Advanced real-time health monitoring for mud motor performance

Drilling dynamics measurement of drilling motors and its application in recognition of motor operation states through machine learning

A data-driven bit projection system with motor yield prediction and advisory for directional drilling and well trajectory control

Bayesian Statistical Method for Real-time Tool Yield Calibration of Mud Motor

Well deviation is a prevalent problem in deep oil and gas exploration, leading to a significant increase in drilling costs. The conventional bottom-hole assembly (BHA) anti-deviation design method does not consider the impact of the BHA structure on lateral vibration. This paper proposes an integrated BHA design method that takes into account both anti-deviation and vibration reduction. This method evaluates the BHA’s anti-deviation ability using the drilling trend angle. A negative value of the drilling trend angle indicates that the BHA can correct well deviation. A finite element linearized dynamics method is used to evaluate the lateral vibration intensity of the BHA. This method involves calculating the bending displacement caused by mass imbalance and then determining the magnitude of the bending strain energy based on this displacement. The structural factors affecting the anti-deviation ability and potential lateral vibration intensity of pendulum BHAs and bent-housing mud motor (BHMM) BHAs were studied, and field tests were conducted for verification. The research shows that for pendulum BHAs, the factor that has the greatest impact on anti-deviation ability and vibration intensity is the distance from the stabilizer to the drill bit. For BHMM BHAs, the length of the short drill collar has a significant impact on the vibration intensity. Compared with current design methods, the mechanical specific energy (MSE) of the single stabilizer pendulum BHA decreased by 12%, while the MSE of the BHMM BHA decreased by 26.4%. Both decreases indicate a reduction in vibration intensity. This study will help to further increase drilling speed while preventing well deviation.

Efficient and cost-effective drilling of directional wells necessitates the implementation of best drilling practices and advanced techniques to optimize drilling operations. Failure to adequately consider drilling risks can result in inefficient drilling operations and non-productive time (NPT). Although advanced drilling techniques may be expensive, they offer promising technical solutions for mitigating drilling risks. This paper aims to demonstrate the effectiveness of advanced drilling techniques in mitigating risks and improving drilling operations when compared to conventional drilling techniques. Specifically, the advanced drilling techniques employed in Buzurgan Oil Field, including vertical drilling with mud motor, managed pressure drilling (MPD), rotary steerable system (RSS), and expandable liner hanger (ELH), are investigated and evaluated through case study analyses, comparing their performance to that of conventional drilling techniques. The findings indicate that vertical drilling with mud motor exhibits superior drilling performance and wellbore verticality compared to conventional rotary drilling bottom hole assemblies (BHA) for drilling the 17 ½" hole section. MPD systems employed in the 12 ¼" hole section demonstrate safe drilling operations and higher rates of penetration (ROP) than conventional drilling methods. Rotary steerable systems exhibit reduced tortuosity and achieve higher ROP when compared to mud motor usage in the 8.5" and 6" hole sections. Lastly, investigations of expandable liner hanger cases reveal subpar cement quality in the first case and liner remedial work in the second case, highlighting the successful implementation of ELH techniques in the offset field. Overall, this paper highlights the advantages of utilizing advanced drilling techniques in Buzurgan Oil Field, showcasing their ability to mitigate drilling risks and enhance drilling operations when compared to conventional drilling approaches.

Directional drilling has been used in oil and gas operations since the 1930s when onshore drillers employed the technology to reach offshore reservoirs. Over the years, technologies have been introduced to improve precision and control and at the same time have allowed multiple reservoirs to be produced through a single well, which reduces drilling costs and minimizes the environmental impact of the drilling process. In designing drilling plans, operators have considered economics when deciding whether to employ the traditional process of rotating the drillstring to control well trajectory or use more precise directional drilling techniques, but an either/or approach is not always the best one. The introduction of software that analyzes drilling conditions and determines the most appropriate drilling solution is changing the status quo, streamlining the drilling process and changing the playing field for drillers. The Evolution of Directional Drilling The widespread adoption of horizontal drilling from narrowly spaced slots on a centralized pad location has led to the introduction of complex wellbore geometry intended to maximize field development while minimizing geographical footprint. The growing need for precise execution of complicated well trajectories increased the demand for directional drilling expertise. Using a steerable bottomhole assembly (BHA) comprising a mud motor with a bent housing, an experienced directional driller can orient the bend of the motor in the direction prescribed on the well plan to steer the well on the intended trajectory in a process known as sliding. When the well trajectory is intended to remain relatively straight, the entire drillstring is rotated from surface in a process referred to as rotating. Experience and research have shown, however, that the well trajectory is rarely straight during periods of rotation due to rotational tendencies, a combination of systematic and random influences from BHA design, drilling parameters, and geological formation characteristics that can cause a significant divergence from plan. Rotational tendencies, along with designed well plan deviations, often require sliding to ensure the well follows the planned trajectory. All else being equal, it might seem that sliding should be applied across the board, but there are two reasons that sliding is not the default solution.

Ground drilling technology for drilling has an environment where the major parts are prone to damage due to high stress, torque, and harsh operating conditions that can occur in the rotary power transfer structure. Research for preventing this damage is very important, as it can be coupled with the nature of drilling operations that take a long time in operation, which can lead to enormous cost and time consumption. Previous work investigated the cause of damage by analyzing the working environment and breakage of drilling holes for connecting rods, and a power transfer component of directional mud motors used in ground drilling systems. The material properties by heat treatment conditions for applied materials were analyzed. Based on prior work, we evaluated whether the stress concentration part shown in the analysis results matched the actual damage occurring point by conducting a structural analysis of the connecting rod, a damaged part, using the finite element analysis. We also analyzed how to reduce the stress concentration phenomenon that occurs during the mud motor operation by conducting part shape and design changes between the connecting rod and key parts.

Pareto optimal directional drilling advisory for improved real-time decision making

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199556, “Directional Drilling Automation: Human Factors and Automated Decision Making,” by Bill Chmela, SPE, Sarah Kern, SPE, and Tyler Quarles, Helmerich and Payne, et al. The paper has not been peer reviewed. A joint industry project has created a drilling-systems-automation (DSA) roadmap to help the industry understand and anticipate the direction of drilling systems automation. In the complete paper, the authors suggest that the transition from human action to automation in the general drilling space can occur across four cognitive functions: acquiring information, analyzing and displaying information, deciding action, and implementing action. They also suggest that value exists in partial automation. Directional Drilling: Human to Automated One of the more-important tasks of the directional driller historically has been to decide when to rotate the pipe from the surface in an attempt to drill relatively straight and when to stop rotation, point a bent sub in the desired direction, and determine how long to drill using only the downhole mud motor (sliding) and then implement that decision on the rig. While some directional drillers perform this task at a high level, others often fail to compensate properly for multiple variables including variations in rotary walk and build, motor-yield variations, tortuosity risks, target uncertainty, and deflections. Even expert directional drillers rarely account for reduced hydrocarbon production potential related to drilling accuracy on a survey-by-survey basis. The following individual tasks, detailed in the complete paper, have been automated in a bit-guidance system that operates across the four cognitive functions detailed in the DSA roadmap. - Acquire information - Analyze and display information - Decide action - Implement action

Suspension-type abrasive water jet machining of slot on nitrile butadiene rubber: A preliminary study

Well construction must always be executed safely at reduced operational costs, while ensuring appropriate wellbore quality and placement, per asset team requirements. Consequently, analysis of drilling efficiency, a critical performance indicator, has moved from maximizing rate of penetration (ROP) to improving cycle time. This recognition establishes the need for holistic solutions that address drilling challenges and promote efficient improvement strategies. This endeavor achieves well construction objectives, with associated reductions in cycle time and operations costs. Holistic solutions must start with project analysis and comparisons to offsets to identify application differences and similarities. These evaluations establish project risks, which ultimately have positive or negative effects on well construction. Consequently, implications from these risks (limiters and potential dysfunctions) must be addressed in the planning phase, or preparations must be made for their remediation during project execution. It is not enough to know what worked or failed. Rather, it is essential to understand why and how specific trends, events, results, or relationships come about. Effective and permanent remediations for all drilling dysfunctions must focus on identification and analysis of their initiating risks. Additionally, holistic solutions require detailed analysis of drilling systems, which include bits and reamers, bottomhole assemblies (BHAs), drive systems, hydraulics considerations, and drilling-parameter ranges and roadmaps. In addition to establishing component relevance, this effort must ensure their functional compatibility and effectiveness at addressing project risks. Drilling-parameter roadmaps must focus on well construction objectives and cycle time reduction, not ROP maximization. In this regard, cycle time is defined as the cumulative time associated with the following operations: pick up the BHA, drill out, drill ahead, trip out of hole, and run casing. Bits and BHAs have a major role in this discussion. The industry’s fast-developing capabilities with modeling and deeper under-standing of downhole tools and systems, coupled with applications based on big data analytics, are leading these efforts. The door has been kicked open. Let’s walk through. Recommended additional reading at OnePetro: www.onepetro.org. SPE 205965 - Oil and Gas Drilling Optimization Technologies Applied Successfully to Unconventional Geothermal Well Drilling by Junichi Sugiura, Sanvean Technologies, et al. SPE 205993 - Using Downhole Sampled High-Frequency Torsional Oscillation Measurements for Identifying Stringers and Minimizing Operational Invisible Lost Time by Andreas Hohl, Baker Hughes, et al. SPE 206064 - Mud Motor PDM Dynamics: An Analytical Model by Robello Samuel, Halliburton, et al.

In order to improve the sidetracking efficiency for the recovery of old wells in the middle and later stage of oilfield, an improved 3.5° single-bend positive displacement mud motor (PDM) is designed. This novel single-bend PDM first uses the structure of 3.5° large angle PDM + cushion block, which can meet the sidetracking requirements of high build-up rate and short directional section in large curvature short-radius sidetracking wells and can significantly improve the build-up ability. Furthermore, based on the mechanical analysis and finite element numerical simulation, its parameter optimization is carried out. The optimal main parameters are determined as follows: the structural bending angle is 3.5°, the outer diameter is 95 mm, the height of the cushion block is 14 mm, the distance between the cushion block and the bending point is 120 mm, the minimum curvature radius is 35.50 m, and the weight-on-bit (WOB) should be less than 30kN. The initial section build-up rate of directional sidetracking can be increased up to 52.67°/30 m ~ 53.29°/30 m. The research results have been applied in Tahe oilfield. It proves that 3.5° single-bend PDM can sidetrack successfully at one time and increase deviation, and the overall angle change rate of bottom hole can reach 45.00°/30 m, which can meet the requirements of short-radius sidetracking with curvature radius of 40 m. The successful application of open-hole sidetracking technology with 3.5° single-bend PDM is of great significance to the production increase and efficiency improvement of old oilfields.

A mud motor is a kind of positive displacement motor (PDM) that is used to transform the hydraulic energy of drilling fluids (mud) into mechanical energy. This mechanical energy enables the drill bit to cut the rock and drill a well. It is one of the key parts of downhole assembly that is placed in the drillstring to provide additional power to the bit while drilling as its power downhole output is still unmatched. Mud motor failure is a common and costly issue in drilling operations. A proper prediction of the failure as well as an estimation of the remaining useful life (RUL) are essential for timely downhole mud motor maintenance and drilling optimization.
 Until now, the oil and gas industry has lacked reliable procedures to monitor and maintain the health of mud motors, resulting in unnecessary maintenance costs as well as unpredictable and costly drilling failures. Recently, Schlumberger has addressed this problem with an industry-first prognostics and health management (PHM) solution, which not only estimates the health of the mud motor and tracks RUL, but also creates a new service for clients and provides a competitive advantage. Timely mud motor retirement and maintenance will ultimately reduce failures and NPT.
 The proposed PHM solution is suitable for real-time implementation and combines two different sterling algorithms for reliable prediction of possible problems with the mud motors. It enables the estimation of the mud motor health both on the system level with the entire mud motor (system level PHM model) and on the subcomponent level (power section PHM model) – the most critical component of the mud motor.
 The system-level algorithm model leverages both surface and downhole drilling data as well as mud motor characteristic curves to compute the severity of mud motor degradation. A special mud motor degradation indicator is defined. The indicator is calculated to evaluate the degree of power section decay at each time recorded from thousands of field jobs. The trends of the degradation with respect to drilling time and drilling distance are extracted for each motor job. Based on the study of large datasets, good correlation was observed between the mud motor degradation indicator and mud motor failures.
 The power section PHM model uses downhole measurements to estimate the RUL of the elastomer – the life-limiting component inside the power section. It is 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. Machine learning methods were applied to derive a reduced order surrogate model (ROM) of power sections from the original physics-based models for real-time applications. This ROM outputs the estimation of performance and fatigue characteristics of the considered power section depending on the considered drilling conditions such as differential pressure, downhole temperature, flow rate, and mud compatibility. As the result, the model analyzes accumulative risk of fatigue failure and produces real-time health information for the power section as a percentage of the remaining lifespan.
 The new solution for mud motor PHM was successfully verified and tested in the field. Comparison of the predicted mud motor fatigue life with the actual observed postjob conditions and job failures demonstrated good results of the developed models. The PHM enables optimization of mud motor selection, drilling configuration, and maintenance operations by minimizing RUL uncertainties while facilitating rerun decisions and avoiding overmaintenance and premature retirements. The whole solution is currently being integrated into a drilling platform including the maintenance system, the well construction planning, and the execution. It maximizes the equipment usage with increased drilling performance without sacrificing reliability and enables optimal fleet management of a drilling process for revenue maximization.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202661, “Combination of Radial Drilling Technology With Acid Jetting: New Approach in Carbonate Reservoir Stimulation,” by Ayrat Bashirov, Ilya Lyagov, and Ilya Galas, Perfobur, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The complete paper describes an approach to stimulate carbonate formations with bedding water or a gas cap. The technique is a combination of acid jetting and a radial drilling technology that uses mechanical radial drilling with a slim mud motor. The primary advantages of the technology include controlled trajectory and the possibility of re-entry into channels. The novelty of the technology is in its ability to deploy acids in the rock far away from the wellbore through the mechanically drilled holes with known depths and azimuths. Reservoir Description The mature field is in central Russia in the Republic of Bashkortostan. The field contains both sandstone and carbonate reservoirs. Oil depth is from 780 to 1830 m. Six reservoirs are in development. This study concentrates on projects in a carbonate formation that is a substage of the early Pennsylvanian Period. This formation is highly heterogeneous with closely underlying water. Permeability of the reservoir is approximately 43 md; reservoir pressure is 1,000 psi, and oil density is 0.891 g/cm3. Two adjacent well candidates with identical reservoir properties were selected for the study, with a distance between wells of approximately 136 m. Net oil thickness in Well A is 4.4 m and 3 m in Well B. Mechanical Radial Drilling Technology The technology described by the authors uses mechanical radial drilling with a slim mud motor. The technology allows the drilling of a network of radial channels up to 15 m long with up to four channels of different trajectories on one level. The technical system features a modular construction for ease of assembly at the wellhead area and increased operational efficiency. The main elements of the technical system include the following: - Pipe pusher connected at the top with an overflow valve module and, at the bottom, with a guiding device connected by means of a hydraulic pusher - Flexible pipe assembly with a small (nonstandard) sectional mud motor - Drilling bit (milling cutter for window cutting) - Special whipstock and an anchor module with an orienting funnel connected from below to the pipe frame

SummaryNorth American shale drilling is a fast-paced environment where downhole drilling equipment is pushed to the limits for the 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 subassembly (top-sub) provide unique measurements to fully understand the reaction of the steerable-motor power section under load relative to the type of rock being drilled. Three-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, weight on bit, and drillpipe size. The torsional energy stored and released in the drillstring can be high because of the interaction between surface rotation speed/torque output and mud motor downhole rotation speed/torque. Torsional drillstring energy wind-up and release results in variable power output at the bit, inconsistent rate of penetration, rapid fatigue on downhole equipment, and motor or drillstring backoffs and twistoffs.A new mechanism of motor back-drive dynamics caused by the use of an MWD pulser above a steerable motor has been 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 polycrystalline diamond compact (PDC) drill bit during severe stick-slip and back-drive events (−50 rev/min above the motor), confirming that the bit rotated backward for 9 milliseconds (ms) every 133.3 ms (at 7.5 Hz), using a 1,000-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 was discovered that the back-drive dynamics are worse at the drillstring, approximately 1,110 ft behind the bit, than these measured at the motor top-sub position. These dynamics caused drillstring backoffs and twistoffs 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.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29875, “Combined Data Analytics and Physics-Based Simulation for Optimal Bit, Motor, and Bottomhole Assembly Combination,” by Samba Ba, SPE, Dmitry Belov, SPE, and Daniel Nobre, SPE, Schlumberger, et al., prepared for the 2019 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Today, drill bits and mud motor issues can account for more than half of the reasons for pulling out of hole before total depth (TD) on directional drilling wells. The complete paper presents a methodology designed for optimally matching drill bits, mud motors, and bottomhole-assembly (BHA) components for reduced failure risks and improved drilling performance. Work Flow The overall work flow includes detailed modeling of each sophisticated component and an algorithm to combine them efficiently at the system level without losing their specific nature. Drilling-Bit Simulation. The drill-bit model is created in 4D - 3D space modeling plus the transient behavior with time. In 4D finite-element modeling, both polycrystalline-diamond-compact (PDC) and reverse-circulation bits can be modeled. The detailed cutting structure model may include specifying the number of cutters and how to place them in a 3D cutter space. The bit cutter and rock interaction must be modeled correctly to simulate the real scenario. This interaction is characterized by laboratory testing for almost all types of rocks interacting with the cutters. Motor Simulation. The mud motor consists of multiple subassemblies. The power section assembly is where the transformation of hydraulic power into mechanical power occurs; this consists of a rotor/stator pair. The rotor is the moving part and the stationary stator is a metal tube with rubber bonded inside. The authors developed a motor- optimization modeling work flow for evaluating the mud motor’s performance and durability for any defined drilling conditions. This model includes performance, fatigue, and hysteresis heating simulation capabilities. Within the framework of the developed work flow, the authors use three types of simulation (mechanical, thermal, and fatigue), with mutual correlations between the results. Drillstring Simulation. A proper drill-string simulation is critical for the successful evaluation of drilling performance and equipment reliability. In this study, the drillstring and BHA analysis consists of a comprehensive full-scale finite-element model that also includes a proper transient analysis of the drilling process in a 4D analysis. This finite- element model uses 3D beam elements with six degrees of freedom for each finite-element node. The described complex finite-element model incorporates all components from drill bit to surface. This model considers factors affecting the dynamic performance of the drillstring and can predict the transient response in the time domain. Detailed working mechanisms and geometries of downhole drive tools were implemented in the model to study the dynamic characteristics and directional performance of these tools.

Introduction. Directional drilling of wells is currently carried out by a rotary steerable system and conventional equipment including a mud motor with an adjustable skew angle. Either of the two methods has particular advantages. Research aim is to analyze the technologies provided by various service companies in the field of directional and horizontal wells drilling in order to provide means of improving the utilization capacity of the conventional bottom hole assembly in long horizontal boreholes. Methodology. When drilling directional wells with a small departure from the vertical and wells with horizontal boreholes up to 500 m long, a preference is given to a mud motor as far as a change in deviation parameters is concerned. This is due to the fact that the mud motor has a significant economic advantage. However, when drilling directional well with complex planned profile or a well with a horizontal borehole of more than 500 m, the mud motor may cause a variety of problems, while a rotary steerable system will allow to avoid some of them. Results. The rotary steerable system is not always economically feasible suggesting a need for an alternative technology with a more advantageous offer on the market of services. A system of pulsed controlled drilling will allow the adjustment of the trajectory of the wellbore when drilling in a rotary mode with conventional equipment for directional drilling, reduce rig time, and improve the borehole quality. Summary. The given technology will make it possible to improve the efficiency of conventional equipment which includes the mud motor for directional wells drilling with complex planned profile and long horizontal boreholes of more than 500 m, as soon as the technology provides the possibility of adjusting the trajectory in a rotary mode. The system of pulsed controlled drilling is developed as an alternative to the rotary steerable system making it possible to significantly reduce construction expenses for wells with complex geological conditions of drilling

Summary The use of drilling automation is accelerating, mostly in the area of rate of penetration (ROP) enhancement. Autonomous directional drilling is now a high focus area for automating drilling operations. The potential impact is immense because 93% of the active rigs in the US are drilling directional or horizontal wells. The 2018–2019 Drilling Systems Automation Technical Section (DSATS)-led international Drillbotics® Student Competition includes automated directional drilling. In this paper, we discuss the detailed design of the winning team. We present the surface equipment, downhole tools, data and control systems, and lessons learned. SPE DSATS organizes the annual Drillbotics competition for university teams to design and develop laboratory-scale drilling rigs. The competition requires each team to create unique downhole sensors to allow automated navigation to drill a directional hole. Student teams have developed new rig configurations to enable several steering methods that include a rotary steering system and small-scale downhole motors with a bent-sub. The most significant challenge was creating a functional downhole motor to fit within a 1.25-in. (3.18 cm) diameter wellbore. Besides technical issues, teams must demonstrate what they have learned about bit-rock interaction and the physics of steering. In addition, they must deal with budgets and funding, procurement and delivery delays, and overall project management. This required an integrated multidisciplinary approach and a major redesign of the rig components. The University of Oklahoma (OU) team made significant changes to its existing rig to drill directional holes. The design change was introduced to optimize the performance of the bottomhole assembly (BHA) and allow directional drilling. The criteria for selecting the BHA was hole size, BHA dynamics, a favorable condition for downhole sensors, precise control of drilling parameters, rig mobility, safety, time constraints, and economic practicality. The result is an autonomous drilling rig that drills a deviated hole toward a defined target through a 2 × 2 × 1-ft (60.96 × 60.96 × 30.48 cm) sandstone block (i.e., rock sample) without human intervention. The rig currently uses a combination of discrete and dynamic modeling from experimentally determined control parameters and closed-loop feedback for well-trajectory control. The novelty of our winning design is in the use of a small-scale cable-driven downhole motor with a bent-sub and quick-connect-type swivel system. This is intended to replicate the action of a mud motor within the limits of the borehole diameter. In this paper, we present details of the rig components, their specifications, and the problems faced during the design, development, and testing. We demonstrate how a laboratory-scale rig can be used to study drilling dysfunctions and challenges. Building a downhole tool to withstand vibrations, water intrusion, magnetic interference, and electromagnetic noise are common difficulties faced by major equipment manufacturers.

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.