The jack-up platform will face the risk of punch-through failure when pilling in areas where a stronger-thinner layered soil overlays a softer soil layer. The punch-through failure that occurred in the South China Sea indicates that there are still shortcomings in the existing punch-through failure assessment methods. Therefore, this paper improves the shortcomings of the existing punch-through failure assessment method based on the simulation experiment. Firstly, the shortcomings of the existing punch-through failure assessment method were analyzed based on the case of punch-through incidents occurred in the South China Sea. Then, the main factors of punch-through were analyzed by means of simulation experiment, and the shortcomings of the existing method were improved. Meanwhile, a punch-through failure assessment method considering the spudcan tip height and loading process was established. Finally, taking a case of the South China Sea as an example, the improved model guided the penetration of jack-up platform and avoided punch-through failure successfully. By analyzing the case of the punch-through failure occurred in the South China Sea, the soil layer in which punch-through failure occurs has the characteristics that the thickness of stronger-thinner layered soil is close to the height of pile tip. In order to explore the main factors leading to punch-through failure, a set of experimental system simulating the spudcan punch-through was designed, and a series of punch-through simulation experiments were conducted. Simulation experiment results show that the reduction ratio of bearing capacity will decreases with the ratio of stronger-thinner layered soil thickness and pile tip height (d/h) increases. When the d/h is greater than 2, the reduction ratio of bearing capacity is less than 5%; When the pile tip height is equal to the thickness of stronger-thinner layered soil, the reduction ratio of bearing capacity is more than 95%. The innovation of this paper is that punch-through failure assessment method considering ratio of pile tip height and soil layer thickness was established.

Objectives/Scope This paper shares results from the first field deployment of an active sealing device in a narrow margin deepwater well in the Black Sea. The active sealing device represents a clean-sheet design approach purpose built for deepwater MPD operations. This paper shares highlights from the detailed design through the prototype testing to the first-use stages of the program. Methods, Procedures, Process This paper discusses three distinct program phases covering the overall process from concept development to field operation. First, the detailed design phase is discussed, introducing the reader to system components and functionalities. The second phase of full-scale testing is discussed from the design verification, system optimization, and systems integration testing perspectives. Finally, field results are shared detailing findings from the first deployment on a dynamically positioned deepwater rig drilling a narrow margin MPD well in the Black Sea. Results/Observations/Conclusions The paper shares findings, insights, and results from each of the phases of the active sealing device development program. Upscaling passive RCD technology for deepwater has negative effects on system performance. A non-rotating, externally functioned seal sleeve element eliminates multiple high wear components. Elimination of bearing assemblies and rotary seals removes common failure modes seen in deepwater. Redundant, actively controlled seal elements ensure wellbore seal quality throughout the seal life. A lubrication system injects mud between seal elements, enabling seal condition monitoring. Active seal condition monitoring alerts the rig crew when to replace the elements prior to failure. Full-scale testing has been completed demonstrating the system under simulated drilling conditions. Seal life demonstrated to outlast most deepwater MPD hole sections. Operational testing and integration testing reduce commissioning and testing time consumed on the rig. Active sealing device successfully integrated into the drilling riser and MPD specialty joint. Multi-modal system provides rig crew with distinct operational strategies to meet current parameters. Consistent seal life enables rig crew to drill MPD sections with confidence in the wellbore seal. Deepwater well with multiple MPD sections successfully drilled using new active sealing device. Novel/Additive Information The project includes secondary novel aspects such as drilling contractor ownership of the subsea and topside MPD equipment. The MPD system is integrated into the drilling control system allowing communication between the rig, subsea, MPD topsides, and all third-party systems, while also sharing commonality with other rigs in the fleet. An objective of the MPD system design is to enable new models of fleet management to meet drilling contractor operations.

Continuous efforts are made in drilling engineering to identify and develop advanced tools and technologies to maximize rate of penetration (ROP). Optimization of ROP has a major impact on both the reduction of the cost in terms of cost per foot and well delivery. Numerous correlations, methods, designs, models, and tools for ROP optimization are available in literature but rarely are applied in drilling operations. This paper introduces a robust methodology aiming to optimize the rate of penetration without inducing any associated wellbore stability problems. The objective of this paper is to detail the methodology and the effectiveness of the technique introduced. We report performance indicators for a trial well drilled using the novel approach and compare the findings with a conventionally drilled offset well. The drilling parameters for a challenging horizontal hole section were collected and analyzed to evaluate their effect on ROP performance. The drilling parameters selected are from corresponding hole sizes, formation and mud types with respect to the offset well for a consistent comparison. The proposed approach contributed to an enhanced well drilling performance by more than 40% and was instrumental in mitigation of stuck pipe incidents. In this paper, we introduced and verified a novel technique to maximize the rate of penetration (ROP) by optimizing the drilling parameters (RPM and WOB). As long as the CCA is less than 0.05, the proposed workflow in this study can be used to determine an optimized ROP in conjunction with a minimized DSE yielding ideal RPM and WOB values thereby reducing the cost per foor drilled. Evidence of the efficiency of the proposed procedure is provided by comparing the ROP and DSE measured for a horizontal section drilled employing the technique with data for an offset well drilled in a non-optimized fashion. Compared to the latter case, we reported a 44% improvement in ROP and a 48% reduction in DSE.

In an industry more increasingly focusing on efficiency and cost reduction, controlling well pressures during drilling is a fundamental requirement for operational efficiency, economic success and personnel safety, especially with very narrow margins and more extreme deepwater, high-pressure/high-temperature (HP-HT) environments. The use of continuous circulation system (CCS) as a simple managed pressure drilling (MPD) solution or as complementary technology to backpressure-control MPD in our industry focusing on reduced well costs and drilling time should be more diffused for its numerous benefits. It provides a downhole steady-state condition and, as a result, the formations do not suffer from pressure oscillations while hole cleaning and borehole stability improve, reducing the chance of problems in open hole. The practice of Continuous Circulation Drilling in a deep-water exploratory well, solves many drilling challenges through a continuous dynamic condition in the well and consequent benefits in terms of constant equivalent circulating density (ECD) and bottom hole pressure (BHP), continuous hole cleaning and solids transport. All these advantages result in significant safety standard gains, with reduced likelihood of kicks and losses during connection times, mitigation of stuck pipe incidents and improvements of rate of penetration (ROP). The first CCS was a ‘Coupler’. The "development of the ‘Coupler’ became the subject of an ITF (Industry Technology Facilitator) Joint Industry Project in October 2000, supported by five major oil companies." 1 After its first field protype land application in 2003, starting from 2005 many operators began using the ‘Coupler’ in tight pore pressure and fracture pressure windows. The needs to easily integrate and manage the CCS in every rig in operation moved the industry to a sub based configuration with lower footprint on the rig operations. Low systems reliability, potential safety issues and uncertain connection times slowed down the establishment of continuous mud circulation as a routine application in the drilling industry, even though this technology represents a substantial drilling breakthrough. For these reasons, a 2 nd generation CCS has been developed to make continuous circulation drilling a standard drilling practice in any land and offshore applications suffering drilling issues related to bottom hole pressure management, poor hole cleaning and borehole instability, with consequent low ROP and costly non productive time (NPT). This 2 nd generation is able to perform connections at full circulation rate with high safety standards and performance. At the heart of the evolution were an innovative sub lateral port configuration with a double pressure barrier configuration, an automated clamp to open and close the sub lateral port through a PLC controlled procedure. "Exploratory wells are in principle classified as challenging ones due to the inherent uncertainty relative to the downhole pressure limits, pore and fracture pressures, as well as formation surprises that are not clearly mapped from seismic. In addition, the exploration frontier is moving increasingly towards more difficult environments, and it is no surprise that many exploratory wells have been abandoned before reaching the planned total depth (TD), therefore failing to meet its commercial or technical objectives of collecting valuable data about possible reservoirs and hydrocarbon reserves." 2 The paper describes the operations and results obtained by the 2 nd generation CCS and its benefits in terms of cost control and safety enhancements in a deep-water exploratory well in Black Sea with a calculated pore pressure – fracture gradient (PP-FG) profile with a high level of uncertainty due lack of calibration wells and seismic velocity anomalies due to gas effect. The major Oil Company utilizing this system recorded a close control of the equivalent circulating density (ECD) during connections and improved borehole cleaning. Potential kicks during connections have been avoided and the system performed 58 operational days with 100% success rate, zero accidents and zero LTI.

A casing wear assessment was implemented as part of the workflow and methodologies for an operator well design process to better anticipate the critical failure mode of a tubular string. Because the reduction in tubular string wall thickness as a result of drilling and workover operations has been an ongoing concern within oil and gas field development, casing wear modeling with a workflow to accurately predict wear and minimize uncertainties is vital to maintaining well integrity throughout its lifespan with minimal or zero intervention. Because of multiple high-angle lateral branches drilled in lateral wells, the wear factor should be understood while managing casing wear. Wellbore and drillstring geometry can incur high lateral loads on tool strings and production casing, causing possible excessive casing wear. This wear reduces both burst and collapse ratings of the casing and can wear through the casing, resulting in costly remedial intervention measures for mitigation. This paper provides an integral insight for production casing wear focusing on a lateral well simulations study of the underlying wear factors ranging from the base case to the worst case. This enables a proper assessment in the well design by means of casing integrity, particularly for multilaterals and deep and/or long horizontal wells. A simulation and detailed workflow on how to incorporate its results into a multilateral/highly deviated casing design and stress analysis are discussed, thus providing an integration process resulting in improved anticipation of the critical failure mode for the investigated tubular string for this type of well.

The objective of this paper is to present the novel approach that the drilling contractor implemented for an operator in West Africa confronted with significant reactivation/recertification costs for one of its idle integrated platform rig. The drilling contractor proposed to couple the platform rig to one of their existing tender vessel, that is usually used to assist its own drilling rig, creating the first ever hybrid platform rig assisted by a tender vessel. The tender vessel was mobilized alongside the platform during the reactivation phase, offering ample POB capacity and avoiding the hiring of accommodation vessel, then the power and fluid system were hooked up to platform equipments that were to be used. This approach avoided the refurbishment/overhaul/recertification of the main and emergengy engine, the mud pumps and the mud pits and all the auxiliary systems that support the rig equipement. For the operator' s eighteen month workover and drilling campaign, the drilling contractor also proposed a cost-effective approach, looking into their available capital equipment inventory for compatible equipment still under certification. Once identified, the equipment were simply swapped so no additional recertification cost was required. The drilling contractor took the opportunity of this major reactivation to review completely the working flow of the rig and proposed a new offline pipe handling system and upgrade the online one, to improve the rig overall performance compare to the original design. All these novel approaches are reducing the overall project cost by 20% compare to a refurbishment of existing rig by OEM and introduce the offline pipe handling bringing an additional minimum 5% of operation time saving, making the project viable. The use of a tender vessel along a platform, feeding the platform rig equipment with power and fluids to extend the platform life is a novel approach in the industry that offer significant cost saving for operator suffering prohibitive reactivation/recertification costs of an idle fixed platform rig or any operator looking to reduce equipment weight on aging platforms. This paper will describe the major modifications that were required to make this world first attempt a success.

The increase in demand for oil leads the petroleum industry to require more complex tools to increase production at lower prices. This complexity is reflected in the complex geometry, manufacturing, assembling, deformations, stresses, and loads acting upon the drilling tools. This paper considers the case of a dual derrick that is used in deep water conditions to reduce the time consumed during drilling operations. The derrick is in motion conditions under waves and current influence. This paper, introduces a novel methodology to simulate a dual derrick in a marine environment, where the procedure considers the derrick under compression, by means of the forces coming from drilling loads or any other vertical loads on one hand, and the loads coming from wave and current loads transferred by the platform on the other hand; i.e., putting the whole structure in equilibrium, and then imitate or simulate the derrick movement coming from wave and current effect, where the effect of this motion due to loads acting upon the derrick is the main concern of this paper. The calculations were performed in STATIC STRUCTURAL considering rotational velocity and rotational acceleration, while a separate evaluation was performed in TRANSIENT STRUCTURAL considering the influence of translation velocity in addition to the rotational velocity and rotational acceleration. The results showed that the vibration and translation of the derrick (platform), excited by waves and current, increased the stress induced by vertical loads considerably. The maximum combined stress induced in the derrick increased by 24 % because of the platform rotation, while the maximum bending stress increased by 30 % compared with the case where vertical translation was neglected and reached considerably high values in the water table and beams connected to the water table. Rather than utilizing the traditional method of using the transient analysis to employ forces changing (in direction and magnitude) with time, this paper used ANSYS WORKBENCH to simulate the movement of the structure, to watch the stress distribution that resulted from this movement.

Downhole fluid analysis (DFA) has proved to be an effective technology for assisting in understanding reservoir dynamics, fluid distribution, reservoir compartmentalization and in-reservoir processes. Until recently, DFA technology was only available with wireline-conveyed tools. It was typically performed after the well had been drilled, limiting the ability for real-time decision making. The recent advent of logging-while-drilling (LWD) DFA technology — also known as fluid mapping-while-drilling (FMWD) — allows operators to make informed and timely decisions early on well construction, landing, geosteering and completion without pulling out of hole. This paper presents the results of an FMWD campaign by Repsol in Malaysia. FMWD technology was deployed in five wells with different objectives but with the common goal of enabling real-time decision making prior to the bottomhole assembly (BHA) reaching the surface. The FMWD objectives were to assess reservoir connectivity, monitor pressure depletion, measure CO 2 content, and differentiate between formation fluids (gas, oil, and water). For exploratory targets, the service was run to confirm the presence of hydrocarbons and to assess in-situ fluid properties. In a highly deviated well, the technology was used to confirm fluid properties for geosteering the wellbore through a targeted zone if it proved to be oil bearing. The campaign was very successful, and the objectives were fully achieved. With the completion of more than 130 pressure tests, a comprehensive and complete pressure profile was obtained in each of the five wells, allowing for the selection of the most appropriate depths for DFA fluid scanning and sampling. Twenty-four DFA stations enabled clearly identifying fluid types in various exploratory and appraisal targets. This information was then used to make key decisions on well landing and completion strategy. In addition, CO 2 was systematically identified and quantified by the tool optical spectrometers; thereby, accurately mapping its distribution across the field. Real-time data transmission using mud pulse telemetry allowed for real-time monitoring and important operational decision making. In some cases, only 15 minutes of pumpout was sufficient time to identify the movable reservoir fluid phase. In other cases, physical downhole fluid samples were collected once the mud filtrate contamination had sufficiently decreased below the predefined acceptable limit. In general, the time on each station was brief, which was attributed to reduced depth of filtrate invasion because FMWD operations took place soon after drilling. This paper presents the lessons learned from introducing of the FMWD service in exploration, reservoir management and geosteering, within the same five-well drilling campaign. Until the present time, this technology was only available using wireline. However, the introduction of LWD DFA has been found to be disruptive for reservoir management, drilling, completion, and geosteering applications, similar to the way formation pressure-while-drilling (FPWD) was a gamer changer for the drilling industry when introduced in early 2000s.

What constitutes a marginal field varies greatly but it is certain that extended time periods of low oil prices only magnify the challenges in developing such fields as it can stir even the largest reservoirs to go from commercially viable to marginal. E field is a marginal development project that must contend with all these unique set of challenges. For many years the project struggled to achieve minimum thresholds for funding. To develop the field during a low oil price market represented a cost-opportunity whilst presenting a value challenge. It is an extremely challenging thin oil rim reservoir development, under a complex and heterogenous geological environment, involving six long-to-extended reach wells in a loss-prone karstified carbonate. While the well planning and design built upon the Operator's considerable experience in carbonate and long reach drilling in the region, the campaign remained unique as the characteristic resided beyond the envelope of what had been accomplished before. The key distrincions were the much longer lateral length and the combined scope to target the thin oil rim in addition to the gas cap, which was the first-time application in this area. This is where technology played a vital part, as an enabler for delivering a complex project in a competitive manner. This paper briefly describes the planning stage of the campaign to ensure that the project was competitively scoped and delivered a fit-for-purpose solution, with focus on the technology implementation to address specific drilling challenges. Furthermore, it explains how a robust front-end loading, replication, and strong collaboration were key to making developable what was previously uneconomic.

In a heterogeneous and fractured carbonate hard rock with UCS more than 15K psi, drilling a highly deviated well is a challenging process that would require real time monitoring, using best in class MWD and LWD technology. A client in South Oman is in a development phase of drilling 1000m lateral wells to maximize the exposure for optimum oil production. The carbonate formation is characterized as heterogeneous vuggy dolomites with a network of regional fractures acting as the secondary source of porosity. The thin reservoir is isolated by thick layer or Anhydrites above and Shale formation below & managing geological uncertainties in real time is going to be the differentiator between success and failure. A combination of hybrid RSS to manage aggressive steering requirements along with distance to boundary imaging LWD tool to identify the bed boundaries & keep the well on course along with an azimuthal resistivity ultra-high imaging for reservoir characterization were deployed to overcome these challenges. The proposed solution was put into challenge on well X for drilling 5.87in lateral section and 1000 m lateral was successfully drilled. Hybrid RSS with aggressive bend setting helped in geo-steering the well and managed to achieve directional objectives to chase the geological uncertainties. After confirming the formation dip the well was steered 6to 7ft from the bottom conductive layer with the help of distance to boundary resistivity imaging tool. Real-Time High-Definitionazimuthalresistivity images helped in petrophysical interpretation and formation evaluation. Later, better density memory imaging data helped in evaluation of full borehole structural features and detailed fracture characterization. Hybrid rotary steerable systems along with best in class LWD tools provide purpose to fit solution to drill and geo-steered well in the optimum place. Success of this combination has eliminated the risk of exiting the reservoir leading to costly sidetrack scenario. At the same time, it has also helped the client to optimize production by geo-steering the well in the high porosity sweet spot and by Identifying regional fractures. Developing deep, hard and heterogeneous carbonate reservoirs is a complex and challenging affair and a conventional approach to overcome these challenges is not always producing the best results. A novel approach with the help of advanced rotary steerable and logging while drilling tools helped client in developing the field by minimizing the risks and maximizing the best reservoir exposure characterized, as the well are drilled.

This paper provides insight on planning and equipment-selection processes to successfully ream and drill in 9 5/8-in. casing through a water-sensitive shale formation, followed by a two-stage cement job to isolate lost-circulation zones. Proper placement of cement all the way to surface would be essential for providing an additional annular barrier to prevent casing-to-casing annular gas migration. Selection of the equipment is dictated by the operation to be performed (i.e., drilling new hole versus reaming a tight section), the type of reamer or drill shoe used, selection of specialized drilling tools and centralizers, along with stage cementing tools with integral packing elements, among many other requirements. Current drilling with casing (DwC) applications allow for plastering cuttings to the wellbore wall, creating a barrier that minimizes fluid losses. It also reduces the annular clearance between the casing and the wellbore wall, thus improving velocity and hole cleaning compared to conventional drilling practice. And, by introducing a stage cementing tool with an integrated packer, the annular barrier can be set inside the previous casing string to facilitate two-stage cementing, thus enabling full circulation, with cement to surface. Currently, 23 wells have been completed using this approach. A few of these jobs stand out. In one case, the casing string was reamed 501-ft (153-m) for 7.75 hours at speeds between 20 and 25 rpm using an eccentric nose shoe with carbide cutting structure on the exterior. Following the first stage of cementing (with zero returns received at surface), the team inflated the packer element of the stage cementing tool and initiated the second stage of cementing. During a second bottoms-up circulation, returns at the surface indicated successful setting and a successful second-stage cementing job in a reamed hole. In another case, the string was reamed 316 ft over 3.75 hours with 20 RPM rotation, until the bottom of the conventionally drilled hole was reached. Using a specialized drilling shoe, the string was then drilled 301 ft over 14.75 hours with 20 to 50 RPM rotation to the desired depth. Based on the broad success of this technique, the service provider built a detailed database of field jobs. This database provides a better understanding of the parameters and recommendations for this application. These insights include how to improve standoff and minimize damage to the element while rotating by using rigid centralizers, implementation of shouldered connections to allow torque transmission without compromising thread integrity, recommended RPMs and torque based on internal and external components of the tool, among others. This well construction technique has saved hundreds of hours of rig time by enabling operators to drill with the two-stage cementer (with integral packer in the string) instead of having to continue drilling a problematic open hole with a conventional assembly and run casing afterwards. By performing successful two-stage cement jobs, the need to perform top cement jobs due to total losses is eliminated. And finally, the technique eliminates the need for conditioning the hole to allow casing placement at TD, an operation that would require an additional trip with a dedicated bottom hole assembly (BHA).

The floating Gas industry is growing rapidly. As with all sectors in boom times, the focus is firmly on output. We need to ensure safety, compliance and profitability of what are high value, complex assets some of which operate close to high population densities. The speed of growth must be matched by an equivalent effort to maintain asset integrity while continuing production. Put simply, existing inspection and maintenance methods are not fit for purpose. This paper describes a joint industry approach for addressing these challenges that has proved successful for FPSOs. The industry needs to operate with high levels of asset integrity, with a programme of continuous improvement and with a long-term planning view. Effective Asset Integrity programmes are a key part of the strategy, and it is widely agreed that better use of data and robotics will help reduce unnecessary work and human risk. The HITS (Hull Inspection Techniques and Strategy) JIP, part of the FPSO Forum, has a membership made up of oil majors, service providers, classification societies and regulators. It has encouraged the development of new technologies, which have significantly improved safety and reduced operational costs. Drawing on experiences of other industries, the HITS JIP has driven innovation; safer, more cost-effective, more efficient technology, which has led to less impact on core operations of floating production assets: these include: The gas industry provided a means of placing nuclear industry miniature cameras into sea chests and isolation valves so that they can be inspected without affecting operations; Hull inspections were improved using deck launched, remotely operated underwater vehicles (ROVs) adapted to carry out cavitation cleaning of sea chest inlet grids, impressed current cathodic protection (ICCP) anodes and points of structural interest, such as bilge keel end connections; The forestry industry provided the idea for chain crawlers for inspection and repair of deep-water moorings; From the Nuclear industry, robotic inspections using high performance cameras, adapted to be inserted through Butterworth hatches or purpose-fitted ports in the deck enabling general and close visual inspection to meet regulatory requirement without the need for confined space entry; To protect the hull, diverless ICCP systems, deploying retractable anodes through the hull; and For pressure systems, using data more effectively; inputting inspection data to confirm fitness for service to an agreed level of confidence. This paper describes a joint industry approach for addressing these challenges that has proved successful for FPSOs. It will describe the steps that have already been taken to create an industry wide group including operators, class, regulators and service providers, to agree the primary challenges and to encourage development of solutions in a cost-efficient way. It will describe how innovations developed and proven in the FPSO and other sectors can be successfully introduced to this sector.

Accurate prediction of loads on any large offshore structure during loadout and transportation is of utmost importance, not only for the design of the structure but also to predict operational margin and prevent any unwanted damage onto the structure during the process. The design and engineering of Tension Leg Platforms (TLP) are usually carried out in accordance with the API 2T, MODU Codes and applicable company specifications/requirements. These codes provide extensive guidelines on design of TLP with respect to operational loads but specifics of simulation of loadout are not explicitly mentioned. This paper presents a method to estimate the loadout loads on any large offshore structure, in this case a TLP. The loadout operation of TLP usually comprises of lifting of the structure, i.e. the hull with its topsides, to transfer the loads from temporary support blocks onto jacks followed by skidding of the structure through a distance to the quayside and then crossing over the structure from the quayside to the Heavy Transport Vessel (HTV) and finally setting down the structure onto the HTV to transfer the loads from the jacks to the skid shoe guide posts and additional support structures, on HTV. It is the objective of this paper to present an optimized method of grouping the jacking system for safe transfer of loads during the above operation. This paper also talks about simulating and predicting the series of loads on the hull of the TLP during the entire process of loadout, crossover and setting down.

Objectives/Scope This paper introduces an active wellbore sealing system for use in Managed Pressure Drilling (MPD) incorporating a wellbore seal condition monitoring system. The paper will discuss how finite element analysis which has previously been validated with full scale testing can be expanded to develop the condition monitoring system. Methods, Procedures, Process In contrast to a passive rotating control device, an active MPD wellbore sealing system requires hydraulic pressure to engage a sealing element and form a wellbore seal. The paper will investigate the relationship between wellbore sealing pressure and hydraulic fluid parameters using the results of finite element analysis on a sealing technology which has been previously operated offshore in addition to extensive full-scale testing in a lab environment. Results, Observations, Conclusions The paper will show how the required hydraulic fluid requirements to form a wellbore seal change over time due to sealing element wear. The information can be used to predict the remaining life of the existing sealing element as well as proactively alarm the driller of the need to replace a seal sleeve due to a sudden deviation from expected behavior. The implementation of a real-time, condition monitoring system for the MPD wellbore seal is intended to increase the rig's confidence toward using MPD for challenging hole sections as well as circulating out small influxes from the well without closing the SSBOP, further reducing the risk of stuck pipe events. Novel/Additive Information The active MPD wellbore sealing system is a non-rotating, offshore wellbore annular sealing device which is integrated into the riser. It contains a seal of elastomeric composition which seals against drill pipe during all tripping and drilling operations. As the seal wears, the hydraulic closing fluid requirement to maintain an annular seal changes, which indicates the amount of seal material remaining.

In today's environment drilling, well workover and well intervention operations call for increased efficiency and safety. Concurrent operations are a method to increase efficiency. However safety should not be compromised. An innovative device has been developed to enable SIMOPS (Simultaneous Operations) from a jack-up. An analysis has been made to identify which operations, when executed from a jack-up, would benefit from the possibility to be done concurrently. Typically most well operations are done through the rotary table. Those operations are either using drillpipe, wireline or coiled tubing. The operations are thus often sequential and allow for working at one well at the time. On production platforms with multiple wells it would be of interest to work on more than one well at the time. For example working on one well with drillpipe while working on another well with wireline or coiled tubing. Also the setting and retrieval of temporary plugs can be done faster while not compromising safety. While the primary load path on a jack-up is through the rotary table some operations do not really require the high lifting and lowering capacity which is offered by the topdrive assembly in the derrick. Especially for wireline and coiled tubing operations the lifting and lowering capacity can be much lower. So an add-on device with reduced load capacity which enables non-drillpipe operations can be advantageous. Especially when it can be working free of obstructions under the cantilever of the jack-up. The new add-on device will increase rig efficiency during development drilling, well workover/intervention and plug & abandonment operations. It for instance enables wireline guidance into the well through its moveable arm with the hoisting point below the cantilever. This while other operations on an adjacent well are executed simultaneously through the rotary table.

Objectives/Scope This paper presents a comprehensive summary of the different techniques for increasing the available torque of existing drilling products, the limitations of these techniques and the best practices that can be implemented to reduce risks when using drilling tubulars beyond the API recommended make-up torques. Methods, Procedures, Process The torsional strength and make-up torque of a threaded connection are traditionally calculated by only using inherent attributes of the connection, such as the thread design, the yield strength of the connector's material, and the cross critical section of the connector. However, the design of a connector is not the only option to increase its operational torque. Stress balancing considerations and the thread compound friction factor can also help increase operational torque. The recommended make-up torque for rotary shouldered connections is typically defined by stressing those connections to 60% of their torsional strength, thus leaving a margin for using a higher make-up torque‒and hence reaching a higher operational torque. Another option to increase the available operational torque is to use a thread compound with an increased friction factor. API thread compounds are designed with a friction factor of 1. Because of this, when using a thread compound with a higher friction factor, the applicable make-up torque has to be corrected. Results, Observations, Conclusions Although stress balancing and the thread compound friction factor considerations can easily and economically increase the available torque of a connector during drilling and allow having more versatile products on the rig, these practices can also carry some risks. Novel/Additive Information Compilation of lessons learned from torque-increasing techniques for rotary shouldered connections and compatibility considerations with rig equipment when using them.

Hydrocarbons are the major source of energy. Its increasing demand has made the hydrocarbon exploration go beyond the shore. Offshore Rig power requirements are higher compared to onshore rigs. Diesel Generators are conventionally used for the power requirements of offshore rigs. This paper aims to suggest an idea to use the renewable sources of energy (mainly tidal energy) for energy generation in offshore. The idea is to have a Hybrid energy system, in which both the renewable and non-renewable sources of energy can co-exist together in a symbiotic relationship. The energy harnessed from tidal-waves shall be used to meet the power requirements of offshore rig alongside the diesel generator. This would result in overall more efficient and cost effective energy generation. Wave energy would be harnessed on wave energy harvester system platforms installed around the offshore rig set-up; on which the motion of floats would be transferred via hydraulics into rotation of generator which will produce electricity. The energy generated would be transferred to rig via wires and can be stored in batteries for transportation to land to meet other power requirements. An analysis of tides/waves generation is detailed. Available data for prototype of Wave Star Energy harvester is examined followed by Monetary-Energy Capacity analysis. SWOT analysis and environmental impacts are discussed. Various parameters affecting the Tidal energy generation are scrutinized. There is a need of an alternative source of energy in offshore rigs because of high environmental impact of diesel generators and other problems associated with it. Given the current global scenario and advancements in Electric automobile market, there is an exigency for a Hybrid energy system to meet the upcoming energy needs and boost the Global Energy Infra.

Egypt Western Desert drilling fields have been known for harsh drilling environment, shock and vibrations conditions, interbedding and abrasive formations. Drilling assemblies have normally been suffering from excessive damages drilling through these conditions. Motorized rotary steerable drilling systems (RSS) were mostly considered the favored mechanism of drilling in this environment as they delivered higher drilling performance and mitigated vibration harmonics from transmitting higher up the string. Realtime shocks and vibrations data from directional tools was critical information to ensure safe and efficient drilling parameters and managing this harsh drilling environment without operating the equipment beyond its specifications. In a recent western desert well, Khalda Petroleum Company (KPC) endorsed a new drilling strategy by modifying the conventional motorized rotary steerable drilling assembly from having only the RSS below the motor to having both the MWD and RSS tools below the motor. This modification was designed to enable KPC get closer measurements to bit with full transmission of all downhole data to surface to optimize the drilling parameters. The modification also aimed at increasing the bottom hole assembly (BHA) stability to prolong the run duration. To ensure reaching this goal, the design phase focused on two main directions. First, multiple finite element analysis modeling was implemented to ensure the optimum BHA stability and resistance to shocks and vibrations conditions. Second, KPC took needed considerations on the mud motor design, RSS operational procedures and MWD setup to ensure that these would fit properly in the new BHA design. The strategy implemented has shown great success in delivering the section safely and with no incidents related to downhole drilling uncertainties and conditions. The section delivered the required directional profile with great precision and adherence. The new BHA actual data has shown high conformance to the modeled data and no shocks and vibrations conditions were encountered. The section was drilled in one run and was considered the longest and fastest directional run in its field. This has eventually lead to delivering this milestone section 3 days ahead of its planned timing.

The key word for the production development of offshore methane hydrate reserves is "Low-cost". In this article, we propose the design of a subsea production well that could be deployed at the Nankai Trough, offshore Japan. Instead the traditional drillship, we intend to use a combination of three specialized vessels: (i) top-hole drilling vessel, (ii) well intervention vessel equipped with Coiled Tubing Unit and (iii) subsea equipment support vessel. These three specialized vessels have cheaper daily rates than a single last generation drillship. Keeping the limitations of such vessels in mind, we propose a well with a top-hole composed only by the surface casing. Further, we intend to use the "coiled tubing drilling" technology to drill-in, what shall reduce the operational time. Then a liner could be used as interface with the reservoir. In terms of completion, the methane shall be produced by the annular and a tubing shall be installed to remove the water from the well bore using a pump that is installed outside the well. Such arrangement makes the installation and maintenance of the pump easier because the equipment can be replaced without the need of a heavy workover. Summarizing, the use of specialized vessel in distinct phases of the well construction may reduce the cost in 2 ways: cheaper daily rates than a traditional drilling and reduced operational time due to specialization itself (reduced time for rig up/down of equipment for distinct phases). Further, the use of coiled tubing and a simple completion shall reduce the operational time and equipment costs.

A combined offshore jacket structure and foundation concept is presented, which is installable from a jack-up drilling rig. This novel system integrates the various components with extensive track record in both the offshore oil & gas and windfarm industries. It is founded on suction buckets that use water underpressure to drive installation of the foundation. It is rapid and quiet to install and re-usable; utilising the same jack-up that will be drilling and/ or abandoning the wells to perform the installation/relocation. The scope of the paper is to present the technical aspects of installation, structural and foundation engineering necessary for successful development of such facilities. This includes consideration of interaction between the structure and jack-up during both installation, but also during operation (work-over) and re-use.