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The purpose of this paper is to share the challenges and engineering solutions in managing risk of using nitrogen as the refrigerant in the LNG (Liquefied Natural Gas) liquefaction process on a Floating LNG (FLNG). In December 2016, the first FLNG started to produce LNG 130 km offshore using Nitrogen Liquefaction Technology, which is also the first in the world. Multi-Component Refrigerant (MCR) is commonly used to liquefy natural gas worldwide in the LNG plants. However, the Nitrogen Liquefaction Technology has been selected in view of its inherently safer nonflammable non-corrosive property, simplified process and reduced refrigerant handling and storage onboard. As compared to MCR, the flammable hazard on the FLNG is reduced by adopting nitrogen as refrigerant. Nevertheless, during the course of engineering design, other risk that could potentially be posed by nitrogen was identified. The main concern is the brittle fracture and anoxia risk in the event of cryogenic nitrogen loss of containment. This leads to engineering challenges in terms of the process containment, structural impact, ability to detect, safe disposal and drain and lifesaving appliances, etc. This sharing can be the pioneer reference for other FLNG designs in particular the refrigerant system, the relevant risk management and the engineering solutions.
Poor drilling performance can lead to increased costs when enhanced drilling performance and extended reach are the main goals for oil operators. Service companies and operators can use the latest technology and several pre-well planning processes and methods to enhance drilling operations effectively and attain these goals. These processes include developing a thorough understanding and application of the geological structure and conducting a formal planning process that incorporates all aspects of drilling, well design, formation evaluation, bit selection and bottomhole assembly.
In this dynamic market where companies are trying to minimize the cost and attain the objective, basic planning and execution using the latest advanced technology are not enough to provide significant performance improvements.
Extensive job planning, including sensitivity analysis, is essential. During the execution phase, close monitoring of drilling parameters and continual testing against modeled data help identify hazards early.
Enabling quick and informed decisions to ensure safe and efficient drilling in a challenging environment will be one of the main factors to improve performance.
Using the right downhole optimization tool with highly experienced engineers enable the interaction with real-time parameters. That's the key factor to overcome extended-reach challenges such as Steering in different environments Vibrations Transfer of usable energy Hole cleaning and quality indications
Steering in different environments
Transfer of usable energy
Hole cleaning and quality indications
Supporting downhole optimization with real-time geomechanics will influence the success rate to deliver the expected performance. The involvement of geomechanics in the planning stage and during execution enables faster and safer drilling and resolves many challenges in extend-reach wells such as Wellbore stability Hole quality Hole cleaning Pressure management Torque and drag Mud system and properties
Torque and drag
Mud system and properties
This paper highlights the importance of utilizing a downhole optimization tool and real-time geomechanics by describing a case study from the Middle East.
In this study, pore pressure prediction for a HPHT exploration well was conducted using both convention 1D modeling method and 3D basin modeling approach. Due to the considerable challenges encountered in three nearby fields (narrow mud weight windows, over pressure up to 17.0-17.8 ppg, and temperature as high as 185 °C at projected well TD), 3D basin modeling was considered as an alternative approach to help reduce the uncertainty due to lack of constraining data for conventional 1D modeling.
Both Eaton and Bowers methods were used to generate 1D models of the pore pressure profile from seismic interval velocity. Calibration of the models was based on offset wells of the three nearby fields. On the other hand, 3D basin modeling approach was used to model all three fields together. Detailed lithology was defined for each layer of the basin. By carefully calibrating the relationship of porosity-effective stress, porosity-permeability, and varying sealing capacities of the faults, a good match was obtained between the 3D basin pore pressure distribution and pressure data measurements from offset wells of all three nearby fields. After the calibration process, pore pressure profile of the HPHT exploration well was extracted along the proposed drilling well path.
Modeling a basin consists of reconstructing the deposition history of the entire sedimentary sequences from geological, geophysical, and geochemical data. It allows establishment of paleo water depths and heat flows in burial sediments to understand the hydrocarbon generation, migration, and accumulation processes during the geological history of a basin. The accurate definition for porosity-effective stress and porosity-permeability relationship of layers of source rock, reservoir, and seal will generate reliable pressure regimes in the basin. Extraction of 1D pore pressure profiles showed an excellent match with measured pressure in offset wells.
In addition to providing pore pressure prediction to optimize drilling plans, 3D basin modeling could deliver rock properties data for further wellbore stability studies in exploration areas. This is valuable for HPHT offshore drilling to help reduce the possibility and severity of drilling issues such as kicks, losses, and wellbore collapse.
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.
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.
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.
Compilation of lessons learned from torque-increasing techniques for rotary shouldered connections and compatibility considerations with rig equipment when using them.
Chee, S. S. (Schlumberger) | Tan, H. (Schlumberger) | Ando, M. (Schlumberger) | Pai, S. (Schlumberger) | Yandon, E. (Schlumberger) | Yamamoto, K. (Japan Oil, Gas and Metals Corporation) | Suzuki, S. (Japan Oil, Gas and Metals Corporation)
Gas hydrate production commenced from two production wells drilled in 1,000 m of water in the Nankai Trough, Japan, in May 2016. Two adjacent monitoring wells were drilled to monitor the in-situ event change of the hydrate reservoir over a two-year monitoring period. To achieve this monitoring purpose, an innovative design of wellbore gauges was installed downhole to provide valuable temperature and pressure data to show the dynamic nature of the gas hydrate dissociation front.
Using two seabed located autonomous subsea monitoring systems, data were continually logged from the monitoring gauges since they were installed in May 2016. To gain access to the recorded wellbore data, early project thoughts revolved around either recovering the large subsea monitoring systems or deploying remotely operated vehicles (ROVs) to tieback umbilical cables from the two subsea monitoring systems to the drillship, once it arrived at the field site. These techniques proved to be expensive and of increased risk to both personnel and equipment.
With a view to future safe and more cost-effective data harvesting techniques, a project was instigated to investigate using autonomous, unmanned surface vehicle (USV) along with vessel-based "dunker" methods to upload data from each of the monitoring wells using integrated high telemetry acoustic modem technology. The main objectives of the study were to verify data could be harvested and delivered to the client using a USV along with safe and repeatable piloting of the USV from a remote location.
Two USV missions have since been conducted, one in June 2016 and the other in March 2017. Lessons learnt from the initial USV mission, such as higher than expected sea surface currents and thrust limitations of the USV, were incorporated into the second deployment. This resulted in roughly 200 days' worth of data being uploaded and delivered from each of the two monitoring wells.
In this paper, we will outline how the project objectives were met and how some of the challenges, both technical and environmental, were overcome.
Novel well completion technique is used to ensure dual tubing performed under fatigue condition in Field B TLP. Based on initial tubing stress analyses, the dual strings are under compression during production. Also due to the Single Combo Top Tension Riser (SCTTR) design, first in the industry, the riser must be isolated from hydrocarbon flow. All 10 producers completed to date were tensioned successfully using this technique.
Samuel, Orient Balbir (PETRONAS) | Fabian, Oka (PETRONAS) | Rosato, Miguel (PETRONAS) | Khalid, Zaidan (PETRONAS) | Johari, Raimi (PETRONAS) | Jusoh, Zulaikar (PETRONAS) | Idris, Faisal Rizal (PETRONAS) | Hamid, Azim (PETRONAS) | Rosli, Faidzal (Welltec Oilfield Services M Sdn Bhd) | Salleh, Harris (Welltec Oilfield Services M Sdn Bhd)
The W field located north of the coast of East Malaysia, Malaysia in approximately 100 meters of water. Five dry gas wells, W1 through W5 were drilled and cased between Q1 and Q4 2016. The well depths fell between 3700 meters and 3825 meters measured depth (MDDF), 2with bottom hole temperatures as high as 180 degrees centigrade and formation pressures of 6500 psi. In addition, the wells were expected to be sour with 140ppm H2S and 20% CO2.
Originally the wells were planned to be completed with slotted liners, however this was proving to be problematic as it limited well control options and a safer solution was needed. An alternative un-cemented liner was run and it required to be perforated. TCP (Tubing Conveyed Perforation) and CTCP (Coiled Tubing Conveyed Perforation) were the logical choices, however after some considerable discussion it was agreed that wireline conveyed guns employing friction reducing rollers and tractors had the potential to save considerable rig time while satisfying all safety concerns. Detailed planning and simulation for this complex operation was required, the operator and service provider formed a strong technical alliance to achieve the objectives.
All five (5) wells were successfully perforated with a total of 840 meters of perforations achieved in 40 runs, 11 of them tractor conveyed, the longest gun string was 29 meters long and the total operating time was 783 hours. The campaign was completed with and operational efficiency of 94% and all objectives were meet. This paper describes the operational objectives and how careful planning managed to overcome the challenges encountered in these hostile environment. The case study underlines the efficiency of wireline conveyance in environments previously dominated by Coiled tubing and Tubing conveyance and highlights a new and powerful tool now available to operators.
This paper presented the extended reach well construction results to date of 3 infill wells: YA-01, YA- 05ST1, and YA-12ST1 during the Phase VI development drilling campaign in Yetagun gas field, offshore Myanmar which had delivered top-quartile drilling performance throughout every phase of well delivery.
The significant changes in drilling practices had led to the overall time and cost savings. Systematic approach to benchmarking drilling performance had been incorporated into the efficiency of the operation based on the Key Performance Indicators. Every phase of drilling, evaluating, and completing high angle wells was analyzed. The main technical hurdles contributed to the success of these wells were drilling practices, mud selection and directional control technique. Section-by-section was being described in the paper taking into account the factors that contributed to a top-quartile drilling performance including wellpath design, hydraulic, bottom-hole assembly design, drillstring design and torque and drag reduction methods. A few offset wells were selected and analyzed in order to act as a benchmark of expected performance, but up-front effort was established by proposing the significant key performance indicators (KPIs) which required specialized resources.
Value was generated through performance improvement. Engineering team of the drilling campaign dramatically achieved all the KPIs in the top quartile with zero LTI and successfully secured the reservoir target with the maximum drainage contacts as well as meet the gas volume target. Every aspects of the well design and construction was discussed, challenged and where possible, optimized for further study. The dramatic outcome of the drilling performance always came from the combination of some small incremental improvements and step-change innovations. Statistically analyzing of the KPIs covering the central tendencies and convergence link to the consideration of benchmarks. YA- 05ST1 successfully achieved Best in Class for WCPF and DCPF whereas the DDPTF of all the 3 wells were categorized in Quartile 1 performance. Among the significant changes in drilling practices that contributed to the time saving were the waiving of pilot hole, utilization of casing drive system, installation of tubing isolation Valve-Flapper for completion and implementation of drill to limit approach. Moreover, both the techniques and lesson learnt throughout the campaign were continuously revised, improved and distributed with the aim that the information can be built upon and lead to further improvements in the next extended reach well delivery.
In conclusion, the key differences in drilling practices throughout the campaign were proven to be practicable and in fact play an important role in time saving. Since the ERD has become an ever-more important enabling technique to exploit hydrocarbons nowadays, the replication of the best practices and lesson learnt should be shared for future extensive ERD wells planning and executions.
The proposed paper will examine the potential of remote working technology to overcome operational challenges, reduce mobilisation costs and enable collaborative working in real-time by bringing expertise located anywhere in the world to local sites through digital technology. The potential benefits associated with the technology are compared to traditional techniques using recent case study examples.
Following the ‘technology readiness levels’ approach used by NASA and other organisations, Wood took a methodical but expeditious approach to developing and testing remote working technology. Supply chain expertise was leveraged to identify suitable technologies (hardware and software) that met the stringent requirements of deploying such technology to oil and gas facilities. Once these technologies had been selected, initial office-based tests were completed, followed by deployment onshore and offshore for piloting. Valuable lessons were learned from piloting, and the technology refined. The so-called ‘eXpert’ system is now internationally deployed to onshore and offshore facilities and successfully embedded in day-to-day business.
The paper will detail comparative case study examples where this technology has been successfully applied. Key learnings are summarised as follows: The technology has the potential to better connect the workforce with data, processes and systems necessary for safe, efficient and more effective execution. It improves collaboration between colleagues located at different sites, facilities or offices and reduces disconnects and misunderstandings that can occur in distributed organisations. The hardware and software package is easy to use, requiring minimal user training and leading to swift adoption. The remote working technology reduces execution times for specific work scopes by 60%-90%, and significantly reduced mobilisation costs. By reducing the need for personnel mobilisation by helicopter once the technology is deployed to site, travel emissions can also be minimised. The ability to involve experts from anywhere in the world, in real-time, allows faster issue resolution, reduction of risk to personnel safety and avoidance of mobilisation costs.
The technology has the potential to better connect the workforce with data, processes and systems necessary for safe, efficient and more effective execution. It improves collaboration between colleagues located at different sites, facilities or offices and reduces disconnects and misunderstandings that can occur in distributed organisations. The hardware and software package is easy to use, requiring minimal user training and leading to swift adoption.
The remote working technology reduces execution times for specific work scopes by 60%-90%, and significantly reduced mobilisation costs. By reducing the need for personnel mobilisation by helicopter once the technology is deployed to site, travel emissions can also be minimised.
The ability to involve experts from anywhere in the world, in real-time, allows faster issue resolution, reduction of risk to personnel safety and avoidance of mobilisation costs.
Remote sites present some of the greatest operational challenges in the energy industry. Effective communication between offices and worksites is crucial to identify issues, diagnose problems and develop solutions. Frequently, teams of engineering specialists and decision makers are required to reach a conclusion, however getting these experts to site can prove difficult in terms of logistics and cost. This technology brings the knowledge and expertise of colleagues to site in a direct, meaningful and efficient manner.
The Thermoplastic Composite Pipe (TCP) has been established for a number of years as a viable alternative to steel and flexible pipe in subsea applications, with various intervention type of applications building track record in the field. After the successful installation of a Thermoplastic Composite Pipe for permanent methanol injection on Chevron's high-pressure Alder field in the North Sea in September 2016, Airborne Oil & Gas moved forward with the installation of a flowline for a full well stream application.
The selection of a TCP Flowline ensures a CAPEX reduction as it is manufactured in long continuous length up to 6000 meter and reeled on lightweight transport /installation reels. This allows for reel-lay or surface tow installation with a low-cost installation spread, contrary to steel pipeline requiring slow lay-barges. Furthermore, the TCP flowline can be terminated on the platform and pulled through the I or J tube without the end-fitting, allowing for small and light I or J tubes. The TCP Flowline can be installed in a single pass, optionally with a weight coating to achieve on-bottom-stability and immediate burial with for example a jet trencher if required. This single vessel installation results in the lowest material and installation cost for TCP Flowline compared to the alternatives.
Besides the CAPEX reduction, the selection of TCP flowlines ensures a significant OPEX reduction. Integrity management and corrosion prevention in particular have significant impact on operational cost. This is the case for new developments that more often see increasingly challenging environments with H2S, CO2, MIC etc, but also for existing operations that face unplanned shut-downs and repair cost caused by corrosion.
The fully bonded TCP Flowline has significant advantages. The TCP does not corrode, has a smooth bore featuring low pressure drop, is collapse resistant to large water depth and combines pressure and tensile strengths with spoolability. The unique and specific properties of TCP make it a cost effective choice for a variety of different applications, from shallow water flowlines, to flexible high pressure jumper spools and deepwater risers.