A drilling fluid for drilling deviated wellbores must provide adequate hole cleaning efficiency for all well angles relevant to the operation. For angles near vertical, experience show that hole cleaning is straight forward. In wellbore angles larger than, say, 45 degrees hole cleaning is more difficult. Cuttings beds are formed and at some well angles these beds may avalanche during circulation stops etc. This paper presents results from laboratory tests with injected cuttings using a low viscosity oil based drilling fluid with micronized grained barite as weight material. The fluid is designed for highly deviated wells with low ECD requirements and the cuttings transport performance through relevant wellbore inclinations was investigated. The experiments have been performed under realistic conditions. The flow loop includes a 10 meters long test section with 2” OD freely rotating steel drill string inside a 4” ID wellbore made of steel, representing a cased wellbore. Sand particles were injected while circulating the drilling fluid through the test section. Experiments were performed in three wellbore inclinations: 48, 60 and 90 degrees from vertical. Results show that hole cleaning in absence of drill pipe rotation is significantly improved if the well angle is less than a critical angle. This critical angle appears to be less than 60 degrees from vertical. Further result show that this critical inclination angle is dependent to the drill string rotation rate and the annular flow velocity.

Mobile jack-up rigs are frequently cantilevered over production jacket platforms to drill new wells or rework existing well for the offshore oil and gas at shallow and middle water depths. The proximity of the rig to the existing fixed platform will affect the performance of pile foundations of the platform and may cause some distress to the adjacent pile foundation by spudcan penetration. With the increasing accidents with respect to the spudcan penetration and spudcanpile interaction caused severe economic losses in offshore engineering of China, solving these problems is an urgent and significance assignment at present. Since the spudcan-pile interaction is a typical offshore geotechnical large strain large deformation problem, a numerical approach based on the large strain technique is a valid solution tool for evaluating spudcanpile interaction. The paper addresses additional responses of the adjacent pile induced by spudcan penetration in single clay profile and clay overlying sand profile using two different large strain large deformation numerical approaches. One is called two-stage approach. Firstly, ALE (Arbitrary Lagrangian Eulerian) approach is used to the displacement field of soil is calculated at the free field without adjacent piles, and then bending moments of piles investigate through conventional beam-column model. Another is CEL (Coupled Eulerian Lagrangian) approach to analyze the adjacent pile responses induced by spudcan penetration through three dimensional numerical model including spudcan, soil profile and adjacent pile. The feasibility of two approaches was verified through comparison between numerically predicted and experimentally measured results. Variations of pile bending moment induced by spudcan penetration are demonstrated with different pile length, spudcan-pile clearance and soil profiles. Comparisons of the numerically predicted pile bending moment and the experimentally measured values show that the both are close agreement for the different spudcan-pile clearance at the spudcan penetration depth of less than 15m in NC soil profiles. However, an apparent discrepancy lays on that the second positive peak bending moment from the numerical calculation by the beam-column model moves up to a higher depth than the measurement for the 40m pile length.

Solids/sand production is an unintended byproduct of the hydrocarbon production that, from an operational point of view, might potentially lead to undesirable consequences. This paper focuses on a study centered in the geomechanical perspective for solids production. An integrated workflow is presented to analyze the combined effect of reservoir pore-pressure, drawdown, in-situ stress, rock properties and well/perforations orientation on the onset of solid production. This workflow incorporates analyses at multiple scales: rock constitutive modeling at lab scale, 1D geomechanical models at wellbore scale along well trajectories, a 3D geomechanical model at the reservoir scale and 3D/4D high resolution reservoir - geomechanical coupled models at the well and perforation scale. 1D geomechanical models were built using log and field data, drilling experience and laboratory tests in order to characterize in situ stresses, pore pressure and rock mechanics properties (stiffness and strength) profiles for several wells. Rock shear failure mechanism was also analyzed in order to build a pre-drill model and evaluate the wellbore stability from a geomechanical point of view. Pre-production stress modeling was simulated to obtain a representative initial stress state integrating 1D geomechanics well results, 3D dynamic model and seismic interpretations. Mechanical properties were distributed considering properties calculated in the 1D geomechanical models as input. 3D stress field was validated with in-situ stress profiles from 1D modeling results. This simulated pre-production stress state was then used as an initial condition for the reservoir - geomechanical coupled simulations. Effective stress changes and deformations associated to pore pressure changes were calculated including the coupling between reservoir and geomechanical modeling. Finally, a 3D/4D high resolution well scale reservoir - geomechanical coupled numerical model was built in order to determine the threshold of sand production. A limit of plastic strain was obtained based on numerical simulations of available production data, DST and ATWC tests. This critical plastic strain limit was used as a criterion (strain-based) for rock failure to define the onset of sand production as a function of pore pressure, perforation orientation and rock strength. Conclusions regarding the perforation orientations related to the possibility of producing solids can support operational decisions in order to avoid undesirable solid production and therefore optimize the production facilities capacity and design to handle large amounts of solids and/or the clogging of the well.

Through the life-time of a production field in the offshore petroleum industry it is normal to drill several new wells for both production and injection purposes. The initial well template, either at the platform or at a subsea installation, has space for a fixed total number of wells. When this limit is reached an old well needs to be plugged and the well slot reused to allow new wells to be drilled. In order to re-use well slots and benefit from full diameter when constructing the new well, it is required to remove the tubulars in the upper part of the plugged well. The outside of these tubulars are normally in contact with cement or settled particles from shut-in drilling fluids. Removing the tubular through the cement or settled particle is always challenging and there is need for using new techniques. In order to address the dominating effects in these operations, down-scaled laboratory tests are performed. The experiments reported here are performed by pulling steel pipes out of a cemented annulus. The pipes used in the tests are down-scaled from typical casing sizes. They are either normal pipes, grooved pipes or pipes with and without collars. Two setups with different geometries are used. The first is selected to study the de-bonding effect from the cemented annulus and the mechanical friction that must be overcome to remove the pipe. The other setup is designed to show the effect of collars when pulling out the tubulars. Since most tubulars in wells have collars between each stand with extended diameter, this effect is important to consider when comparing laboratory results to field operations. Results show that the loosening force (de-bonding) and pulling force can be significantly reduced by manipulating the pipes with grooves prior to pulling them out. Further, the results show that the most significant resistance when pulling the tubulars are caused by the collars outside the pipe. It is also observed that the effect of collar is significantly reduced when the pipe is grooved between the collars. In total these results provide improved understanding on the dominating effects when pulling pipes from packed wellbore annulus.

Predicting drilling risks in advance is a major challenge in areas that lack drilling experience, and even when information from offset wells is available. Large overpressure was found at TD of an offshore exploratory well drilled mainly through shale. None of the other two previously drilled offset wells in the area had shown any sign of such a high overpressure. This study presents two complementary approaches to gain insight on the overpressure generation mechanisms. The effect of chemical compaction is first evaluated in terms of well cuttings analysis, including sample washing, high-resolution photo catalog, automated mineralogy and X-ray diffraction clay mineralogy analysis. The obtained mineralogical results confirm the presence of the dehydration diagenetic process involving the transformation of smectite to illite. Consequently, a numerical model is presented which combines the effect of mechanical and chemical compaction to predict pore pressure values very close to the overpressure observed during drilling. The model reproduces the depositional history of the lithological column by coupling mechanical and chemical compaction with fluid flow over geological time, and it allows predicting stress, porosity and pore pressure evolution at different geological ages. Calibration and verification of the results of the pore pressure model is done by comparison to drilling experience and logs (post-drill pore pressure profile, geology tops and density/porosity logs).

Fairings have historically been known to achieve in-line drag coefficients (C dx ) of approximately 0.60 across the Reynolds number (Re) range of 100,000 to 1,000,000, typical for the offshore environment [1]. The recent development of helically grooved drill riser buoyancy was shown to achieve C dx values of 0.65 for this Re range [2], presenting a strong alternative to fairing products especially considering the additional installation, storage and maintenance requirements of fairings. Therefore it is the purpose of this paper to investigate possible fairing designs capable of achieving even lower C dx values where fairings can still be beneficial in further reducing drag loading. This paper proposes a non-parallel reduced chord horseshoe (RCH) fairing design and is analysed using computational fluid dynamics (CFD) in 3-d using the transient k-epsilon (Reynolds-averaged Navier-Stokes) turbulence model. The modelling approach is validated against tow tank test data of a previous teardrop-shaped (TD) fairing design which showed good agreement with published, peer-reviewed literature. It was found CFD simulations with axially continuous fairings provide artificially low C dx values due to the absence of fairing end-effects and gaps between fairing sections. In essence, an infinitely long and uninterrupted fairing in the riser axial dimension is not realistic. Incorporation of this discontinuity sees a significant increase in Cd x compared to the axially continuous fairing configuration. Although this is the case, it was found C dx of approximately 0.48 or lower is achievable for the entire offshore Re range for the discontinuous fairing configuration (assuming a chord/diameter ratio of 2.0). Larger chord/diameter ratios would provide lower C dx at the cost of a longer chord length which may impact fairing installation efficiency. Longer axial lengths would also achieve lower C dx but with the risk of flutter instability. This development in RCH fairing design sees a possible option for further fairing applicability to offshore drilling operations where lower drag is desirable beyond that offered by the helically grooved buoyancy.

A newly developed Tri-Helically Grooved drilling riser buoyancy module design was tested in the towing tank of SINTEF Ocean in June 2017. This new design aims to reduce riser drag loading and suppress vortex-induced vibrations (VIV). Objectives of the test program were two-fold: to assess the hydrodynamic performance of the design allowing for validation of previous computational fluid dynamics (CFD) studies through empirical measurements, and, to develop a hydrodynamic force coefficient database to be used in numerical simulations to evaluate drilling riser deformation due to drag loading and fatigue lives when subjected to VIV. This paper provides the parameters of the testing program and a discussion of the results from the various testing configurations assessed. Tests were performed using large scale, rigid cylinder test models at Reynolds numbers in the super-critical flow regime, defined as starting at a Reynolds number of Re = 3.5 × 10 5 – 5.0 × 10 5 (depending on various literatures) and continuing until Re = 3 × 10 6 . Towing tests, with fixed and freely oscillating test models, were completed with both a bare test cylinder and a test cylinder with the Tri-Helical Groove design. Additional forced motion tests were performed on the helically grooved model to calculate lift and added mass coefficients at various amplitudes and frequencies of oscillation for the generation of a hydrodynamic force coefficient database for VIV prediction software. Significant differences were observed in the hydrodynamic performance of the bare and helically grooved test models considering both in-line (IL) drag and cross-flow (CF) cylinder excitation and oscillation amplitude. For the helically grooved model, measured static drag shows a strong independence from Reynolds number and elimination of the drag crisis region with an average drag coefficient of 0.63. Effective elimination of VIV and subsequent drag amplification was observed at relatively higher reduced velocities, where the bare test model shows a significant dynamic response. A small level of expected response for the helically grooved model was seen across the lower range of reduced velocities. However, disruption of vortex correlation still occurs in this range and non-sinusoidal and highly amplitude-modulated responses were observed.

During activities of ultra-deepwater exploration using drilling vessels an emergency disconnection between Lower Marine Riser Package (LMRP) and Blowout Preventer (BOP) stack could occur due to extreme environmental conditions. The disconnection is not instantaneous; it takes time due to the discharge of pressurized liquid from the system of hydraulic accumulators and the entire process is known as emergency disconnect sequence — EDS. Therefore, estimate the response time of the BOP control system is important to avoid damages that compromise the drillship safe operation. In this study, the BOP control system uses a hydraulic system constituted of accumulator bottles, a pressure regulator, rams, valves, and connectors. This system is considered to estimate the response time of cutting and sealing the BOP. The response time is estimated by applying the theory of fluid mechanics and Bernoulli equation to calculate the system equilibrium pressure. The accumulators are sized according to API 16 D and considered to have adiabatic behavior. Nitrogen is simulated as real gas. The validation of the proposed model is performed by comparison with a surface test for cutting of drill pipe with blind shear ram. The model is applied to a case study for ultra-deepwater in Campos Basin Brazil.

The scientific drillship Chikyu, operated by JAMSTEC has faced the problems with drill pipe damage and failure. After a failure, we examined the surface-measured drilling data, including Fourier transform analysis and spectrogram, and conducted an outlier investigation with an autoregressive model. We found some possible indications of top drive torque anomalies among the surface-measured drilling data. The purpose of this study is to attempt anomaly detection of top drive torque by applying machine learning approaches to such pre-examinations. Data acquired during the drilling operations of the Chikyu are first analyzed to observe the operations and determine the characteristics of the drilling data. Several hundred sets of surface drilling data are extracted and prepared as labeled learning data. Machine learning is then performed using several algorithms to build predictive models for anomaly detection of top drive torque. Simulations using these predictive models are then conducted for other sets of drilling data, including the anomaly conditions acquired during the operations of the Chikyu. The results demonstrate the validity of the predictive models. This study applies machine learning technique to the anomaly detection of the top drive torque with aim of preventing the drill pipe damage and failure. This paper describes our approaches in detail and discuss the results.

Offshore drilling with drill string over 10,000m long has many technical challenges. Among them, the challenge to control the weight on bit (WOB) between a certain range is inevitable for the integrity of drill pipes and the efficiency of the drilling operation. Since WOB cannot be monitored directly during drilling, the tension at the top of the drill string is used as an indicator of the WOB. However, WOB and the surface measured tension are known to show different features. The deviation among the two is due to the dynamic longitudinal behavior of the drill string, which becomes stronger as the drill string gets longer and more elastic. One feature of the difference is related to the occurrence of high-frequency oscillation. We have analyzed the longitudinal behavior of drill string with lumped-mass model and captured the descriptive behavior of such phenomena. However, such physics-based models are not sufficient for real-time operation. There are many unknown parameters that need to be tuned to fit the actual operating conditions. In addition, the huge and complex drilling system will have non-linear behavior, especially near the drilling annulus. These features will only be captured in the data obtained during operation. The proposed hybrid model is a combination of physics-based models and data-driven models. The basic idea is to utilize data-driven techniques to integrate the obtained data during operation into the physics-based model. There are many options on how far we integrate the data-driven techniques to the physics-based model. For example, we have been successful in estimating the WOB from the surface measured tension and the displacement of the drill string top with only recurrent neural networks (RNNs), provided we have enough data of WOB. Lack of WOB measurement cannot be avoided, so the amount of data needs to be increased by utilizing results from physics-based numerical models. The aim of the research is to find a good combination of the two models. In this paper, we will discuss several hybrid model configurations and its performance.

In recent years, lower oil prices have forced many oil companies to reduce capex costs by revitalizing brown fields, rather than developing new green fields. At the same time, the offshore drilling rig market has seen many old rigs, typically used for shallow water operations, being scrapped, leaving new generation, deep and ultra-deep water MODUs as the only viable option for new drilling campaigns. Based on the above, wellhead fatigue on older assets, especially in harsh, shallow water environments, has started to gain a central role during the planning phases of workover and intervention operations. In recent years, Suncor Energy began investigating an extension to its Terra Nova field, which began production in 2002. The field uses subsea wells tied back to an FPSO which is moored in 95m of water off Canada’s eastern Grand Banks, an area frequented by icebergs. Drilling operations for the field extension were planned to commence in summer 2017, and continue with a year-round drilling campaign using a Cat 6 MODU. Since the extension would involve sidetracks and interventions from existing wellheads, a series of wellhead fatigue studies were undertaken using a variety of industry recognized methodologies [1] to understand the levels of fatigue accumulation. Although there has been no evidence of wellhead fatigue damage, Suncor chose to take a very prudent and proactive approach, aimed at minimizing fatigue, and maintaining fatigue life for potential future drilling operations. An Instrumented Wellhead Load Relief (iWLR) system was installed, which is designed to restrain BOP motions, thereby reducing the wellhead loads considerably. The load reduction system virtually eliminates additional fatigue accumulation for the planned operations. Additionally, the instrumentation system enables the precise monitoring and tracking of loads applied at the wellhead for future analysis. This paper describes the engineering challenges needed to develop and install the iWLR system in a harsh, shallow water, arctic environment. This area is characterized by very stiff soils pitted with iceberg scours, where subsea equipment must be protected within 10m deep excavated drill centers to prevent iceberg collisions in the relatively shallow water. Additionally, the paper describes how the instrumentation system was integrated with the BOP MUX cable communication system, for the first time, to enable real time monitoring of BOP motions using high accuracy gyroscopes and load cells which monitor dynamic iWLR tether forces. A topside data gathering and processing system was developed to present wellhead loads based on the indirect method, with new algorithms established to account for the tether forces. Finally, the paper presents some preliminary high-level results, showing the efficiency of the system based on measured data.

Magnetic shielding of the Measurement While Drilling (MWD) directional tools and damages to mud pumps, down-hole tools and casing/drill-pipe and difficulties in understanding logging results are some of the main problems caused by steel and magnetic contaminated drilling fluids. In order to have these problems significantly reduced, all the magnetic contaminants should ideally be removed from the drilling fluid by the use of ditch magnets. Hence, the magnets and their ability to remove magnetic waste from the drilling fluid was evaluated by field evaluations. Data from a field test of a new ditch magnet system where all the drilling fluid is forced to flow into an area with a strong magnetic fields have been compared with data from an operation with a traditional ditch magnet system in order to see if there are any significant differences in the total amount of magnetic waste material collected from the two systems. It is shown how drilling length, inclination and casing size may affect the production of magnetic debris entering the drilling fluid, and hence, show the well construction dependence of the ditch magnet performance.

During drilling, there must be an evaluation of the maximum pressure that the formation can handle during a well kill scenario. This will depend on various parameters like fracture pressure, pore pressure, kick volume and several other factors. The depth of the next planned hole section will depend on if a kick of a certain size can be handled safely. This evaluation is often referred to as performing kick tolerances. When starting to drill a section, one will take a leak off test to get an indication of the fracture pressure at the last set casing shoe and this will be important information for the kick tolerance results. For HPHT wells the margin between pore and fracture pressures will be small, and one often has to resort to using transient flow models to perform the kick tolerances. However, there are many uncertain parameters that are affecting the results. Some examples here are pore pressure, type of kick and kick distribution. There is a need for trying to incorporate the uncertainty in the calculation process to give a better overview of possible outcomes. This approach has become more and more popular, and one example here is reliability based casing design. This paper will first describe the kick tolerance concept and its role in well design planning and operational follow up. An overview of all parameters that can affect the results will be given. In water based mud, the gas kick will be in free form yielding higher maximum casing shoe pressures compared to the situation when oil based mud is used where the kick can be fully dissolved. Then it will be shown how both an analytical and a transient flow model can be used in combination with the use of Monte Carlo simulations to generate a probabilistic kick tolerance calculation showing possible outcomes for maximum casing shoe pressure for different kick volumes. Here uncertain input parameters that can affect the calculation result will be drawn from statistical distributions and propagated through the flow model to estimate the casing shoe pressure. Multiple runs will be needed in the Monte Carlo simulation process to generate a distribution of the maximum casing shoe pressure. This will demand a rapid and robust flow model. The resulting maximum casing shoe pressure distribution will then be compared against the uncertainty in the fracture pressure at the last set casing shoe to yield a probability for inducing losses. The numerical approach for predicting well pressures and a schematic of the total calculation process will be given. Emphasis will also be put on discussing how this should be presented to the engineer with respect to visualization and communication. It will also be shown that one of the strengths of the probabilistic approach is that it is very useful for performing sensitivity analysis such that the most dominating factors affecting the calculation results can be identified. In that way, it can help in interpreting and improving the reliability of the kick tolerance simulation results.

Stick-slip is one of the typical phenomenon which is observed in offshore drilling and considered as a critical problem for the drilling operation. The stick-slip makes a large fluctuation of drill bit rotation, even though the top of the drill pipe is rotating at a steady velocity and sometimes causes the damage of the drill bit. Additionally, it leads a crushing of the sediment layer which is a big problem especially for the scientific drilling [1][2][3]. The main purpose of the scientific drilling is to correct high quality core samples of sediment layers under the seabed. However, once the stick-slip occurs, it makes difficult to recover a high-quality sediment layer core sample. Therefore, it is necessary to detect the occurrence of stick-slip and its fundamental characteristics such as oscillation periods and amplitudes by simulation with the aid of surface drilling data, which can be monitored during the drilling operation to mitigate or prevent stick-slip. It would be advantageous to identify the characteristics of the stick-slip from the surface drilling data. The past study [4][5][6] investigated a numerical method to analyze the stick-slip by solving the NDDE (Neutral Delay Differential Equation) which is derived from torsional vibration equation. A small-scale model experiment was conducted in a water tank to observe the stick-slip phenomenon, and the result from the analytical model is evaluated with that obtained from the experiments. In this study, the numerical model is applied for the stick-slip analysis not only of the drill pipe model but also the actual drill pipe in operation. The solutions of the NDDE is depend on not the initial value but the initial history of the solution, because NDDE contains a delayed function term. Especially, the initial history settings have much effect on the numerical solution of NDDE in case of the actual drill pipe. Additionally, to solve the NDDE for stick-slip analysis, we must set some model parameters concerned with the frictional torque on drill bit. The present study investigated the effects of the initial history and the model parameters settings on numerical solutions in detail and presented an procedure to determine the appropriate settings of the initial history and the model parameters by reference to the measured top drive torque.

In view of the increasing scarcity of energy resources, wells are being drilled to progressively greater depths for the production of liquid and gaseous hydrocarbons. Economical exploitation of these HT/HP reservoirs is possible only with the application of drilling and completion methods which do not damage the formation. Here, the reservoir-saving exposure of these deposits is an essential contribution. The damage potential of drilling fluids and treatment fluids is usually assessed on the basis of return permeability (RP) tests. An impairment of the effective rock permeability through appropriate candidate fluids (drill in fluids, etc.) can be measured with special laboratory tests. In addition to the RP-Tests further investigations should be made to estimate the formation damage such as high-resolution digital photography, mercury porosimetry, scanning electron microscopy as well as microsection analyses. Within the framework of the German Society for Petroleum and Coal Science and Technology a project was carried out to evaluate common formation damage test facilities and to define the “best practice” meeting the requirements of RP-measurements under borehole-like conditions. After a thorough evaluation an advanced HT/HP facility for formation damage testing was designed and built. By using of this set-up, systematic return-permeability tests were performed under dynamic conditions for temperatures up to 180 °C, for a flow pressure up to 250 bar, and a mantle pressure up to 350 bar. This paper presents results from a study on the filtration and formation damage behaviour of drilling fluids under variation of the concentration and of the weighting material particle size distribution. Furthermore, promising results from changing dynamic and static filtration experiments are discussed.

One of the critical factors in the deepwater exploration and development is the temperature during the drilling process. Temperature in the wellbore will induce the wellbore instability, which means the bottom hole pressure will change according to the accumulated thermal effects on the density, viscosity of the fluid during the circulation. Unpredicted bottom hole pressure will lead to unknown well control risks, which make the deepwater drilling is in great danger and unacceptable for the engineers. In the casing design, the thermal effects were ignored in the past but with drilling deeper subsea wells, the thermal effects will exist inevitably. The extreme values observed at the seafloor could be as low as 40°F and as high as 150∼200°F at the wellbore annulus. Unfortunately, deepwater environments combine low temperatures, high pressures, gas and water that can induce hydrate formation. Hydrates can lead to drillpipe blockages and affect BOP operation. The low temperatures due to the hydrate or ocean current affect the properties of cement, which indicates to redesign cement slurry composition required. Except the effects on the density and viscosity of fluid, the rising temperature in the annulus between the drill pipe and casing will make the trapped pressure increase in the annulus between outside casings. If the annulus build-up pressure can’t be released without rapture disks, otherwise the trapped pressure is beyond the initial design pressure, and the potential damage will happen. This paper provides a simplified method to predict the circulation temperature under steady-state heat transfer in the deepwater rissssserswellbore, and a simulator is developed.

During riserless drilling operations, which are carried out in some scientific drillings and in the initial stages of all drilling operations in oil and gas exploration, a lifting force is generated in addition to a drag forces in ocean current environment owing to the ocean current and the rotation of the drill pipe. This is called the Magnus effect, and it is a critical phenomenon during such operations. First, the lifting and drag forces are calculated using the computational fluid dynamic (CFD), and the lift and drag coefficients are calculated for several rotational velocities of the drill pipe and the velocities of the ocean current. It can be observed through the calculations that the lifting force increases as the rotational velocity of the drill pipe increases, and it reaches a level of approximately several times that of the drag force. The force reaches such a considerably high magnitude that it can induce the motions of the drill pipe, resulting in the generation of a high bending moment. An analytical model of a drill pipe has been established by applying an absolute nodal coordinate formulation (ANCF), which can express a relatively flexible and long pipe, such as a drill pipe. ANCF is a finite element method, and was basically developed to analyze deformable linear objects such as the cable. With ANCF, the absolute slopes of elements are defined based on the absolute nodal coordinate. Finally, the drill pipe motions are simulated using the established model by applying the results of CFD simulations for sample cases and referencing the operation of the Chikyu.

In both of scientific and industrial drilling, it is not desirable to any have accompanying vibrations, large fluctuations, or other unexpected dynamics disturbing a steady and stable drilling process. One of the origins of such disturbances can be the flexibility of the drill pile; drill pipe is easily deformed by external perturbations because it is very long and slender. To specify the stable range of parameters of drill pipe, we theoretically and numerically analyzed a Cosserat-type mathematical model of drill pile. The values of the parameters of this model were set to appropriate values representing actual riserless drilling situations adopted in the operations of the scientific deep-sea drilling vessel Chikyu owned by the Japan Agency for Marine-Earth Science and Technology (JAMSTEC). We concluded that the buckling of pipe should be treated as a possible accident, but buckling does not happen in the normal operations of the Chikyu.

Petroleum engineers are aware of the advantages of directional and horizontal wells. In case of intermediate deep wells, the preference is the customary solution, in which a well is drilled vertically to the kick off point, and then moved directionally to the reservoir level. Nowadays, due to the advent of extended reach drilling, this approach does not satisfy the meant goal anymore. In extended reach drilling, the concern lies on the drill pipe’s strength. Because of the great depth of the borehole, the torque and tension below the drill floor increase and could reach the drill pipe’s strength. Therefore, in order to extend the wellbore reach, it is necessary to minimize the torque and drag. Several authors have mentioned that catenary profile may help reduce torque and drag. The purpose of the paper is to analyze the mechanics of the drill string, and to understand the stress distribution along the drill string and the geometry of the well configurations while bringing the borehole from a vertical to a horizontal position. . This will be achieved by means of an analytical comparison between the catenary profiles and the conventional well configurations. A novel catenary profile which improves the previous models is also presented in this paper. The modified catenary has a larger curvature of the drill string; particularly in the upper parts of the borehole the bending stresses are small. The modified catenary profile, which resembles a free hanging cable, can be a novel method in directional drilling of deep and extended reach wells. Thus, the build rate in the modified catenary is being continuously increased until it reaches the desired position. It is different from conventional methods used especially in horizontal drilling to connect the vertical and the horizontal section, where the build rate is kept constant. The focus of this paper lies on the study of catenary’s geometry as a complex well path and the induced stress. Different approaches are used and compared.

Currents and waves cause flow-structure interaction problems in systems installed in the ocean. Particularly for bluff bodies, vortices form in the body wake, which can cause strong structural vibrations (Vortex-Induced Vibrations, VIV). The magnitude and frequency content of VIV is determined by the shape, material properties, and size of the bluff body, and the nature and velocity of the oncoming flow. Riser systems are extensively used in the ocean to drill for oil wells, or produce oil and gas from the bottom of the ocean. Risers often consist of a central pipe, surrounded by several smaller cylinders, including the kill and choke lines. We present a series of experiments involving forced in-line and cross flow motions of short rigid sections of a riser containing 6 symmetrically arranged kill and choke lines. The experiments were carried out at the MIT Towing Tank. We present a systematic database of the hydrodynamic coefficients, consisting of the forces in phase with velocity and the added mass coefficients that are also suitable to be used with semi-empirical VIV predicting codes.