside University

Enhancing Directional Drilling using WDP 2.4.2 Survey Three components such as measured depth, inclination and azimuth are regularly measured while drilling a borehole at a specific location near to the drill bit. While drilling a directional well frequent measurements may be performed in order to enable a more accurate control of the wellbore trajectory. To achieve an excellent measurement, the drill string should be kept stationary. The MWD tool will carry out a measurement only when the tool is not rotating and hence the flow of mud through the tool should be reduced in order to keep the tool stationary. The tool carry out the measurements and send them back to the surface immediately when the flow is brought back. The time taken to take each survey depends upon the start-up rate of the mud-pulser and the rate at which the measured data is sent to the surface.

Fig 30: Operating sequence for the survey clearly depicting the general time required for a survey taken by MPT. (Spinnler, Stone and Williams, 1978)

48

Teesside University

Enhancing Directional Drilling using WDP 2.4.3 Downlink The down-hole tool will not be able to identify the instruction it has to carryout unless a variation in RPM or flow rate is made during downlinks. When downlinks are being performed, it is required to stop the transfer of data from down hole to the surface. This is the case when old generation mud pulsars were being used. Now, the new generation mud pulsars can identify the instruction send from the surface with out varying the RPM or flow rate during downlinks and it is possible to continue transferring data to the surface. However, to recognize and make sure that the downlink was successful it is necessary to stop sending data to the surface at the end of the downlink. Clearly, this will create poor real time logs. Similarly, continuing drilling while sending downlinks will cause poorer data resolution on the logs. Under these circumstances, the rate of penetration (ROP) has to be decreased while downlinking to ensure good data resolution. In some occasions, the drilling may have to be stopped until the downlink is complete. Furthermore, it requires several minutes for the bottom hole tool to confirm that the downlink command has ben received. In geo-steering the well, the adjustments to the well path is aided by down-hole measurement while drilling (MWD) data in real time. In some occasions, it is required to send huge amount of data to the steering unit for adjusting parameters if the well is complicated and the trajectory is tight and even the drilling might be stopped in order to get a good resolution log.

2.4.4 Drilling Parameters Optimization The quality of data obtained from the down hole is highly significant for real time drilling optimization. The data received should be accurate and more over the data has to reach the surface for interpretation in real time (Eren et al., 2010). When conventional MPT is used for transmitting data to the surface assuming moderate transmission rates, it is normal to send data to the surface every 45 to 60 seconds. However, when high ROP is desirable for drilling the update rates stated above are not adequate and will provide only an incomplete picture of the down-hole drilling dynamics. Several kinds of vibration can occur while drilling such as vertical, lateral and torsional vibration. Stick slip is the most violent type of torsional vibration, which can cause severe damage to the wellbore if not controlled. Stick and slip as implied by its 49

Teesside University

Enhancing Directional Drilling using WDP name has a sticking phase and a slipping phase. During the sticking phase the BHA stops for a finite time interval and during the slipping phase the angular velocity increases two to three times the imposed velocity (Zakuan et al., 2011). It has been observed that stick slip occurs mostly under high weight on bit and low angular velocity, which is typically called as the RPM (Brett, 1992). Controlling various drilling parameters such as increasing the rotary speed, decreasing the weight on bit (WOB) and changing mud characteristics can be employed to reduce the chances of stick slip (Sananikone et al., 1992). Hence, its is essential to monitor the vibration data in real time in order to control rotary speed and weight on bit (WOB) to eliminate or mitigate stick slip. As the bandwidth of mud pulse telemetry is low, sometimes it is necessary to restrict or stop some dynamic sensor data for maximizing bandwidth available for the real time drilling and formation evaluation parameters. The stick slip effects become greater as the wells become deeper and more inclined and hence it is substantial in directional drilling (Kyllingstad et al., 1987).

2.4.5 Reservoir Navigation Reservoir navigation can be described as pro-active geosteering using LWD measurements to update geological models in real-time, and thereby refining the well path to stay in a defined formation target (Hernandez et al., 2008). Apparently, if the measurement data from MWD are complete and can be transferred to the surface in real time, the reservoir navigation will be more accurate. However, a complete set of MWD data set will include formation resistivity measurements, natural gamma ray images, nuclear porosity measurements and images etc. that are large in size and require high bandwidth to transfer them to the surface in real time. Even though conventional mud pulse telemetry (MPT) system has low bandwidth, it is possible to send data by employing highly sophisticated data compression techniques, which will sacrifice the resolution of the data and timeliness to transfer to the surface. As a result, drilling performance parameters such as inclination, azimuth, tool face, and even annular pressure may have to be sacrificed or sent to the surface less frequently. Just as critical as drilling the wellbore accurately and effectively is the ability to place it in the optimum way for maximum reservoir exposure (Klotz et al., 2008). The clarity of the downhole picture and the decisions made are directly proportional to the 50

Teesside University

Enhancing Directional Drilling using WDP transmission rate. To place the wellbore accurately, a high-speed telemetry system is required.

2.4.6 LWD Formation pressure test Formation pressure tests are used to vary drilling fluid properties to avoid kicks and losses aided by LWD/MWD pressure testing tool. During the pressure test, the drill string has to be kept stationary. The LWD tool deploys the test pad after receiving a downlink command from the surface to start the test. If the downlink command send from the surface were slow, it would effectively create a lag to start the test. When MPT system is employed for sending commands down hole, real time monitoring of the pressure test is not possible. The results of the test send to the surface take a considerable amount of time even with data compression techniques. Moreover, in case of a poor test (for example, as a result of poor seal), the test cannot be immediately stopped and re-started.

2.4.7 Well control operations Well control operations are the methods used to minimize the potential for the well to flow or kick and maintain control of the well in the event of flow or kick (IADC, 2013). Two methods are extensively used for well control such as ‘Drillers Method’ or ‘Wait and Weight’ method. Irrespective of the method used it is necessary to maintain the bottom-hole pressure marginally above the formation pressure to avoid further inflow of formation fluid. If the bottom-hole pressure is maintained slightly above the formation pressure, it will help to prevent fracturing other exposed layer and can avoid developing a condition for an underground blowout. The calculation of bottomhole pressure required, kill mud density and the amount of fluids required to circulate out the inflow contain sources of uncertainty. Some of these sources of uncertainty as described by Hernandez et al. (2008) are: 

The variation in drilling fluid density cannot be determined due to entrained cuttings, sag, air bubbles etc.



Some surface pressure gauges read less precisely at lower pressures.



When calculating the fluid volumes and heights, the borehole washouts are not considered. 51

Teesside University

Enhancing Directional Drilling using WDP 

The efficiencies of the pump may not be fully described to determine the volume of fluid circulated.



Formation ballooning (wellbore breathing or micro fracture) due to ECD variations when the pumps are on and off.



Bit pressure drop changes in case if the bit nozzle is plugged or lost due to well control operation.



Partial pack off due to partial blockage of the annulus, for example formation of hydrates in deep water wells, during well control operation.



Parameters such as fluid compressibility, density and rheological parameters (for example viscosity) not being considered which are affected by down hole pressure and temperature.



Assumption that annular pressure losses (ECD effects are so small at kill flow rates that they can be ignored.

In most cases of killing operations, the process is done below the flow rate at which the MWD tools can efficiently transfer a decodable mud pulse and so the downhole pressure gauges attached on the MWD tool cannot be used. Consequently, the uncertainties associated with the well control is increased. Conventional mud pulse telemetry mud pulsers are exposed to blockage when lost circulation materials (LCM) are pumped. This can result in a transmission loss or sometimes even can result in total blockage of the drill sting preventing further circulation of the drilling fluids. This normally necessitates a trip out of the hole to replace the blocked MPT system which can be very troublesome and uneconomic.

2.4.8 Trouble Shooting In an event of failure of tools downhole, a diagnostic downlink is sent to request for parameter that are not normally sent to the surface from the tool. For instance, this could be the current/voltage output or input to the different components in the BHA. These data is then compared with the reference values that are available to help in troubleshooting process and a costly trip might can be avoided. The system diagnostic data should be available in real-time. If the telemetry system is slow, it would be difficult for the technician to troubleshoot problems more rapidly and with better confidence.

52

Teesside University


Chapter 3 Case Studies

53

Teesside University


3. CASE STUDIES Case Studies on Wireless Drill Pipe deployment in different fields Four case studies has been chosen with different scenarios. In all the cases discussed, the most obvious advantages of using wired pipe telemetry, which has been explained in section 3.2.2 prevails. All four cases employs rotary steerable system (RSS) as directional drilling equipment and measurement while drilling (MWD) for logging. Mud pulse telemetry system has been used as a backup in all the cases to have full telemetry redundancy. The case studies provide substantial reasons why wired drill pipe telemetry should be employed in such circumstances.

3.1 Case study 1: Occidental of Elk Hills, Inc. (OEHI) in kern County, California (Allen et al., 2009) Kern County covers a significant oil producing area of the United States, with many large fields. Elk hills is nearly 20 miles west of Bakersfield, is the fifth largest oil field in California and one of the most productive fields in the country (Brown, 2009) . The production in Elk Hills started in 1911 and was held back as the nation’s first Naval Petroleum Reserve for the U.S. Navy. The cumulative production was close to 1.3 billion barrels as informed by California Department of Conservation (2006) annual report. Key issues: 

Equivalent circulating density (ECD) management and pore pressure density management were the critical problems encountered in the field. Also, the sandstones and siltstones in the formations exhibited high porosity of about 30% and the permeability was generally variable, but usually low (10md to several 100md) (Callison and Jones, 2002) . As the well has low permeability, it is essential to do underbalanced drilling with foam as drilling fluid. Furthermore, to be able to provide with proper ECD management and pore pressure management, foam drilling has to be employed. The operation of MPT system in foam drilling environment is operationally inefficient and sometimes even shut down the bottom hole assembly. This happens due to the lack of data flow continuously as a result of non-uniform density and flow rate of the drilling fluid. The mud pulses 54

Teesside University

Enhancing Directional Drilling using WDP requires uniform density for transmission at faster rates. Commonly, this can result in the switching on/off of the downhole tools due to the abnormal voltage input from the power turbines in the system. 

Another problem encountered while drilling was the downlink time and the time required to confirm that the signal has reached downhole, which was substantially high for MPT system. This created a large non-productive time of about 10-12% of the total time required to drill the well.



An additional problem encountered while drilling with MPT on this field was shock, vibration and stick slip. Shock, vibration and stick slip can vary rapidly with time, so the MWD data of these parameter varies very quickly. MPT system is incapable of sending these data from the MWD tool to the surface at high transmission rates to interpret them, even if the data is compressed due to the low bandwidth. This will result in severe damage to the well bore, as the operator cannot take necessary actions in order to mitigate the shock and vibration due to the vaguely generated data. Sometimes, even a trip was required to retrieve the memory quality data as it cannot be transferred through MPT due to the high quality and quantity of this data.

Project impact/accomplishments: In this case study, out of the 17 wells analyzed, 5 were drilled using foam as the drilling fluid with 4-in. wired drillpipe and 63/4-in. bit. The use of wired drill pipe telemetry provided higher resolution spectral gamma ray and azimuthal gamma ray images to be transmitted to the surface in real time which aided in better bed identification and well placement decisions (Xu et al., 2015) . Interpretation of the log will help to understand what type of formations are being drilled (for example, the radioactivity in shales will be higher than other formations and hence the API in the graph) in real time. The following figure represents the gamma ray log image acquired via WDP.

55

Teesside University


Fig 31: Plot of log image attained via wired drill pipe telemetry while using foam as drilling fluid. The log consists of spectral gamma ray and azimuthal gamma ray images that can aid for better well bore placement and bed identification. MPT transmits these data with high resolution in real time to the surface (Allen et al., 2009) .

To reduce or remove non-productive time (NPT) associated with downlinking, WDP telemetry was employed in the field. The WDP telemetry allowed bi-directional high speed communication between the downhole tools and surface equipment which in turn enabled better control of the rotary steerable systems. Hence, the real time bi-directional control enabled to remove NPT and improved trajectory control. The initial two wells drilled with WDP in this field acquired a drilling time saving of nearly 4 and 6.25 hours respectively, which is depicted in Fig 32. The total time required to drill these wells were 43.4 and 41.5 hours which saved approximately 10 to 12 % of the total drilling time. 56

Teesside University


Well

No. of

Downlink Time and

Time Saved

Downlinks

conformation

(hr:mm)

(hr:mm) 25 bps Mud

A

58

04:00

0

B

71

04:15

0

C

54

03:45

0

1

50

N/A

04:02

2

72

N/A

06:24

3

62

N/A

04:00

Pulse Telemetry

Wired Pipe Telemetry

Fig 32: Downlink efficiency comparison during the project employing MPT and WDP in the same field (Allen et al., 2009) .

The problem related to shock, vibration and stick slip was resolved after installing WDP, as the memory quality data can be retrieved in real time and at high resolution due to high data rate. The instantaneous peak in vibration data can be transferred by WDP. Fig 33 and Fig 34 below depicts two cases of vibration data acquired by the MWD tool and transferred through WDP. The first case has no damaging vibration and is showing the vibration data in a 25 minutes time frame. The resolution of data is excellent and the update occurs every 10 seconds. The second case has damaging vibration in the time frame of 23:05:00 – 23:14:00 and 23:22:00 – 23:26:00 and the drilling engineer can adjust the parameters to mitigate the vibration.

57

Teesside University


Fig 33: MWD log showing no damaging vibration (Allen et al., 2009) .

Fig 34: MWD log showing damaging vibration which can be obviously inferred referring to the log and necessary action can be taken to mitigate the vibration (Allen et al., 2009) . 58

Teesside University

Enhancing Directional Drilling using WDP Fig 35 below depicts the data tracks acquired by both MPT and WDP. Apparently, the data acquired by WDP is of high resolution whereas the data acquired by MPT is vague. The data acquired from mud pulses is not precise as the update of the data occurs only every 60 to 180 seconds. The variation in stick slip is a gradually increasing in the case of MPT whereas sudden peaks in data can be obtained by WDP. Considering the time 04:36:00, where the stick slip is actually high, has not been noted by MPT. Furthermore, the lateral vibration depicted by MPT is a straight line, which implies that the sudden changes in lateral vibrations are not logged and WDP shows precise changes in lateral vibration in real time. Thus the extra data obtained from wired pipe system make it capable to acquire clearer image of drilling dynamics and hence optimizes drilling performance.

Fig 35: Mud pulse telemetry and Wired drill pipe measurements comparison (Allen et al., 2009) As mentioned earlier, ECD management was an important problem in this reservoir due to formation damage, hence the ECD should be controlled precisely in real time. To be able to do so, the ECD data measured by the MWD tool must reach the surface equipment in real time and with great resolution so that the project engineer can vary the parameters to maintain them in a particular window guidelines.

59

Teesside University


Fig 36: Unpredictable ECD measurements shown precisely by WDP (Allen et al., 2009) . Inference: o In low permeability formations, underbalanced drilling using foam as drilling fluid may be required to provide proper ECD and pore pressure management. Mud pulse telemetry cannot be used under these circumstances as it needs constant density for the transmission of mud pulses. Hence, WDP has to be employed. o WDP can save drilling time of approximately 10 to 12% by substantially reducing the drilling time. o Shock, vibration and stick slip can vary rapidly and requires high speed telemetry to detect them in high resolution. o 3.2 Case Study 2: Offshore Trinidad Fields in Trinidad and Tobago (Edwards et al., 2013) Trinidad fields are located on the southeast corner of the Caribbean Plate and within the Eastern Venezuelan Basin. (Miningmaven, 2013) . It is one of the largest oil provinces in the world with over 3 billion barrels of oil produced till 2013. Generally, the wells drilled in offshore Trinidad fields are multiple high angle wells drilled from a single fixed platform.

60

Teesside University


Key issues: 

In this case study considered, the well being drilled is a big bore gas well with 103/4 in. casing on the top of the reservoir at 10,000 to 13,000 total vertical depth. Adding to the challenge, the hole angle approaching the reservoir is more than 60°. The big bore gas wells were drilled to reduce the number of wells being drilled and also to increase the production rate (Clancey et al., 2007) .



Another problem encountered while drilling in this well was excessive wellbore instability. The instability arouse from drilling softer sediments which has the tendency to wash out when drilled resulting in the removal of support for the inclined BHA and leads to serious downhole dynamics problems such as whirl and stick slip. Subsequently, this will cause the tool to fail if not fixed quickly.



As highly inclined big bore gas wells were drilled in the soft sediment environment, the transportation of big caving size materials were very difficult. This makes the LWD images even more valuable as it aids to improve the capability for early detection of well bore instability and necessary actions can be taken to avoid the loss of hole section. Currently, as MPT is employed, the images sent to the surface are either not delivered or a compressed low resolution image. These images are normally inadequate for deducing well bore stability issues. However, high quality images and data can be acquired by reducing the rate of penetration to 60 ft/hour as the amount of data is low, the traffic is low and hence relatively higher quality images can be retrieved at the surface.

Project impact/ accomplishments: Better quality gamma ray (density) image will help to recognize and diagnose wellbore instability problems. All of the data logged by LWD tools are not transmitted to the surface while using MPT system. The remaining data can be retrieved only when a trip is made. On the other hand, when WDP is used the gamma ray images can be transferred to the surface without any lag. Fig 37 depicts a memory quality image acquired from a 150ft measured depth high angle shale section of the well. The image was captured during an interval when WDP was not available and the telemetry system was switched to MPT. The image clearly shows the instability that was occurring while drilling without the benefits if real time images from 61

Teesside University

Enhancing Directional Drilling using WDP WDP. The dark areas in the gamma ray images depicts the failed well bore walls. The hole drilled was in good shape one hour after drilling (it took 1 hour for the logging tool to pass the formation). Only a slight amount of instability is visible in the short spaced density images. After drilling half way through there was a pause in drilling. As the sensors are placed 75 ft. behind the drill bit, the drill bit have to travel 75 ft. further to log 150 ft. depth. 6.5 hours was required to log the second interval and in the meantime the well bore had suffered considerable instability. The whole length of the well bore was relogged after a time interval of 10 hours. By the time, the well bore became unstable. Due to excessive instability, the hole was lost and had to be re-drilled.

Fig 37: Gamma ray image logged using MPT while the WDP was unavailable (Edwards et al., 2013)

62

Teesside University


As the hole section drilled using MPT was lost, the hole had to be re-drilled with WDP. WDP was capable of providing real-time images so that the mud weight can be adjusted (increased) to prevent the instability of the hole. However, the mud weight cannot be increased beyond a limit and has to be a good balancing act as the interval is exposed to large amount of sand and will result in losses and differential sticking. The equivalent interval drilled instead of the lost hole is depicted in Fig 38. This interval was drilled using WDP and hence real-time images were available. A mud-weight of 12.6 PPG was employed in order to drill the well and the well was showing slight instabilities. However, due to the previous experience, it was decided to increase the mud weight to 13.1 PPG. Apparently, the influence of rise in mud weight on the hole stability can be inferred from the figure.

Fig 38: LWD images acquired during re-drilling of an equivalent interval which was lost (shown in Fig 7). After increasing the mud weight from 12.6 to 13.1 ppg, the well delivered higher stability. 63

Teesside University


Inference: o The wellbore instability problems aroused due to the presence of soft sediments can only be reduced by analyzing the gamma ray (high density) images acquired by the MWD system in real-time. o To deliver these images in real time, a high speed telemetry system is essential and hence MPT should be employed under such circumstances. o After analyzing the gamma ray images, the mud weight can be increased to mitigate the instability problem.

3.3 Case Study 3: Troll fields in Norway (Wolter et al., 2007) The Troll field is located nearly 80 km northwest of Bergen in the Norwegian North Sea. The area of the field is approximately 770 km2. It contains a thin oil column (10-26 m) which is exploitable below a thick gas column. It is one of the largest oil fields on the Norwegian continental shelf. The well under consideration is a re-entry drilling program including a sidetrack. Key Issues: Calcite stringers which were up to several meters thick were present throughout the reservoir. The prediction of these calcite stringers are impossible as they are developed locally. When a calcite stringer is encountered, the bit may be forced into more drillable formation resulting in high local doglegs (HLD) which is illustrated in Fig 39.

Fig 39: Illustration of high local dogleg (HLD) (Hood et al., 2003) 64

Teesside University


Often, this can result in fatigue, due to stress in the BHA and bending related damage to the tools. The extent of fatigue depends on the severity of HLD. The hard calcite stringers also leads to reduction in ROP. This problem can only be mitigated by knowing the change of formation hardness in time. Project impact/ accomplishments: The calcite stringers were identified through high density drilling dynamics and bending data in real-time and necessary corrective actions were taken to minimize the local doglegs. The RSS steering parameters were changed instantaneously and hence the drilling time which should have been used to flatten out these doglegs were greatly reduced. The wellbore developed after implementing WDP system was smoother and caused only little stress on the BHA and reduced the bending related tool issues, unlike the previous Troll wells. Inference: To mitigate the high local dogleg, two conditions has to be satisfied: o The high density drilling dynamics and bending data should reach the surface in real-time so that the presence of HLD can be identified. o To take the necessary action for mitigating the identified HLD, certain drilling parameters have to be changed instantaneously. To satisfy both of these conditions, a high bandwidth and high data rate telemetry system is required. Only WDP can provide such high bandwidth and data rate.

3.4 Case Study 4: Southern Mexico (Dorel et al., 2013) The well is located in Southern Mexico and has complex structure separated by salt intrusion. The reservoirs are present in the Kimmeridgian-Jurassic and in Middle and Lower Cretaceous interval.

65

Teesside University

Enhancing Directional Drilling using WDP Key issues: 

The reservoir pressure is substantially low and so it is essential to supply a gasfluid system to avoid lost-circulation problems. The gas-fluid system is used to reduce the hydrostatic pressure and this will result in some operational threats such as wellbore collapse and fluid influx.



Mud pulse telemetry system cannot be employed due to high nitrogen-injection rates and also full directional control cannot be achieved due to increase in fluid compressibility which results in the decrease in pressure signals.

Project impact/accomplishments: Real-time survey data was available in gas fluid environment which helped to mitigate lost circulation events, wellbore collapse. Retrieving the pressure measurements instantaneously made it possible to monitor the downhole pressure precisely. Inference: o In low pressure reservoirs where gas-fluid system has to be used as drilling fluid, only wired drill pipe telemetry system can be used to mitigate lost circulation and wellbore instability problems.

The following table differentiates the challenges associated with drilling before implementing WDP and the benefits after implementing WDP. The table provides a briefing of all the case studies discussed earlier. No.

Well Location

Challenge

Benefits after

Author

implementing WDP

1

Occidental of Elk Hills in Kern County, California, U.S.A.

-Low permeability

-Underbalanced drilling

(Allen et

formation requiring proper ECD and pore pressure management.

with foam as drilling fluid was employed.

al., 2009)

-Limited ability to communicate with downhole consumes rig time. -Rapid shock, vibration and stick slip tendencies

66

-Instant commands and confirmation through realtime bi-directional communication saved approx. 10-12% of drilling time.

Teesside University


2

Offshore Trinidad fields in Trinidad and Tobago.

and limited measurements availability.

-High resolution data

-Excessive wellbore

-High definition images

(Edwards

instability due to soft sediments resulting in washout.

(gamma ray) of borehole delivered in real-time.

et al.,

-HLD detected by the real

(Wolter et al., 2007)

available in real-time.

2013)

-Limited data availability in real time to recognize borehole instability.

3

Troll fields in Norway.

-Presence of calcite stringers resulting in high local doglegs (HLD) which in turn will result in BHA fatigue and low ROP.

time availability of accurate data. -Drilling parameters changed instantaneously to mitigate HLD.

-Limited bending and high density drilling data availability.

4

Southern Mexico.

-Substantially low

-Gas-fluid environment

reservoir pressure resulted in lost circulation and wellbore collapse.

does not affect WDP and hence real time data was available.

-Required gas-fluid system to mitigate the problems caused by low pressure reservoir.

- Pressure measurement possible all along the drillstring enabled monitoring of pressure across entire wellbore.

-High fluid compressibility resulted in poor pressure signals.

(Dorel et al., 2013)

Table 1: Challenges before implementing WDP and benefits after implementing WDP based on the case studies considered.

67

Teesside University


Chapter 4 Conclusion and Recommendations

68

Teesside University

Enhancing Directional Drilling using WDP 4. CONCLUSIONS AND RECOMMENDATIONS Based on the literature review discussed and case studies analyzed, it can be concluded that the correct deployment of wired drill pipe telemetry in conjunction with rotary steerable systems (RSS) and measurement while drilling system (MWD) is capable of delivering new opportunities and increase the value of the project such as: 

ROP improvement



Smoother wellbore



Enable drilling in underbalanced environment



Along string pressure management



Reduction in high local doglegs (HLD)



Improved reservoir exposure due to accurate geo-steering.

The system offer transmission rates that are thousands of times higher than mud pulse telemetry system and hence it enable full value to be extracted from the escalating amount of real time data from new rotary steerable systems. However, wired pipe telemetry has certain reliability issues and hence it has to be used in conjunction with mud pulse telemetry for full telemetry redundancy. Moreover, the display and interpretation of massive amounts of data is challenging. In all four case studies considered, the wired drill pipe telemetry system was implemented with equipment designed to work with the former mud pulse telemetry system. In the near future, the drilling is going to be more deep and challenging and hence high definition real-time data will be required to enable drilling. As a result, wired drill pipe technology is going to be more significant in near future. Recommendations: Currently, the along string sensors present on the wired drillpipe are capable of only measuring temperature and pressure. If these sensors are capable of measuring further drilling parameters such as flow rate, it would lead to better control of the well. Wired drill pipe telemetry should be used only in harsh environments where the use of mud pulse telemetry results in high non-productive time (NPT) as the cost of implementation of wired pipes are high.

69

Teesside University

Enhancing Directional Drilling using WDP 5. REFERENCES Al Yami, H., Kubaisi, A., Nawaz, K., Awan, A.H., Verma, J.K. and Ganda, S. (2008) 'Powered Rotary Steerable Systems Offer a Step Change in Drilling Performance', SPE Asia Pacific Oil and Gas Conference and Exhibition. Perth, Australia, 20-22 October. Society of Petroleum Engineers. Allen, F., Tooms, P., Conran, G., Lesso, B. and Van de Slijke, P. (1997) 'Extended reach drilling: break the 10 km barrier', Oilfield Review, 9 (4), pp. 32-47. Allen, S., McCartney, C., Hernandez, M., Reeves, M., Baksh, A. and MacFarlane, D. (2009) 'Step-change improvements with wired-pipe telemetry', SPE/IADC Drilling Conference and Exhibition. Amsterdam, The Netherlands., 17-19 March. SPE. American Oil & Gas Historical Society (2015) Technology and the "Conroe Crater". Available at: http://aoghs.org/technology/directional-drilling/ (Accessed: 31 July 2015). Arps, J.J. and Arps, J.L. (1964) 'The subsurfae telemetry problem- A practical solution', The British-American Oil Producing Co.,. Baker Hughes (1997) Baker Hughes INTEQ's guide to measurement while drilling. Houston, TX: Baker Hughes INTEQ. Brett, J. (1992) 'The genesis of torsional vibration', SPE Drilling Engineering, . Brown, D. (2009) Elk Hills 'Secrets' being revealed. Tulsa, OK: American Association of Petroleum Geologists. Bryan, H.H., Cox, J., Blackwell, D., Slayden, F.W. and Naganathan, S. (2009) 'Highdogleg rotary-steerable systems: A step change in drilling process', SPE Annual Technical Conference and Exhibition. New Orleans, Louisiana, 4-7 October. Society of Petroleum Engineers. Bybee, K. (2008) 'High-speed wired-drillstring technology', Journal of Petroleum Technology, pp. 76-79. California Department of Conservation (2006) Oil and gas statistics, Annual report. California Department of Conservation. Callison, D. and Jones, J. (2002) 'Integrated modelling of a field of wells- An evaluation of western shallow oil zone completion practices in the Elk Hills field, Kern County,

70

Teesside University

Enhancing Directional Drilling using WDP California.', SPE/AAPG Weastern Regional Meeting. Anchorage, Alaska, 20-22 May. Society of Petroleum Engineers. Clancey, B.M., Khemakhem, A.S.D., Bene, T.F. and Schmidt, M.H. (2007) 'Design, construction and optimization of big-bore gas wells in a giant offshore field', SPE/IADC Drilling Conference. Amsterdam, The Netherlands, 20-22 February. Society of Petroleum Engineers. Desbrandes, R. (1988) 'Status report: MWD technology, Part 2- Data transmisssion', Petroleum Engineer International, pp. 48-54. Dorel, A., Azizi, T., David, A., Duran, E., Lopez, H., Aguinaga, G., Beltran, J.C. and Ospino, A. (2013) 'Using Wired-drillpipe technology during managed pressure drilling operation to maintain directional control, constant bottomhole pressure, and wellbore integrity in deep, ultradepleted reservoir', SPE/IADC Drilling Conference and Exhibition. Amsterdam, The Netherlands, 5-7 March. Society of Petroleum Engineers. Downton, G., Klausen, T.S., Hendricks, A. and Pafitis, D. (2000) 'New directions in rotary steerable drilling', Oil Field Review, 12, pp. 18-29. Dwyer, R.P. (1959) 'Recent advances in directional drilling', American Petroleum Institute, . Edwards, S.T., Coley, C.J., Whitley, N.A., Keck, R.G., Ramnath, V., Foster, T. and Honey, M. (2013) ' A summary of wired drill pipe field trials and deployment in Bp', SPE/IADC Drilling Conference. Amsterdam, Netherlands, 5-7 March. Society of Petroleum Engineers. Eren, T. and Ozbayoglu, M.E. (2010) Real time optimization of drlling parameters during drilling operation. Felczak, E., Torre, A., Godwin, N.D., Mantle, K., Naganathan, S., Hawkins, R., Li, K., Jones, S. and Slayden, F. (2012) 'The best of both worlds- A hybrid rotary steerable system', Oilfield Review, 23 (4), pp. 36-45. Gravley, W. (1983) 'Review of downhole measurement-while-drilling system', Journal of Petroleum Technology, , pp. 1439-1445. Hdigauges

(2015)

HDI

2100

pump

stroke

counter

system.

http://hdigauges.com/products/hdi-2100-mud-pump-stroke-counter/ August 2015). 71

Available (Accessed:

at: 28

Teesside University

Enhancing Directional Drilling using WDP Hernandez, M., MacNeill, D., Reeves, M., Kirkwood, A., Lemke, S., Ruszka, j. and Zaeper, R. (2008) 'High speed wired drill string telemetry network delivers increased safety, efficiency, reliability and productivity to the drilling industry', Indian Oil and Gas Technical Conference and Exhibition. Mumbai, 4-6 March. Hood, J., Hovden, J., Heisig, G., Ernesti, K.D. and Knipper, A. (2003) 'Real-time BHA bending information reduces risk when drilling hard interbedded formations', SPE/IADC Drilling Conference. Amsterdam, The Netherlands, 19-21 February. Society of Petroleum Engineers. Hutin, R., Tennent, R.W. and Kashikar, S.V. (2001) 'New mud pulse telemetry technique for deepwater application and improved real time data capabilities.', SPE/IADC Drilling Conference. Amsterdam, Netherlands., 27 February- 1 March. SPE/IADC. IADC (2013) Well control. Available at: www.iadclexicon.org/well-control/ (Accessed: 26 August 2015). Inglis, T.A. (1987) Petroleum engineering and development studies: Directional drilling. London: Graham & Trotmen Limited. Jellison, M.J., Hall, D.R., Howard, D.C., Hall, H.T., Long, R.C., Chandler, R.B. and Pixton, D.S. (2003) ' Telemetry drill pipe: Enabling technology for the downhole internet', SPE/IADC Drilling Conference. Amsterdam, The Netherlands, 19-21 February. Society of Petroleum Engineers. Jianhui, Z., Liyan, W., Fan, L. and Yanlei, L. (2007) 'An effective approach for the noise removal of mud pulse telemetry system', The Eighth International Conference on Electronic Measurement and Instruments. Beijing, China, 16-18 August. ICEMI. Klotz, C., Kaniappan, A., Thorsen, A.K., Nathan, E., Jahangir, M. and Lie, L. (2008) 'A new mud pulse telemetry system reduces risk when drilling complex extended reach wells', IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition. Jakarta, Indonesia, 25-27 August. Society of Petroleum Engineers. Kyllingstad, A. and Halsey, G.W. (1987) 'A study of slip-stick motion of the bit', 62nd Annual Technical Conference and Exhibition of the Society of Petroleum Engineers. Dallas, TX, September 27-30. Manning, M.J., Macpherson, J.D., Taylor, D.E., Baksh, N., Peveto, C., Farnsworth, L. and Lemke, S.R. (2008) 'Wired pipe enabled logging while drilling applications', 72

Teesside University

Enhancing Directional Drilling using WDP International Petroleum Technology Conference. Kuala Lumpur, Malaysia, 3-5 December. International Petroleum Technology Conference. Mantle, K. (2013) 'The art of controlling wellbore trajectory', Oilfield Review, 25 (4), pp. 54-55. McCartney, C., Allen, S., Hernandez, M., MacFarlane, D., Baksh, A. and Reeves, M.E. (2009) 'Step-change improvements with wired-pipe telemetry', SPE/IADC Drilling Conference and Exhibition. Amsterdam, The Netherlands, 17-19 march. Society of Petroleum Engineers. McMillian, K. (1999) 'Rotary steerable systems creacting niche in extended reach drilling', Offshore Magazine, 59 (2), pp. 52-124. Miningmaven (2013) Trinidad oil report. Mining Maven. Moody, M., Jones, S. and Leonard, P. (2004) 'Development & Field-Testing of a Cost Effective Rotary Steerable System', SPE Annual Technical Conference and Exhibition. Houston, Texas., 26-29 September. Society of Petroleum Engineers. Patton, B.J., Gravley, W., Godbey, J.K., Sexton, J.H., Hawk, D.E., Slover, V.R. and Harrell, J.W. (1977) 'Development and successful testing of a continuous-wave, Loggingwhile-drilling telemetry system', Journal of Petroleum Technology, 29(10). Reeves, M.E., Prideco, G., Payne, M.L., Ismayilov, A.G. and Jellison, M.J. (2005) 'Intelligent drill string field trials demonstrate technology functionality', SPE/IADC Drilling Conference. Amsterdam, The Netherlands, 23-24 february. Society of Petroleum Engineers. Roberts, D.L. (1949) 'Directional drilling in Los Angeles basin', American Petroleum Institute, . Sananikone, P., Kamoshima, O. and White, D.B. (1992) A field method for controlling drillstring tortional vibration. Schaaf, S., Pafitis, D. and Guichemerre, E. (2000) 'Application of a point the bit rotary steerable system in directional drilling prototype well-bore profiles', SPE/AAPG Western Regional Meeting. Long Beach, CA, USA, 19-23 June. Society of Petroleum Engineers. Schlumberger

(2014)

Oil

field

gloassary.

http://www.glossary.oilfield.slb.com/ (Accessed: 31 August 2015).

73

Available

at:

Teesside University

Enhancing Directional Drilling using WDP Spinnler, R.F., Stone, F.A. and Williams, C.R. (1978) Mud pulse logging while drilling telemetry system- design, development, amd demonstrations. Bertlesville, Oklahoma: U.S. Department of Energy. Stimson, T.E.,Jr. (1950) 'Curves', Popular Mechanics Magazine, 93(1). Taub, H. and Schilling, D.L. (1986) , in Principles of communication systems. 2nd edn. New York: McGraw-Hill Book Company, . Wilson, A. (2013) 'Wired- drillpipe field trials reveal potential benefits over traditional pipe', Journal of Petroleum Technology, pp. 105-107. Wolter, H., Gjerding, K., Reeves, M.E., Hernandez, M., Macpherson, J.D., Heisig, G. and Zaeper, R. (2007) 'The first offshore use of an ultra high speed drillstring telemetry network involving a full LWD logging suite and rotary steerable drilling system', SPE Annual Technical Conference and Exhibition. Anaheim, California, U.S.A., 11-14 November. Society of Petroleum Engineers. Xu, L., Huiszoon, C., Wang, J., Adolph, B., Yi, J., Cavin, D., Laughlin, G., Tollefsen, E., Jacobsen, S. and Boyce, M. (2015) 'Spectral gamma ray measurement while drilling', SPWLA 56th Annual Logging Symposium. Long Beach,CA, 18-22 July. Society of Petrophysicists and Well Log Analysts. Zakuan, A., Junaida, A., Subroto, B., Hermawan, H., Fatakh, A. and Halim, A. (2011) Stick slip mitigation plan to improve drilling. Society of Petroleum Engineers.

74