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Mud motor failure should be avoided where possible and a lot of research has gone into understanding potential mitigation strategies. Previous research performed for the RAPID group at the University of Texas at Austin identified stalls as a leading cause for mud motor damage and failure, yet very little research has been done to investigate them. Temperature is known to be leading factor in reducing mud motor life and will likely be more important now than it was in the past as drilling operations increase in complexity. In this work, we present two different algorithms designed to run while drilling. The first is a statistics-based stall detection algorithm designed to run on surface data. Where stall detection has previously based itself only on the Differential Pressure, our approach requires three simultaneous peaks in MSE, WOB and Differential Pressure. The second is a temperature model for the estimation of bottomhole temperature which can serve as a real-time advisory alerting if the temperature exceeds the motor rating. Both could be implemented in a damage index for the estimation of mud motor degradation at any time

In this study, results from a realistic 3D hydrodynamic and sediment transport model, applied to a channel in the Dutch Wadden Sea, are analyzed in order to assess the effect of short-term wind forcing, the impact of fresh water effects, and the variability induced by the spring-neap cycle on the transport of suspended sediment. In the investigated region, a pilot study for sediment nourishment, the so-called Mud Motor, is executed. This project aims for the beneficial re-use of dredged harbor sediments through the disposal of these sediments at a location where natural currents are expected to transport them toward a nearby salt marsh area. The model results presented in this study advance the understanding of the driving forces that determine sediment transport in shallow, near-coastal zones, and can help to improve the design of the Mud Motor. In the investigated channel, which is oriented parallel to the coastline, tidal asymmetries generally drive a transport of sediment in flood direction. It was found that already moderate winds along the channel axis reverse (wind in ebb direction), or greatly enhance this transport, up to an export of sediment over the adjacent water shed (wind in flood direction). The most beneficial wind conditions (moderate westerly winds) can cause an accumulation of more than 90% of the initial 200 tons sediment pool on the intertidal area; during less favorable conditions (northeasterly winds), less than a third of the dumped sediment is transported onto the mudflat. On-shore winds induce a transport toward the coast. Surprisingly, sediment pathways are only sensitive to the exact disposal location in the channel during wind conditions that counteract the tidally driven transport, and freshwater effects play no significant role for the dispersal of sediment.

Mud motors are widely used for directional and performance drilling. Due to the extremely challenging operating conditions, they are prone to failures, resulting in unnecessary maintenance repair costs as well as unpredictable and very costly drilling failure. Until now, the oil and gas industry has lacked reliable procedures to monitor and maintain the health of the mud motor power sections. Recently, we systematically addressed this problem with an industry unique prognostic health management solution, which not only tracks remaining useful life (RUL), but also creates a new failure prevention scheme for operators. The key objective of this solution is to reduce maintenance costs and improve mud motor fleet reliability. It's based on a high-fidelity model and uses a hybrid approach by combining a high-fidelity physics-based model of a power section and data-driven approaches with machine learning techniques for real-time applications. The new methodology was tested in the field with great success. The verification of the created solution was completed based on numerous field data from Saudi Arabia and Argentina. Comparison of the predicted mud motor fatigue values with the actual observed post-job conditions and job failures demonstrated high fidelity of the developed models. The whole solution is currently being integrated into a drilling platform including the maintenance system, the well construction planning, and the execution. The first application of the workflow was deployed in the field in Colombia targeting reduction of maintenance cost and failure avoidance. The result was outstanding, with the initial deployment bringing about 27% of projected yearly maintenance savings and 10% of projected yearly failure reduction. It enables using the equipment to the full extent with increased drilling performance without sacrificing reliability. In addition, it optimizes the entire fleet management with reduced cost of logistics and maintenance. The findings of this paper demonstrate the value of the mud motor PHM solution for the oil and gas industry by providing accurate prognosis of power section health, leading to reduced costs, minimized NPT, and increased operational reliability.

The post COVID-19 era will undoubtedly present paradigm shifts in operational planning and execution and advanced automation will become an important factor. However, drilling automation without directional drilling (Cayeux 2020) capability will exclude the use of automation in a vast number of fields where precise placement of the wellbore has shifted from a luxury to a necessity. This is important in unconventional plays where automation can make a step change in operational outcomes (Chmela 2020). However, most efforts in automating directional drilling are using bespoke rigs (Slagmulder 2016) and bespoke bottom hole assembly (BHA) that limit operational options. The goal is in designing systems that enable directional drilling automation (Chatar 2018) with existing BHAs. This paper will look at three challenges that were identified and overcome to deploy a vendor agnostic system for automating the directional drilling (DD) process. The three challenges identified here are as follows:Using any mud motor including low-cost motors in a closed loopIntegration with an existing measurement and logging while drilling (MLWD) systemAbility to roll out automation systems on any operations with existing rigs The system is a modification of an operator’s autonomous drilling system (Rassenfoss 2011), designed to use existing rigs, BHAs and have minimum footprint on the rigs for operational use. The system will have a dedicated connection to the rig’s programmable logic controller (PLC) via common industrial protocols including Modbus, EthernetIP or Profinet, a physical connection the MLWD receiver and a brain box with a cloud connection to aggregate, process data and send commands to the rig PLC to execute directional commands. A vendor agnostic system will increase adoption of automated technologies and further drive improvements in operational and business performance.

In a fast drilling environment, suchas shale drilling, refining advanced technologies for preventing downhole toolfailures is paramount. Challenges are still very much associated with complex bottom-hole assemblies and the vibration of the drill string when used with a downhole mud motor. The mud positive displacement motor with various lobe configurations and designs becomes an additional excitation source of vibration. Further, it affects the transient behavior of the performance mud motor. Unbalanced force exists because the center ofmass of the motor rotor does not coincide with the axis of rotation.Further, the vector of full acceleration of the center of the rotor can be decomposed into two perpendicular projections—tangent and normal—which aretaken into account and integrated intothe full drill string forced frequency modelas force and displacement at the motorlocation. The paper includes two models, first one to predict the critical speeds and the second one to see the transient behavior of the downhole parameters when the mud motor is used.The model also considers the effect of the stringspeed. The unbalanced force is more pronounced at the lower pair or lobe configuration as compared to the higher pairlobe configuration because of the larger eccentricity. The unbalance is modeled in terms of an equivalent mass of therotor with the eccentricity of the rotor. Also, the analysis provides an estimation of relative bending stresses, shear forces, lateral displacements and transient bit rpm, bit torque, and weightone bit for the assembly used. Based onthe study, severe vibrations causing potentially damaging operating conditionswhen transient downhole forcing parametersare used for the vibration model.It has been found that when a mud motor isused using static forcing parameters may not provide the conservative estimation of the critical speeds as opposed totransient parameters. This is because coupled oscillations fundamentally can create new dynamic phenomena, which cannot be predicted from the characteristics of isolated elements of the drilling system.

Rotary Steerable System (RSS) has transformed the directional drilling industry by producing smoother borehole, reducing torque and drag and enhancing the Rate Of Penetration (ROP). Despite the advantages of using RSS, the conventional steerable motor is still widely used in deviated well due to its lower daily cost. Therefore, to optimize the performance and the cost of the drilling operation, it is critical to analyze when the RSS outweigh the conventional mud motor. This paper analyzes the performance between Rotary Steerable System and Conventional Steerable Motor, based on these following parameters: Rate of Penetration (ROP), overall drilling cost, borehole quality and lost in hole cost. This empirical study uses literature study and quantitative data analysis from several wells in Mavvar Field in compliment. The result shows that the Rotary Steerable System (RSS) provides better performance and more efficient in cost.

North America shale drilling is a fast-paced environment where downhole drilling equipment is pushed to the limits for maximum rate of penetration (ROP). Downhole mud motor power sections have rapidly advanced to deliver more horsepower and torque, resulting in different downhole dynamics that have not been identified in the past. High-frequency (HF) compact drilling dynamics recorders embedded in the drill bit, mud-motor bit box, and motor top sub (sub-assembly) provide unique measurements to fully understand the reaction of the steerable-motor power section under load relative to the type of rock being drilled. 3-axis shock, gyro and temperature sensors placed above and below the power section measure the dynamic response of power transfer to the bit and associated losses caused by back-drive dynamics. Detection of back-drive from surface measurements is not possible, and many measurement-while-drilling (MWD) systems do not have the measurement capability to identify the problem. Motor back-drive dynamics severity is dependent on many factors, including formation type, bit type, power section, WOB (weight on bit) and drill pipe size. The torsional energy stored and released in the drill string can be high due to the interaction between surface RPM (revolutions per minute)/torque output and mud-motor downhole RPM/torque. Torsional drill string energy wind-up and release results in variable power output at the bit, inconsistent rate of penetration (ROP), rapid fatigue on downhole equipment, and motor or drillstring back-offs and twist-offs. A new mechanism of motor back-drive dynamics due to the use of an MWD pulser above a steerable motor is discovered. HF continuous gyro sensors and pressure sensors were deployed to capture the mechanism in which a positive mud pulser reduces as much as one third of the mud flow in the motor and bit rotation speed, creating a propensity for a bit to come to a complete stop in certain conditions and for the motor to rotate the drillstring backward. We have observed the backward rotation of a PDC drill bit during severe stick-slip and back-drive events (-50 RPM above the motor), confirming that the bit rotated backward for 9 mS every 133.3 mS (at 7.5Hz), using a 1000-Hz continuous sampling/recording in-bit gyro. In one field test, multiple drillstring dynamics recorders were used to measure the motor back-drive severity along the drillstring. It is discovered that the back-drive dynamics are worse at the drillstring, approximately 1110 ft behind the bit, than these measured at the motor top-sub position. These dynamics caused drillstring back-offs and twist-offs in a particular field. A motor back-drive mitigation tool was used in the field to compare the runs with and without the mitigation tool, while keeping the surface drilling parameters nearly the same. The downhole drilling dynamics sensors were used to confirm that the mitigation tool significantly reduced stick-slip and eliminated the motor back-drive dynamics in the same depth interval. Detailed analysis of the HF embedded downhole sensor data provides an in-depth understanding of mud-motor back-drive dynamics. The cause, severity, reduction in drilling performance and risk of incident can be identified, allowing performance and cost gains to be realized. This paper will detail the advantages to understanding and reducing motor back-drive dynamics, a topic that has not commonly been discussed in the past.

Mud motor failure is a significant contributor to non-productive time in lower-cost land drilling operations, e.g. in North America. Typically, motor failure prevention methodologies range from re-designing or performing sophisticated analytical modeling of the motor power section, to modeling motor performance using high-frequency downhole measurements. In this paper, we present data analytics methods to detect and predict motor failures ahead of time using primarily surface drilling measurements.We studied critical drilling and non-drilling events as applicable to motor failure. The impacts of mud motor stalls and drill-off times were investigated during on-bottom drilling. For the off-bottom analysis, the impact of variations in connection practices (pick up practices, time spent backreaming, and time spent exposing the tools to damaging vibrations) was investigated. The relative importance of the various features found to be relevant was calculated and incorporated into a real-time mud motor damage index.A historical drilling dataset, consisting of surface data collected from 45 motor runs in lateral hole sections of unconventional shale wells drilled in early to mid-2019, was used in this study. These motor runs contained a mix of failure and non-failure cases. The model was found to accurately predict motor failure due to motor wear and tear. Generally, the higher the magnitude of the impact stalls experienced by the mud motor, the greater the probability of eventual failure. Variations in connection practices were found not to be a major wear-and-tear factor. However, it was found that connection practices varied significantly and were often driller-dependent.The overall result shows that simple surface drilling parameters can be used to predict mud motor failure. Hence, the value derived from surface sensor information for mud motor management can be maximized without the need to run more costly downhole sensors. In addition to this cost optimization, drillers can now monitor motor degradation in real-time using the new mud motor index described here.

Mud motor failure is a significant contributor to non-productive time in North American land drilling operations. Currently, there is limited work on mud motor failure analysis using surface drilling data. The objective of this work was to apply data analytics methodologies on historical drilling datasets to identify features and trends in surface data that contribute most to indicating impending mud motor failure. The methodology involved investigating a large dataset of mud motor runs for certain on-bottom and off-bottom drilling events that are generally known to be leading causes of motor failure. Spikes in differential pressure, pick up practices, drill-off time, etc., were all investigated. Additionally, the impact of temperature on mud motor failure was studied. A combination of the investigated features was analyzed using statistical measures and supervised machine learning algorithms to determine the leading contributors to motor failure. The dataset consisted of 32 motor runs drilled in the lateral section of wells from early-to-mid 2019. These motor runs represented a mix of both failure and non-failure cases. The motor stalls were categorized as either low, medium, or high impact depending on the severity of the differential pressure spike. It was observed that high impact motor stalls and the rate of stalling correlated strongly with eventual failure. Likewise, prolonged exposure to high bottom-hole temperature (exceeding the motor temperature limit) increased the risk of motor damage, most likely through thermal expansion of the stator elastomer. The drill-off time was also found to have some influence on motor failure for the investigated cases. Using these features, statistical significance tests and supervised machine learning models were trained on the dataset to determine the features that contribute most to motor failure. This work shows the feasibility of performing mud motor failure analysis using readily available surface data. It is expected to inform drilling engineers on data analysis methodologies for efficient failure analysis and help them plan future wells more efficiently.

The continued growth in unconventional drilling has resulted in downhole motors being pushed to drill more complex geometries faster, often higher downhole temperatures. This has resulted in increased rates of failure for downhole motors. The most common method to postpone motor failure has been to select a larger motor. This option ignores the root causes of motor failure and is shown to actually not improve failure rates. Impetus for this work centered on an operator who was experiencing high rates of motor failure, however in the process of investigating the failures, important findings were made that apply to any BHA with a motor. Damage occurs in all motors in the data set, regardless of whether or not they are considered "failed." This points to a potential, unrecognized industry-wide issue wherein motor performance may be degrading over a run and is not recognized by operations teams. The result is a version of "hidden NPT" which is limiting drilling performance in wells drilled with downhole motors. Calculating the RPM factors on the operator's wells using actual motor speeds measured by downhole sensors show that motor degradation is a significant problem, resulting in a reduction of up to 40% in bit RPM. In order to measure performance, motor properties are used to convert the traditional surface MSE measurement into a more representative downhole MSE. Further refinement of this metric was tested as downhole MSE is calculated using a simple factor and a more exact but complicated multi-dimensional correlation. Drilling data is used to show that the simplicity of the simple factor more than offsets minor loses in MSE accuracy. As noted, the real time RPM factors are also computed using downhole data showing the stark differences between the actual factors and the originally reported factors. The difference is used to determine the degree of motor damage while drilling. A suite of downhole sensors was placed above and below the motor to monitor the rate of motor damage. Differential pressure was also analyzed in the frequency domain spectrum to demonstrate the damaging effect of bottom hole assembly (BHA) whirl during rotating. The use of depth of cut control (DOCC) is analyzed as a method to improve motor efficiency and decrease damage. Two identical wells and BHA's are compared, one with and one without DOCC. The uses of the first derivative of differential pressure is suggested as a method to better quantify and visualize the effects of DOCC. Ultimately, the research presented provides quantitative insights into the operation of a motor, and shows that motor performance is not as expected based specification sheet values.

Cuttings transport becomes critical important when horizontal directional drilling (HDD) technology has been used more often in long distance and large diameter oil and gas pipeline construction in rocks. Front reaming (FR) and one way drilling mud return (OWDMR) were not new in oil and gas well drilling, but they were rarely used in HDD industry compared to the traditional back reaming (BR) and two way drilling mud return (TWDMR). FR and OWDMR technologies, when they were used in HDD, were designed mainly for highly non-leveled HDD projects to overcome some difficulties such as the recycling of drilling mud. Along with these technologies is that the cuttings need to travel longer distance to the ground surface. In addition, the effect of the drill rod rotation on the cuttings transport does not exist because hole bottom mud motor is usually used in FR. To find a solution for this problem, the cuttings transport mechanism was analyzed based on the drilling mud hydraulics, and then, an equation of cuttings transport distance was derived. It found that the average drilling mud velocity in the annulus and the consistency index of drilling mud are the two most important factors related to the cuttings transport distance. To help with the cuttings transport, a new MMH drilling mud system, which provides a high consistency index and a low flow index, was used in rock HDD projects, instead of the common Bentonite-water drilling mud system.

Horizontal oilwell drillstring failures are very costly. Vibration causes excessive wear and tear on the bottom hole assembly and reduces the life of the drill bit, and has motivated extensive research on these types of drillstring vibrations. Two key factors in simulation of motions of horizontal drillstrings are to have a model capturing coupling among various types of vibration, and an accurate but efficient treatment of the wellbore friction. In this paper, a bond graph dynamic model of a horizontal oilwell drillstring has been developed that predicts longitudinal motion, torsional motion, and coupling between longitudinal and torsional motion excited by bit-rock interaction. A lumped segment modeling approach of vertical drillstring dynamics has been extended to include dynamic wellbore friction in the ‘build’ and ‘horizontal’ sections of the drillstring. The model incorporates torsional viscous damping, longitudinal hydrodynamic damping, and buoyancy effect due to drilling fluid; an extended bit-rock interaction model that allows the drillstring to advance at the rate of penetration, a downhole mud motor, and top drive ac motor dynamics. The friction coefficient between drillstring and wellbore has been tuned with the aid of field data from a horizontal oilfield in Canada. The model predicts the expected coupling between weight on bit, bit speed, and bit-rock interaction conditions; and their effect on longitudinal and torsional motions. Finally, an experiment was conducted with a downhole axial vibration tool (“Agitator®”). A force excitation source, which simulates the Agitator® tool, in the longitudinal direction has been implemented in the horizontal section of the virtual drillstring. Simulations show a better weight transfer to the bit, with a low frequency and high amplitude force excitation giving best performance.

This paper is concerned with autonomous drilling using a mud motor to follow a predefined well plan for hydrocarbon exploration. The well plan contains curve & straight sections, possibly including a horizontal section that is common for non-conventional oil & gas drilling. We first introduce a steering model describing wellbore propagation response of a mud motor in the vertical plane, which contains multiple distributed delays in the depth domain. Later we address the three-dimensional well plan tracking problem by designing and combining two controllers. The first one is based on the idea of Model Predictive Control (MPC) for well-plan tracking in the vertical plane, while the second one performs Azimuthal corrections. Because mud motor control inputs comprise both continuous and binary quantities due to its physics and operation principles, the MPC problem is formulated as a Mixed-Integer-Quadratic-Programming (MIQP) problem with the goal of minimizing certain quadratic cost function. The proposed autonomous drilling method utilizes the same information available to the directional driller for feedback, which includes depth, inclination and azimuth angles at survey points. The MIQP problem is solved online each time a new survey result is available to provide optimal mud-motor control input up to the next survey in the future. The method has been field tested and proven to be both effective and reliable. Testing results are presented at the end of this paper to demonstrate the effectiveness of proposed method.

Horizontal drilling technique is one of the methodologies that have been widely implemented recently to improve the production of oil and gas wells. Several directional drilling technologies can be utilized to drill the horizontal wells, vary from the simple mud motor technology to Bottom Hole Assembly (BHA) with the advanced motorized rotary steerable system. The most common challenges that are faced on horizontal drilling process are on the torque and the stick-slip throughout drilling process, which can be a technical limiter for the length of horizontal section that would be achieved. Stick-slip is the vibration that occurs due to cyclical rotation acceleration and deceleration of the bit, BHA or drill string. This speed fluctuation can be zero to rate of penetration (ROP) or far in excess of twice the rotational speed measured at the surface. Stick-slip can significantly decrease the ROP, increases tool failures and damage, affects borehole quality, and impacts the data acquisition. Several studies had been done on the stick-slip prevention and mitigation throughout creation of new technology and drilling parameters envelope throughout drilling operation, however no study has ever been done on the modification of the design and arrangement of the BHA itself to produce more stable BHA. Drill pipe is the longest component of the drill string and hence it has biggest contribution towards the drill string dynamic. This study will focus on the analysis of the combination of several designs of the drill-pipe and heavy weight drill-pipe (HWDP) that has different stiffness and characteristic to produce less vibration, more efficient drilling operation and to create zero impact on the data acquisition measured while drilling. FEA drilling dynamic simulator was used to optimize the drill sting configuration. The calculation is made from the depth of 750 m to 2801 m. Based on the drilling simulation results of FEA modeling, it is concluded that the minimum stiffness ratio to give stability of the drill string of Well-Z7 BHA and Well-Z6 BHA is 0.012175272 and 0.07366999, respectively.

We test an innovative approach to beneficially re-use dredged sediment to enhance salt marsh development. A Mud Motor is a dredged sediment disposal in the form of a semi-continuous source of mud in a shallow tidal channel allowing natural processes to disperse the sediment to nearby mudflats and salt marshes. We describe the various steps in the design of a Mud Motor pilot: numerical simulations with a sediment transport model to explore suitable disposal locations, a tracer experiment to measure the transport fate of disposed mud, assessment of the legal requirements, and detailing the planning and technical feasibility. An extensive monitoring and research programme was designed to measure sediment transport rates and the response of intertidal mudflats and salt marshes to an increased sediment load. Measurements include the sediment transport in the tidal channel and on the shallow mudflats, the vertical accretion of intertidal mudflats and salt marsh, and the salt marsh vegetation cover and composition. In the Mud Motor pilot a total of 470,516 m3 of fine grained sediment (D50 of ∼10 μm) was disposed over two winter seasons, with an average of 22 sediment disposals per week of operation. Ship-based measurements revealed a periodic vertical salinity stratification that is inverted compared to a classical estuary and that is working against the asymmetric flood-dominated transport direction. Field measurements on the intertidal mudflats showed that the functioning of the Mud Motor, i.e. the successful increased mud transport toward the salt marsh, is significantly dependent on wind and wave forcing. Accretion measurements showed relatively large changes in surface elevation due to deposition and erosion of layers of watery mud with a thickness of up to 10 cm on a time scale of days. The measurements indicate notably higher sediment dynamics during periods of Mud Motor disposal. The salt marsh demonstrated significant vertical accretion though this has not yet led to horizontal expansion because there was more hydrodynamic stress than foreseen. In carrying out the pilot we learned that the feasibility of a Mud Motor depends on an assessment of additional travel time for the dredger, the effectiveness on salt marsh growth, reduced dredging volumes in a port, and many other practical issues. Our improved understanding on the transport processes in the channel and on the mudflats and salt marsh yields design lessons and guiding principles for future applications of sediment management in salt marsh development that include a Mud Motor approach.

Bij de haven van Harlingen is een innovatieve methode beproefd voor hergebruik van baggerslib om de ontwikkeling van een kwelder te stimuleren: de slibmotor. Bij een slibmotor wordt baggerspecie als een semi-continue bron van sediment zo dicht mogelijk bij een kwelder verspreid om vervolgens door natuurlijke transportprocessen het sediment af te zetten voor en op de kwelder met als doel deze te laten aangroeien. De hypothese is dat door toepassing van een slibmotor de natuurlijke kweldergroei wordt versneld zonder directe verstoring van de kwelder om zodoende de natuurlijke biologische en geomorfologische kenmerken te behouden. Dit rapport beschrijft de resultaten van het monitoringsprogramma waarmee het effect van de slibmotor op de ontwikkeling van slikken en kwelders is gevolgd.

In the process of gradual reorientation of the oil industry to the production of heavy hydrocarbons, inaccessible to traditional methods of production, the need arises for the application of modern technological solutions. One of these technologies is directional drilling, which poses new challenges for drilling equipment, such as facilitating sliding - changing the angle of well bore, improving the cleaning of the wellbore, reducing the risks of differential sticking, overcoming resistance during horizontal drilling, etc. A modern technological solution is rotary steerable systems (RSS) representing a new generation of downhole systems used in directional drilling. The article discusses the advantages and disadvantages of RSS technology, its modifications, gives a classification, also provides a comparative analysis of well wiring using rotary steerable systems and, the most widely used, mud motor.

Drilling is carried out in the very early stage of the well and it is critical for ensuring smooth execution of every aspect of well construction such as faster drilling, better hole cleaning, superior logging, running casing efficiently, maintaining wellbore integrity and achieving economic production. This paper will demonstrate the significance of best drilling practices to achieve good wellbore geometry, which has a profound effect on total well construction and production time and cost and sometimes even determine the success of the well. Poor wellbore geometry, because of improper choice of drilling system i.e. mud motor or rotatory steerable, is generally related to the washed out and/or spiraled wellbore. Washed out hole is recognized by using calipers, however, the hole spiraling is difficult to detect at the early stage of the well. In spiraled holes, it becomes virtually impossible to get a good cementing job done. The poor cementing conditions behind the casing are identified using ultra-sonic images or high amplitudes values of CBL/VDL. These channels behind casing are, a clear threat to production and life cycle of the well. It is widely assumed that the squeeze jobs are an option to improve cement behind casing, however, it does not hold true in case of a spiral borehole. This paper compares the wells, drilled with different drilling system and their impact on the wellbore geometry. It also exhibits the aftermath effects on wellbore construction, well integrity and production.

As the industry continues to drill increasingly complex wells, the demand put on drilling equipment has increased and will continue to increase. Preventive maintenance often falls to the wayside in favor of keeping the same equipment operational for longer until a failure occurs, which can be very costly and potentially catastrophic to the equipment provider. Fatigue tracking makes it possible to predict failures ahead of time and prevent such incidents. However, the most commonly used fatigue tracking methods are based only on rotating hours and do not take the bending stress into account. Electronic drilling recorders (EDR) coupled with bottom hole assembly (BHA) models allow for better estimation of the fatigue performance by calculating the actual bending stress along each piece of equipment, such as the mud motor or measurement while drilling (MWD) tool, leading to a more reliable fatigue tracking method. A case study of fatigue on a common motor and MWD over the drilling life of a well provides valuable information on how to monitor and react to different fatigue scenarios. By using an advanced stiff string model to calculate stress distribution along the motor or MWD coupled with standard fatigue prediction models, valuable information can be learned about the motor and MWD conditions. One case that will be examined involves a typical well trajectory such as those drilled in the US land market today which involve a high dogleg curve to reach a target formation, with dog leg severity (DLS) locally reaching 18 (deg/100') generating high bending stress and thus fatigue. The consequence on fatigue life can be dramatic through the BHA for even just one exceptionally high dogleg. By using the continuous surveys taken by an MWD tool, to account for the actual tortuosity of the well, the potential fatigue becomes even more significant. Another decision that is commonly made without much regard for fatigue consequences is that of stabilizer placement along the BHA which can dramatically shift the distribution of bending moment and thus extend the life of a mud motor. Simulations will show how wellbore tortuosity can affect dramatically the fatigue life of mud motor and MWDs. By illustrating several common examples of fatigue influencers, engineers will be better equipped to determine the impact of different decisions on the potential motor and BHA fatigue. Better understanding of the nature of fatigue and the consequences of larger bend motors, higher doglegs, and better surveying practices, for example, can lead to better decision making and the reduction of fatigue failures.

The challenging environment in the Kvitebjørn field offshore Norway comprises high-temperature wells, long drilling hours, low rate of penetration (ROP), managed pressure drilling (MPD), and mud additive requirements, all of which are very detrimental for operations and reliability of the positive displacement motor (PDM) power section. In fact, until now, no one has successfully drilled the 5 ¾-in. section in a single run due primarily to motor failures such as elastomer chunking and debonding. This paper presents the steps used for optimizing the selection of a PDM section to achieve a single-run drilling operation with improved ROP. The method includes understanding the drilling environment, type of wells, rig capabilities, formations, temperatures, MPD, and drilling fluid requirements. Furthermore, the usual motor and bottomhole assembly requirements must be evaluated and the mud compatibility with the elastomer must be scrutinized. All of these variables were then input into a modeling engineering workflow to simulate and analyze the power output, the elastomer fatigue life, the hysteresis heating, and the debonding stress to select the best possible PDM candidate for the drilling job. A new long-life elastomer and the drilling parameters recommended by the mud motor modeling resulted in drilling this section in a single run for the first time in the field. Simultaneously, it was possible to drill to the deepest total depth without any need to set the section total depth shallower, as occurred in previous wells due to motor failures. The motor drilled through a very thick cemented sandstone stringer with no stall incidents. This motor set new records for drilling the 5 ¾-in. section with a total run length 60% longer than the previous longest run and a total pumping time 67% greater than the previous record. The combined new technologies of the modeling and the new long-life elastomer were applied for the first time in the anticipated challenging drilling conditions. The successful results demonstrated that with thorough analysis and proper planning, one can achieve a step change in performance and reliability without additional costs. The scope of the operation is even broader than the mud motor application.

The deployment of a new positive displacement motor (PDM) technology as a solution to improve drilling performance in deep vertical exploration wells in northern Kuwait. The new technology of the positive displacement motor was developed within the framework of new capabilities in motor optimization modeling, a holistic approach to configuring motor components as an integrated unit, and new engineering advances in the material and design of motor components. The engineering advances and innovations can be distinctly categorized into two major components, the power section and the lower end. The power section components went under extensive empirical and experience-based failure analysis to refine the design of the subcomponents. The refined designs were then scrutinized with the industry-first motor optimization modeling that simulates both the performance and fatigue of the power section by analyzing eight influential variables of down-hole conditions, and components material and geometry. The second component, is the newly designed high torque lower end which houses an overhauled assembly of transmission and bearing sections. The new lower end was engineered to reliably handle and fully harness the full capabilities of the power section. The result, is an integrated new motor technology that is characterized by its superior resistance to stall, ability to sustain higher limits of differential pressure, and performance reliability in harsh drilling environment. Kuwait Oil Company (KOC), with its ever-expanding exploratory drilling campaign in northern Kuwait, was looking for significant improvements in drilling performance of vertical deep-drilling exploration wells. As such, KOC agreed to test the new motor technology in an exploration field north of Kuwait. The deployment of the new technology would take place in the 16 in section of a vertical well with a starting planned depth of 10,565 ft (3,220 m) and a total depth of 14,605 ft (4,456 m). The section drills through highly-interbedded and abrasive sandstone and carbonates strata with highly-variable windows of pore pressure and rock compressive strength. Given the complex lithology and the high-pressure environment, previous drilling campaign were tainted by low penetration rates, and motors and bits failures. In March of 2017, the new motor technology was field tested for the first time worldwide in northern Kuwait. The field test run covered an interval of 3,658 ft (1,115 m) over three runs. The new motor technology justified its higher specifications by improving the rate of penetration (ROP) by 62% compared with the fastest offset well drilled. The superior rate of penetration can be attributed to the new motor ability to deliver higher ranges of differential pressure, specifically 57% higher than offset wells. The deployment of the new motor technology successfully proved the capabilities of the new motor in drilling optimization and reliability, and also validated the engineering and modeling processes behind the new components.

Aluminum drill pipe has already been proven as a viable alternative to steel drill pipe when drilling long horizontal wells thanks to its lighter weight that does not compromise resistance to yield and buckling. At the same time, the development of unconventional wells has seen the deployment of numerous technologies to further improve the performance and increase the lateral section to reduce costs. An operator has recently and successfully tested a new aluminum drill pipe with an axial oscillation tool to push further the limits of the drilling system. This paper presents the key findings of the case study using a mixed aluminum-steel string combined with an axial oscillation tool. First, the innovative drill pipe design is presented, followed by lessons learned during rig operations regarding pipe handling practices, rig compatibility and pipe inspection. Then, results of the drilling simulations performed during the well planning phase are presented. This modeling led to an optimum drill string design associating the steerable mud motor assembly, aluminum drill pipe, axial oscillation tool and steel drill pipe. The number and placement of aluminum drill pipe along the string was key to reducing friction and improving weight transfer between the bit and the axial oscillation tool. Through extensive modeling and field data interpretation, this paper presents the comparison of the overall drilling performance between steel only and aluminum-steel drill pipe strings, and provides metrics in terms of weight transfer and rate of penetration improvement. This innovative and promising drill string design opens the doors to set new limits in terms of horizontal departure.

One of the most important factors when designing an aerated-fluid drilling operation is the volume of injected gas and liquid necessary for the downhole mud motor to achieve managed pressure drilling (MPD) conditions. This paper discusses a new method for calculating the equivalent liquid rate (ELR) of the gas/liquid mixture. ELR can be equally treated as the liquid volume to measure mud motor performance and can also be used to refine the permissible MPD operational window. During aerated-fluid drilling, gas/liquid are mixed to form one complex flow regime along the wellbore. To model its flow rheology and mechanisms, both foam and multiphase flow models are used. ELR is calculated by using the surface gas injection rate (GIR)/liquid injection rate (LIR), drillstring configuration, wellbore trajectory, and wellbore geothermal allocation. This calculation also considers tool joint effects and formation influx from downhole and parasite string injection. This paper also describes the impact of ELR to form the MPD operational window by considering GIR/LIR, minimum/maximum ELR, bottomhole pressure (BHP), and annulus flow velocity. Sensitivity analysis is performed for various combinations of GIRs/LIRs. Similar ELR value trending is observed in foam and multiphase flow models for both vertical and deviated wells. Increasing ELR is not always the goal because BHP should be controlled within reasonable ranges during MPD. To ensure operational constraints at the bottom hole, a set of ELRs is calculated from a few combinations of surface GIRs/LIRs. Refined by the target BHP and the desirable hole cleaning capability, the permissible managed drilling operation window can be achieved and visualized. Drilling engineers can calibrate surface GIRs/LIRs to achieve maximum mud motor performance. Conversely, with the fixed GIRs/LIRs, to maintain the desirable BHP and hole cleaning, drilling engineers can select the proper mud motors for use. The calculated ELR in this method is not only variable for evaluating mud motor performance, but it is also novel to combine it with other important operational factors to help manage downhole pressure and meet hole cleaning requirements.

The drilling speed has a lot to do with whether the selected bit type and formation type is matched. Choosing a reasonable drill bit type can achieve the goal of high speed and low cost drilling by improving drilling rate and reducing the occurrence of down hole trouble. On the basis of performance analysis of PDC bits, the linear relationship between rate of penetration and drilling footage is obtained. By means of the optimization of motor and parameters, the drilling parameters, such as weight on bit, torque, type of mud motor and operating temperature, are optimized by application in desert oilfield. It provides an effective reference for the rapid development of the same type of oilfield

The paper describes the experimental research of hydrocarbon drilling mud impact on engineering parameters of mud motor elastomer samples. It is believed to be urgent due to an increase in using mud motors in oil and gas well construction now, and the issue of intense exploitation is currently topical. The test results of elastomer IRP- 1226 dependent on the temperature are shown in the paper. It is proved that the hydrocarbon drilling muds have a significant impact on wearing of mud motors elastomers under the condition of a temperature increase.

Technology Update Oil and gas well construction requires the installation of tubulars at a specific depth, prescribed for reasons of mechanics, formation pressure and wellbore integrity, or accessing reserves. Deepwater construction has an additional need to land all strings in the subsea wellhead with precision. The industry recognizes this as a most significant operation. There have many instances of failed well programs where critical depths have not been secured. A step change technology for this purpose has been created to reduce well construction risk, applicable to all casing strings, liners, and completion strings. Introduction: Solving an Important Industry Problem Adverse wellbore conditions, instability, irregularity, doglegs, and fill, among other factors, often result in inefficient, incomplete casing running operations in terms of nonproductive time and potentially lost production. If the rig is equipped to do so, it may be possible to overcome such problems by reaming. However, as casing strings get longer and heavier, and for rigs without a top drive or where other factors lead to a limited ability to rotate the casing, there has been little option but to accept that casing placement problems are just a “cost of doing business.” The industry problem is clear, but there do not appear to be key performance indicators on the percentage of casings run to 100% of target depth. Well construction creates well integrity, ensured in part by following the plan, landing casing on depth, and obtaining a well cemented tubular. Cost of failure to run the casing to design depth can reflect many factors, including the costs of drilling unused hole; running, pulling, and rerunning casing; and any subsequent casing plan revision. There is also the potential cost to reputation for failing to deliver to plan. In developing a new technology to address the problem, it is of primary importance to add no risk to the existing well control or casing running process. Ideally, for reasons of safety, operation of new equipment should not require additional personnel.

Severe vibrations in drillstrings and bottomhole assemblies can be caused by cutting forces at the bit or mass imbalances in downhole tools. One of the largest imbalances is related to the working principle of the so-called mud motor, which is an assembly of a rotor that is maintained by the stator. One of the design-related problems is how to minimize vibrations excited by the mud motor. Simulation tools using specialized finite element methods (FEM) are established to model the mechanical behavior of the structure. Although finite element models are useful for estimating rotor dynamic behavior and dynamic stresses of entire drilling systems they do not give direct insight how parameters affect amplitudes and stresses. Analytical models show the direct influence of parameters and give qualitative solutions of design related decisions. However these models do not provide quantitative numbers for complicated geometries. An analytical beam model of the mud motor is derived to calculate the vibrational amplitudes and capture basic dynamic effects. The model shows the direct influence of parameters of the mud motor related to the geometry, material properties and fluid properties. The analytical model is compared to the corresponding finite element model. Vibrational amplitudes are discussed for different modes and parameter changes. Finite element models of the entire drilling system are used to verify the findings from the analytical model using practical applications. The results are compared to time domain and statistical data from laboratory and field measurements.

The Cardium Formation is a conventional sandstone reservoir in the Western Canadian Sedimentary Basin. The Cardium Formation is currently at a phase of exploitation requiring long horizontal penetrations and large-scale, multi-stage, fracture stimulation to ensure productivity. In the Canadian Foothills, the Cardium is complexly deformed and naturally fractured. Correctly placed horizontal wellbores take advantage of these natural fracture systems which create permeability pathways resulting in extremely prolific wells. To maximize production and effective reservoir drainage, horizontal wellbores need to be drilled to intersect multiple natural fracture networks within the deformed Cardium reservoir. Sub-seismic scale folds and faults result in rapid changes in reservoir bedding orientation and/or position which requires sensitive geosteering responsiveness in order to create an optimal reservoir penetration. The Cardium reservoir exhibits good gamma contrast and predictable character. Therefore, gamma ray has been shown to be an effective tool for geosteering. An innovative instrumented mud motor that provides azimuthal gamma ray and continuous inclination 2.7m from the bit was used for successfully geosteering several wells, and has proven to be a vital component in the horizontal drilling process. For example, a common geological scenario can result in a 5° change in apparent bedding orientation relative to the wellbore resulting in the wellbore exiting the reservoir. Reservoir re-entry can occur as quickly as 30.5m when using the instrumented mud motor compared to 56.4m when using a conventional gamma sensor positioned 15.2m behind the bit. The instrumented mud motor works by wirelessly transmitting the azimuthal gamma ray and continuous inclination measurements via short hop communication to the MWD (Measurement While Drilling) system from where it is transmitted to the surface realtime. This paper describes the complex Cardium reservoir in the Canadian Foothills and presents the unique challenges faced when attempting to geosteer and optimize wellbore positioning within the reservoir. We review the near bit instrumented mud motor and discuss the workflow of how data was used from the instrumented mud motor to help with geosteering the well. Finally, we compare the results from several wells drilled using the instrumented mud motor to those drilled using a standard MWD gamma located 15.2m behind the motor. The use of the instrumented mud motor with near bit azimuthal gamma ray and continuous inclination proved to be a successful geosteering tool in one of the most complex environments of the Western Canadian Sedimentary Basin. Additional footage in zone and increased production in this complex geological environment displays the tool's capibilities and the benefits it could provide to other areas of the basin.

The paper describes the experimental research of drilling mud influence on engineering parameters of mud motor mechanical rubber components. It is believed to be urgent due to increase in using mud motors in oil and gas well construction now, and, consequently, the issue of increasing their exploitation is becoming current. The development test results of elastomer IRP-1226 dependent on the mud type (alkaline, hydrocarbon or salt- saturated ones) and the temperature are shown in the paper. It is proved that the type of drilling mud and the temperature in bottom-hole zone have an influence on wear of mud motors elastomers.

Interest in European Coal Bed Methane (CBM), driven by an increasing demand for supplies of natural gas in Europe has been ongoing since the 1990's in the UK, Belgium, Germany, France and Poland. The nature of Carboniferous age European coals: multiple, thinner coal seams with lower permeability than coals seen in Australia or North America has resulted in a horizontal well or multi lateral wellbore architecture employing geosteering through the coal seams. Use of a conventional directional drilling Bottom Hole Assembly (BHA) in which the Logging While Drilling (LWD) sensors are usually 40ft or more from the drill bit, makes geosteering in structurally complex coals, with changing dip and rolling topography a major challenge. The cost sensitive nature of CBM wells makes the use of geosteering tools such as azimuthal resistivity tools uneconomic. This paper describes the experience of Dart Energy and its heritage company, Composite Energy, in introducing an instrumented mud motor with a near bit Azimuthal Gamma Ray and Inclination tool as a cost effective geosteering aid on the Airth CBM Field in Central Scotland. The use of an instrumented mud motor enabled Dart Energy to improve geosteering performance, increasing net coal in each geosteered section, near doubling of average Rate Of Penetration (ROP), and reducing the number of time consuming and costly sidetracks. The improvement in geosteering is a critical part of realising the commerciality of CBM wells producing from thinner, structurally complex Carboniferous age coals found in the UK and Northern Europe.

This paper analyzes the dynamics of a horizontal drill-string. In this dynamics, the frictional forces between the column and the borehole are relevant and uncertain. A stochastic model is proposed for the frictional coefficient: a random field with exponential autocorrelation function. In the numerical analysis, the drill-string is modeled using the bar model (tension/compression), and is discretized by means of the finite element method. An oscillatory force (due to mud motor) is imposed on the system and there is a bit–rock interaction as the column moves forward. We propose a new way to measure the efficiency of the process: an output/input power ratio. The resultant random ratio is analyzed, and it turns out that it presents a bimodal characteristic, an unexpected result. Fil: Ritto, T. G.. Universidade Federal Do Rio de Janeiro; Brasil Fil: Escalante, M. R.. Universidad Tecnologica Nacional. Facultad Regional Concepcion del Uruguay; Argentina. Universidad Tecnologica Nacional. Facultad Regional de Concordia; Argentina Fil: Sampaio, Rubens . Pontificia Universidad Catolica Do Rio de Janeiro; Brasil Fil: Rosales, Marta Beatriz. Universidad Nacional del Sur. Departamento de Ingeniería; Argentina. Consejo Nacional de Investigaciones Científicas y Técnicas; Argentina

Application of Rotary Steerable System(RSS) drilling in Mumbai High Field was driven by the increasing difficulties associated with directional drilling with mud motor technology, especially in Extended Reach wells. ONGC has focused largely on finding economic and competitive ways of exploiting the mature fields already developed, and the rotary steerable system provides the opportunity to drill high horizontal drift wells, reaching further unexploited subsurface targets without adding new platforms, with significant improvement in drilling performance and subsurface objectives. Since first deployment in 2004, RSS has successfully overcome the drilling challenges & problems, especially in the 121⁄4”section, deliver improvement in drilling time, The paper will discuss in detail, each step of continuous improvement process during the last five years, which include RSS applications & operations, field specific bit design and optimization, shock & vibration mitigation, drillstring and fluid system modifications. The actual result on overall directional drilling efficiency enhancement after implementation of each optimization methodology also discussed. The paper will also discuss some unique RSS applications in Mumbai High Field such as application of RSS in drilling top hole 17-1/2” section successfully 4 times faster than mud motor, drilling 8-1/2” multilateral section including open hole sidetrack, drilling 6”with RSS & pro-active geo-steering technologies keeping the well in good reservoir with high penetration rate and drilling the longest horizontal drift (4071 m) well in Mumbai High Field with application of RSS in all drilling phases from 17-1/2” to 6” hole section. Based on the field results and performance analysis it is concluded that RSS proves to be more effective technology in drilling high drift wells when combined with optimized mud system and bit. Introduction Mumbai High Field has been developed since discovered in 1974 by ONGC with a number of wellhead platforms consisting of directional wells. The field is a multilayered reservoir and the objective of directional wells is to achieve certain drift at given TVD and to penetrate the reservoir inclined to produce hydrocarbon from all layers. In order to sustain the production to desired levels without increasing the number of slots & platforms, drilling “Infill ERD Well” was the best option. In 1995, ONGC started the ERD Well Campaign for 15 wells in Mumbai High with the Motor as the Directional drilling Tool, the only available technique then. Unfortunately, the result of the drilling campaign was not as per expectation. These wells could not be drilled to longer departures of 2 km from platform to L-III reservoir level without any complication such as formation collapse and stuck pipes. Even casing could not reach bottom due to the swelling in shales which were exposed for a prolonged duration. It was observed that the most critical part in ERD Well is 12 1⁄4” phase section. Overview of RSS System RSS was first introduced in the late 1990s, the technology continues to evolve. The impact of the technology to the drilling process has been recognized within the industry.The Push-the-Bit RSS PowerDrive which used is contained in a short nearbit assembly. A schematic of the tool is shown in fig 1. Petrotech-2010 31 October-3 November 2010, New Delhi, India 2 There are two principal components: · The bias unit applies a lateral force to the bit while it constantly rotates at bit speed. · The control unit is a roll-stabilized platform located within a nonmagnetic collar. It contains selfpowered electronics and sensors that set the direction and magnitude of the force vector applied to the bit by the bias unit. The bias unit is connected directly to the drill bit. Three exterior pads are kept in constant contact with the formation by internal, mud-powered actuators. A three way disc valve controls the flow of mud to the actuators. When deviation is required, each actuator is extended in sequence, once each revolution of the bit, against the side of the hole opposite the intended bias direction. Fig 1 illustrates the steering principal. The pads are in constant contact with the wellbore, extending and retracting in a smooth, continuous action. When no deviation is required, the RSS system is put in neutral mode by simply rotating the disc valve stator relative to the high side. This causes the pads to push in every direction and effectively cancel each other. The control unit is mechanically linked to the bias unit and sets direction and deviation. It contains sensors and control electronics inside a cylindrical pressure case, which is mounted on bearings within the drill collar. The bearings allow the control unit to rotate or remain stationary, independent of drillstring rotation. Power is generated through two turbine impellers that support the control unit's sensors and electronics. Drilling with RSS system in Mumbai High Rotary Steerable System (RSS) was introduced in 2003 to overcome the challenges drilling ERD wells in Mumbai High Field, especially in 12-1/4” section. Since the beginning of its deployment, the technology had brought noticeable improvement on drilling time reduction and eliminating of drilling complications. Average completion days for an ERD well with Motor are 111 days and with RSS it improves to 45 days in 2006. The use of RSS tool in ONGC Mumbai High filed has been focused on improving the penetration rates in order to improve project economics. It has also aided drilling in projects characterized with directional drilling difficulties, such as inability to slide or slide with low penetration rate. In some cases, well was redesigned to features long open hole intervals allowing the use of RSS, thus eliminating the need for extra casing string and reducing the overall well cost, wells which were believed to be unachievable using conventional bottom hole assemblies are now being commonly drilled in Mumbai high offshore. In 2004 ,3 wells were drilled by RSS with an average ROP of 15 m/hrs and average section length of 1200 m with KCL-Glycol mud system, bit used was RSX 192 HDF, the whole drilling campaign was successful, with many lesson learnt. Petrotech-2010 31 October-3 November 2010, New Delhi, India 3 In the year 2005-2006,19 wells were drilled with an average ROP of 22 m/hrs and average section length of 1500 m using KCL-Glycol mud system as well as SOBM. With the conventional drill string we can only pump 800 GPM and also the pump pressure was the limiting factor, due to this low discharge the cutting could not be lifted to the active circulation zone. All the lesson learnt from 2004 to 2006 campaign were incorporated, the biggest advantage seen was when the wells were drilled with SOBM, torque & drag was lesser & make the BHA drilled more efficiently. Continuous Drilling Improvement through Design Changes In the year 20072009 the real innovations came and improved the drilling performance with RSS further. 1. Bit Selection & Optimization One of the important factor of the drilling optimization on this project was to select the best performance bit which is suitable for specific field and RSS system. Detailed bit performance study was performed in order to optimize bit design for specific field to give the best performance (ROP, durability, stability, and steerability). Formation Analysis based on offset logs performed to defined compressive strength of different fields. Continuous improvement cycle followed by tracked bit performance for each individual run, evaluated periodically and further modification discussed and implemented. This exercise was still continuously followed to ensure all latest technology, features and improvements on the bit are being used to beat the performance and to keep raising the benchmark. 2. BHA and drillstring design BHA performance was studied from the offset wells and BHA design was optimized for specific Mumbai High Field application. One of the limitations identified was limitation on pump pressure vs expected flowrate and torque. To mitigate this, 6 5/8” Drill pipe / HWDP and 5 1/2 “Drill Pipe was used in place of conventional drill collars and 5” drill pipes. With this, the rig capable to deliver 1000 gpm for 12-1/4” & 17-1/2” section and rotating the string at 150 – 180 RPM for optimum hole cleaning. Extensive Torque & Drag studies were performed during well design, in order to define expected drilling torque versus drillpipe & topdrive capacity . If the torque reaching the limit, strategy to reduce the friction by lubricant or SOBM were used. Drillstring configuration also review including eliminating all the drill collar with HWDP for less contact area. Figure 2 BHA examples 12.25” BHA 8.50” BHA 17.50” BHA Petrotech-2010 31 October-3 November 2010, New Delhi, India 4 3. Real time Measurement & Monitoring To optimize the drilling ROP without overloading the annulus with cuttings and increasing the risk of stuck pipe due to poor hole cleaning, real time ECD and torque & Drag monitoring were applied. This measurement also used to determine the requirement of wiper trip or extra circulation to clean the hole. The other real time monitoring performed was shock & vibration. Mitigating & minimizing shock & vibration help to reduces chances of bit/downhole tool/drillstring failures due to harsh drilling conditions. The drilling ROP also improved by minimizing energy loss due to shock & vibration.

For almost two decades, coiled tubing drilling (CTD) has proved to be a successful method to reach the un-swept portions of Alaska’s North Slope reservoirs. This method of drilling has evolved over the years with new technologies and efforts from contractors and operators striving to improve performance from lessons learned. Despite these improvements in equipment and processes, operators and contractors must still deal with certain inherent deficiencies of this drilling method when compared to conventional rotary drilling – suboptimal weight transfer, sometimes troublesome hole cleaning — due mainly to lack of string rotation and low flow rate range, etc. These shortcomings have the potential to induce other drilling performance problems that affect the smoothness of coiled tubing drilling operations. Severe lateral vibration and severe stalling have become acceptable evils over the years, resulting in undesirable trips for failure and unacceptable non- productive time (NPT), both undermining one of the key benefits of coiled tubing drilling – rapid pace operations compared to rotary drilling. This paper introduces a new lower-speed downhole positive displacement motor (PDM). The technology is equipped with high-performance elastomer and was engineered to improve drilling and drill-bit performance in CTD applications. Recent field deployments in Alaska’s North Slope CTD operations proved this design by eliminating earlier performance problems for improved CTD project economics. For example, the technology’s ability to allow for about 10gal/min higher flow rates (compared to other motor designs) significantly improves hole cleaning; a key aspect in CTD operations. Up to today, this downhole mud motor design has been utilized on 13 wells, accumulating 1,303 circulating hours, 577 drilling hours and over 20,700 ft drilled. Performance improvements in depth of cut, reduced lateral vibration, reduced amount of stalls, and other benefits were achieved. There was no trip for PDM failure in all of the 34 runs, traversing different formation zones. The corresponding paper will provide additional information on application benefits by investigating two recent field deployments.

Obtaining deep ice cores from glaciers and the world's ice caps and rock samples from beneath the ice requires a new approach in coring technology that permits quick access to sampling zones. A combination of mechanical drilling coupled with water as a drilling and hydraulic fluid shows promise in providing quick access to interesting sample areas, as well as the ability to obtain good quality rock or ice core samples. The system consists of a deep well pump to circulate drilling water from within the ice, a triplex pump to provide hydraulic power, heaters, specially designed instrumented hoses, and a down-hole mud motor to drive the drill. The system is described in detail and thermal models of its effect on cores presented.

Trenchless Technology has become more sophisticated and widely used in many fields in recent years. But there are still some construction problems in different geological conditions especially in rock. Due to the complexity and particularity of rock, the trenchless construction technology applied to it is completely different from to soil. As well as there is not very perfect construction technology and methods still, which bring a big risk. Based on existing theoretical research, the characteristics of rock and the construction experience, this paper mainly discussed Drill hole Mud Motor and Roller Cone Bit applied to Trenchless Technology in Rock, the main contents are as follows: first of all, introduced the properties of Rock, and then discussed the working principle and the advantages of Drill hole Mud Motor and Roller Cone Bit which the key point was to make work together smoothly. Afterward to choose the drilling equipment to support them such as Mud Pump, Rig, Drilling Mud and other drilling tools. Finally, according to a project example, general construction problems and solutions were analyzed. For example how to control the construction time of pilot bore and drilling deviation; what we should pay more attention on the process of reaming, cleaning and towing pipe. It will provide some valuable references to the TT of similar nature.

Summary Wells with small liners occasionally require unique methods of drilling, completion, and reworking, especially deep-hole wells and wells with severe doglegs. Innovative drilling procedures were used successfully on two wells with those downhole conditions. On the first well, cement was drilled in a 3½-in. liner with a small mud motor and heavyweight mud. On the second well, a large mud motor was used as a downhole power swivel to drill in a 3½-in. liner. Both jobs were completed at depths of 13, 000 to 20, 000 ft with mud weights > 18 lbm/gal and bottomhole temperatures (BHT's) >300°F.

The overall objective of this effort is to develop, build and test a high-speed drilling motor that can meet the performance guidelines of the announcement, namely: 'The motors are expected to rotate at a minimum of 10,000 rpm, have an OD no larger than 7 inches and work downhole continuously for at least 100 hours. The motor must have common oilfield thread connections capable of making up to a drill bit and bottomhole assembly. The motor must be capable of transmitting drilling fluid through the motor'. To these goals, APS would add that the motor must be economically viable, in terms of both its manufacturing and maintenance costs, and be applicable to as broad a range of markets as possible. APS has taken the approach of using a system using planetary gears to increase the speed of a conventional mud motor to 10,000 rpm. The mud flow is directed around the outside of the gear train, and a unique flow diversion system has been employed. A prototype of the motor was built and tested in APS's high-pressure flow loop. The motor operated per the model up to {approx}4200 rpm. At that point a bearing seized and the performance was severely more » degraded. The motor is being rebuilt and will be retested outside of this program. « less

New tools for Formation Testing While Drilling (FTWD) were introduced to the market less than two years ago. They are used in an increasing number of wells in a wide range of operating environments. The tools are capable of performing accurate tests in the dynamic drilling environment of rotary and rotary steerable drilling. They measure formation pressure and some provide formation mobility estimations in real-time. The application expands formation testing into extended reach drilling where pipe conveyed wireline testing is of high risk. It also allows formation pressure testing in boreholes where drilling risk or hole stability exclude conventional data acquisition. During FTWD operations circulation is maintained at all times to insure wellbore integrity. This presents a challenging dynamic environment for accurate formation pressure measurements. In this paper, the application of an FTWD tool in conjunction with a mud motor is described within an even more challenging environment, due to motor rotation and associated drillstring vibrations, as no circulation bypass valve was used. The Baker Hughes INTEQ TesTrak tool was capable of performing accurate formation pressure and mobility measurements with an overall success rate of over 80% in an extreme pressure and vibration environment. Pressure and mobility test results will be shown and compared to conventional wireline logging results from nearby wells. Mobility data, which are calculated downhole and transmitted to surface in real-time, are compared to previous well test data from neighboring wells. The FTWD mobility data showed a good match with reservoir simulation and core data, and even better agreement than the data derived from conventional wireline measurements. In this application the FTWD tool was run in combination with a triple combo LWD suite. This allowed real-time reservoir evaluation as well as optimizing pressure point selection during on-site formation evaluation. No additional wireline logs needed to be run afterwards and the hole could be cased immediately.

Owing to the economic, well control and drilling efficiency problems it propagates, preventing or curing lost circulation has evolved into a critical issue for the industry. Accordingly, a less expensive drilling fluid system often is selected for a particular interval because it will mitigate the economic ramifications of downhole losses. Conversely, fluid systems are also chosen solely for their capacity to minimize losses downhole. Regardless of the application, special analyses are required to not only determine specific preventative measures for drilling fluid loss, but also for devising an appropriate treatment program to cure losses should they occur. Recently, specialized and chemically activated cross-linked pills (CACP) designed to stop whole mud loss have been developed and have shown significant advantages over conventional loss circulation methods. This paper describes the development and application of the specialized cross-linked pills for controlling downhole mud loss. The authors will detail the laboratory methods used to formulated appropriate formulations, the placement procedures, and the successful field applications of this latest generation lost circulation control mechanism. As detailed in the paper, formulations of the new cross-linked pills normally are tailored to specific downhole conditions of temperature and pressure to create a barrier between the loss zone and the wellbore. Further, they have been specially formulated to enable pumping through narrow drill pipe, coil, or mud motor dimensions and to "set" in a specific time frame. Chemical activators or retarders to control setting times achieve this. These pills also contain controlled concentrations of particulate sealing agents that can be used selectively to either to bridge the loss zone at the formation face or allow deeper penetration into the fracture.

The measurement of mud motor rotation rates, and the transmission of these measurements to surface while drilling, is important for drilling optimization. In general, mud motor rotation rates are estimated from the manufacturers performance data. However, flow rates, torque, weight-on-bit and differential pressure will all vary while drilling as will the efficiency of the motor, affecting the actual rotation rate of the motor. While torque, weight and pressure can all be measured by MWD tools, the direct measurement of motor speed has proven difficult. In general it has been necessary to instrument and hardwire a motor to the MWD system in order to extract a measurement of motor speed. Such modifications result in dedicated and specialized MWD hardware. This paper describes a means of measuring the rotation rate of a mud motor using a device that is independent of the mud motor. In essence, the dynamic signal created by the rotor is detected by vibration sensors in an MWD measurement sub in the BHA, and converted directly to motor speed. The MWD measurement sub may be remote from (i.e., not directly connected to) the motor, and therefore this system will work with any motor developed using the Moineau principle. Development and testing of the system in the laboratory and in the field are described in the paper.

A new steerable motor assembly has been designed that provides significant advantages over conventional steerable motor assemblies. The new system, SlickBore™, is comprised of a uniquely designed pin-down mud motor with a specially designed long-gauge PDC bit in a matched drilling system. By treating the bit and motor as a system, it has been possible to overcome the directional limitations previously experienced when long-gauge bits, or short-gauge bits with piggyback stabilization, were used in combination with conventional motors. This paper describes the new system, its key working principles, and the drilling tests and computer modeling used to confirm the initial design concepts. The paper will also highlight selected field results from more than 100 runs made to date. The field results have not only proven the working principles but also demonstrated its advantages over the conventional steerable systems. The benefits include increased ROP, improved hole quality with less hole spiraling and thus less tortuosity, reduced vibration, lower torque and drag, better steerability, better hole cleaning, increased bit life, and improved PDM and MWD reliability.