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.

Uninterrupted delivery of production chemicals through umbilicals and capillary strings is absolutely critical for oil & gas operators to avoid build-up of solids in wells and flowlines as well as excessive corrosion of the subsea infrastructure. However, flaws in design, poor installation and maintenance of subsea chemical injection systems, or deviating from operational procedures can cause blockages or leaks. In this paper two case histories will be provided about chemical injection failures. One failure is related to the formation of gas hydrates in the umbilical due to malfunctioning of an injection valve. The other failure occurred due to delivery problems due to high viscosity. Some information will be shared on why these failures could occur and improvements to the qualification process to avoid this in the future. Several deepwater operators and service companies developed chemical selection criteria based on the guidelines and recommendations from the 2007-2011 "Blockage Avoidance in Subsea Injection and Control Systems" (BASICS) JIP. Many companies have incorporated these recommendations in a subsea qualification process for deepwater chemicals. Chemical injection failures often relate to mechanical failure or limitations to the subsea injection system rather than to the chemical itself – especially after the JIP recommendations were incorporated. However, a qualified chemical product may cause injection problems if a holistic review of the application is lacking. The case histories will demonstrate the criticality of collaboration between the operator, engineering company and suppliers; sharing system information and operational conditions avoids costly mistakes. The complexity of deepwater chemical qualification is to design experiments that reliably predict field performance from lab testing. Moreover, failure mechanisms, e.g. corrosion, gunking and polymerization, are slow processes and laboratory experiements have to be accelerated to much shorter timescales for chemicals to be deployed quickly in the field to treat the risks they are designed for. With the deepwater boundaries getting pushed to new limits some of the laboratory testing has to be redesigned to assess the risks for these extreme conditions. We will, therefore, provide an overview of the different kind of tests that are required and add some considerations on how the tests can be modified and how the test results are best interpreted for field application.

Hydrocarbon column height is one of the most important parameters that affects the volumetric calculation. Previous prospect volumetric calculations were done using statistics built from the existing database of column heights of hydrocarbon discoveries of deeply buried carbonate pinnacles in Central Luconia. A re-look of the discoveries revealed that not all of the data in the existing database are applicable for a given prospect due to the different geological settings. As it is a common practice to update the database from time to time, a refresh was done after new multi-PSC 3D seismic acquisition and interpretation was completed and more published well information from adjacent PSC's were made available. A more scientific approach was taken this time around; the effective sealing unit of the deeply buried pinnacles was compared against our prospect. All the deeply buried pinnacles in the statistics were effectively sealed by the clastic 5.8mya depositional sequence. The percentage of hydrocarbon fill for each buildup was plotted on the existing paleogeographic map of the overlaying sealing strata. Given sufficient charge, multiple factors remain that can negatively affect hydrocarbon accumulation in Luconia carbonate buildups. These include high aquifer overpressure, crestal faulting, and channels which can impinge on the reservoir and act as thief beds. Some channels may clearly be seen in the seismic, while some appear to be pinched-out, and others may be sub-seismic. In the area of carbonate build-ups that were used in the statistical database, lower percentage of hydrocarbon fill coincides with the presence of a regional channel complex, interpreted to act as theif zones. However for our prospect, within this overall channel complex, several large buildups seem to act as baffles or barriers to the channels, deflecting them away from our prospective carbonate build-up. Thus, by comparing with our prospect, we realized that the regional statistics might not always be applicable, depending on several geological variables. Our prospect has no thieving channel at top seal level and is further protected by the updip channel belt by another carbonate platform. We should not use statistics generated from discovery wells that are affected by the thief beds. Statistics are always favoured whenever we have little knowledge about a basin or subject. By showing how geoscience can drive the statistics, we will be reminded on how using it without interpretation may be misleading.

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.

As the industry rebounds from recent pricing challenges, operators are searching for methods during each stage of their well—from drilling to production—to make the field more economical without compromising safety, health and quality. This paper describes a different method for offloading a newly drilled well. In 2017, a well drilled in north Iraq targeted five productive zones. This directional well had a good potential to flow from upper zones which were producing around 3,000 BPD cumulative production. To get production from the upper four zones, conventional coiled tubing (CT) was utilized, and the well started to flow after lifting the drilling fluids. After testing the upper zones, the operator planned to evaluate the lower zone for the production. The well completion had sliding sleeve doors (SSD) and was installed for every zone separately. This well used a jet pump for offloading fluids from the last zone. The upper four zones were plugged using the SSD, so only the last zone was open for flow. A jet pump was designed using jet evaluation and modelling software (JEMS). The design was based on the optimum size of the nozzle and throat selected for the lowest zone. A downhole jet pump was modified, based on the existing SSD, and installed in the well using slickline. High-pressure power fluid was injected into the well from the annulus and returns were taken from the tubing. The well was successfully offloaded using the jet pump. The well was then tested for production using the same jet pump system, which resulted in around 1,300 BPD production. Jet pump systems require critical observation and proper understanding of the system for this kind of application. The well was economically offloaded using a jet pump system. This method saved a significant amount of time and money for the operator. Additionally, the jet pump system can be easily installed, designed and modified as per well and completion specifications. The nozzle throat combination can be changed on-site, depending on production results. The installation and operation procedure will be explained in detail for a comprehensive understanding of the system.

The objective of this paper is to share the Operator's first experience in utilizing ilmenite in an offshore HPHT well as part of a low cost well initiative and the value obtained by utilization of such a weighting agent in particular towards lowering ECD. After extensive testing micronized ilmenite was used as the weighting agent for the synthetic based drilling fluid (SBM) for the B1 well. This well was classified as high complexity with a narrow margin window and with predicted maximum bottom hole pressure of 12,013 psi at 3,990 m TVDDF. Extensive laboratory testing was conducted to determine the optimum formulation for a 16 ppg SBM. Part of the methodology in the testing was conducting rheology comparisons between various weighting agents, manganese tetraoxide, barite and micronized ilmenite. The subsequent results were then run through hydraulics simulations to determine the best formulation for optimized hydraulics. Additional testing was conducted to determine the overall stability of the system including conducting static sag tests with a similar duration to the planned wireline logging operation. The primary drivers for using this fluid were to reduce ECD in a narrow margin environment and facilitate the taking of good wireline logs by providing optimum hole conditions without any sag. The micronized ilmenite system successfully achieved a similar rheology to manganese tetraoxide with low PV's of less than 50 cP at 17 ppg and a sag index of less than 0.52. These properties were at an OWR of 80:20. This led to both the successful drilling of the well and completing the required wireline logging with no fluids related NPT or issues related to sag. During logging, the mud was static for 5 days without problems. The mud weight of 17 ppg was the highest density, at that time, at which the micronized ilmenite system had been used.

The sliding sleeve has been widely used in upper completions as a useful flow management device to enable selective communications between the production tubing and the annulus. Traditional sliding sleeves are mechanically operated by standard wireline method, which not only results in non-productive time and potential operational risks but also restricts sliding sleeve applicable in vertical wellbores only. To overcome the limitations, this paper introduced an innovative Hydraulic Controlled Sliding Sleeve (HCSS), which eliminates interventions with conventional wireline shifting tools. HCSS offers instant open/close operation by surface controlled hydraulic pressure through a single control line. HCSS features unique advantages over mechanical sliding sleeves, by its operational simplicity, independence on wireline units, and applicability in deviated wells and horizontal wells. The application of HCSS could save non-productive time, reduce operational risks and improve operational efficiency and economics. This paper will give a comprehensive demonstration of HCSS and illustrate the working principle in detail. Unique features and capabilities over traditional sleeves will be discussed explicitly. HCSS will be opened by applying hydraulic pressure from the surface control unit to activate the movement of the inner sleeve, and it will be closed simply by releasing the pressure, which will allow the inner sleeve to return to its original position. In the case of hydraulic control failure, HCSS also equipped with a secondary open/close mechanism by the special shift tools operated by coiled tubing. The authors conducted two representative case studies of HCSS application in offshore upper completion in Bohai bay in China to further highlight the improvement of operational efficiency and well economics.

The reliability of subsurface barrier valves has long been an industry problem. This can lead to costly interventions, especially apparent in deep-water subsea markets. This paper describes the world's first deployment of multicycle barrier valves in 2 subsea wells in Australia that uses innovative methods of both remote activation and triggering, that have been previously unavailable on the market, and attain a step change in reliability. The remote activated barrier valves were deployed as part of a subsea gravel pack system. They were initially run in hole (RIH) open as part of the lower completion, then closed mechanically. The valve was subsequently opened via Radio Frequency Identification (RFID) tags and then closed again mechanically to allow the running of the upper completion. Frequency modulated pressure cycles were applied to the well to open the valve and allow the well to flow. The valve functioned exactly as planned, and it was demonstrated that it could be closed multiple times on a semi-sub vessel. The valve was then opened via RFID tags conveyed on wash pipe. This is a much more reliable method when in high debris environments. The valve was opened for the final time via frequency modulated pressure cycles. These are better able to be transmitted through debris and are not affected by other hydraulic events in the well. The hydraulic pump that is used to actuate the tool provides a constant force directly to the ball valve mechanism and is not subject to failures over time like existing gas charges, ratchet mechanisms or springs. The RFID, Mechanical or pressure cycles used to trigger the valve offer a huge increase in operational flexibility that have never been able to be realized with existing technologies.

The paper presents a case study of an Operator who successfully drilled two challenging wells through optimization of the drilling fluids. Well A was a HPHT well drilled with mud weight up to 18.6 ppg with overbalanced pressure as high as 6,800 psi – the highest overbalanced pressure experienced by the Operator to date. Well B was required to drill through depleted sand and unstable shale where series of severe loss circulation and wellbore instability issues were experienced in the nearby wells. Due to its HPHT nature, the design of the drilling fluids in Well A was expected to have a total solids content up to 70% by volume. Due to this high solid content, the rheology of the fluids system is inherently high posing an issue related to excessive ECD. To further exacerbate the issue, the extreme differential pressure which was expected to be observed in Well A requires the inclusion of bridging material in the system as part of the mitigation plan to minimize the risk of differential sticking. Conventional bridging material such as calcium carbonate and graphite with concentration between 20 to 40 ppb will further increase the amount of solids in the system. Likewise, in Well B, the Operator also observed that the application of common bridging material in the drilling fluids does not help in addressing the severe losses and wellbores instability issue observed in the offset wells. Almost 60% of the offsets encountered severe loss circulation as high as 6,000 bbl mud loss per well. This paper will share several initiatives by the Operator during the design stage in order to optimize the mud formulation to address the challenges for both of these wells. These include evaluation of various types of bridging material and "a must have" mud testing to assess the performance of the drilling fluids system. Subsequently, the Operator has successfully drilled these wells with no issues related to differential sticking, loss circulation and wellbore instability.

Alpha 1 was recognized as the highest overbalanced well drilled in operator's history. A comprehensively designed superior mud system has enabled the well to be drilled successfully, meeting its objectives of producing shallow and intermediate intervals and able to appraise deeper 8-1/2" HPHT section. The HPHT section exhibits a marked pressure spike to pore pressure up to about 14,000psi with 310°F bottom hole temperature. The formation prognoses are very much uncertain due to limited data available from offsets. This considerable HPHT drilling challenges are further compounded by the high overbalance pressure - approximately 6,800psi observed while drilling with 18.4ppg mud weight. Drilling mud designed for high overbalanced pressure well requires special attention particularly on the HPHT filtration control and mud rheology. In deeper section where wellbore pressure control is critical with approximately 1.5ppg drilling margin, the mud formulation and rheology was optimized in minimizing ECD. The components of the mud were heavily scrutinized to minimize risk of wellbore losses and differential sticking. Low fluid invasion system was introduced to provide wellbore shielding mechanics. Operator has made initiatives of conducting unconventional laboratory works in assuring the technical performance. Cost reduction initiative was also made by optimizing mud design with surplus mud and chemical inventory. These were incorporated into the mud design as to have low cost and fit for purpose mud formulation. In actual operation, the mud rheology and ECD were deviated from the plan. Both major deviations demanded several adjustments on the mud formulation. Several lab tests were conducted and unconventional mud apparatus were brought offshore for further fine tuning on mud formulation. The 8-1/2" HPHT hole section was successfully drilled with no issue pertaining to losses, drag during tripping and differential sticking. The best practices and lessons learnt replicated from few HPHT wells drilled previously, in combination with the close collaboration on laboratory works with contractors has contributed greatly to the success of the well.

The award-winning Subsea Equipment Australia Reliability (SEAR) Joint Industry Project (JIP); is a partnership led by Wood with participation from a group of operators namely Chevron Australia, ConocoPhillips, Inpex, Santos, Shell Australia and Woodside. Now delivering Phase 6, the JIP is focused on collaboration and knowledge sharing in order to improve the competitiveness of Australia's oil & gas industry by addressing critical challenges associated with subsea equipment failing prematurely. This paper will provide an overview of the SEAR JIP and outline lessons learned, and value created. Results from the reliability database will be presented as well as findings from ongoing field trials on the four living laboratories deployed in different geographic locations and water depths in Northern Australia. This paper will also discuss challenges associated with subsea controls umbilicals that are prone to emit hydrogen gas and fluids at the surface facility through the electrical junction boxes. The end goal of SEAR JIP is to develop an industry wide recommended practice, with regional guidance notes for equipment and field design. The recommended practice is intended to reduce operating cost for existing and future projects, while identifying technologies that are specific to Australian waters.

In general, the formation in offshore East Malaysia is more challenging than the formation in offshore West Malaysia. One reason is primarily because of the highly interbedded soft and hard formation throughout the well. What is even more challenging is the nature of polycrystalline diamond compact (PDC) cutters, which are prone to breakingbecause of the impact from those highly interbedded formations. Field T is a fieldwithin the area that is well known for using a significant amount of drill bits to drill a well. Most PDC bits exhibited bad dulls and cutting structure conditions, particularly in the shoulder area. Broken and chipped cutters have resulted in the bits being pulled out of hole prematurely, unable to continue drilling to well total depth (TD). In the early days during the exploration phase, the PDC bits used in this field ended up mostly with ring out (RO) dulls regardless of the number of blades being used. This bad dull condition improved significantly during Phase 1A development drilling in Field T compared to drilling during exploration. However, it has being recognized that further improvements could still be made during Phase 1B development drilling in terms of rate of penetration (ROP) without compromising bit durability. To address the challenge, the approach should be a different bit design modifications rather than just a taking an off-the-shelf bit.Collaboration between the drilling project team and drill bit design engineers began months before the project was scheduled to start. This began the continuous interaction process between both parties to enhance drilling efficiency for the operator. After several meetings, discussions and presentations, the drilling project team and drill bit design engineers developed the optimum bit design solution for this application. Several design iterations were performed to obtain the most efficient cutting structure layout before finalizing and manufacturing the bit specifically designed for this field T. As a result, the entire 8.5 inch section was drilled using one specifically designed bit with an outstanding rate of penetration improvement, which was the objective of the 8.5 inch holesection. The successful result reflects a great team effort attained by thorough planning and execution process by both drilling project team and drill bit design engineers.

A leading exploration and production company in India drilled a high-pressure/high-temperature (HP/HT) well in eastern offshore India and required drillstem testing (DST) to be conducted using the service company's multiple-set HP/HT retrievable packer, multicycle circulating valve, and multicycle tester valve. The bottomhole temperature at reservoir depth was approximately 460°F. This case study discusses the recently conducted DST of the HP/HT well by one of the largest global oilfield service providers in collaboration with the operator. The HP/HT environment presented many challenges. The operator initially decided to deploy a permanent packer; however, after comprehensive preoperation planning with the service provider, the decision was made to run a retrievable packer to save time and costs associated with setting and milling/retrieving a permanent packer. The hook-wall concentric bypass, 7-in. retrievable packer was designed and tested for HP/HT environments. It was decided to deploy a full-suite multicycle DST tool string rated to 450°F. To help ensure a higher success rate for the long duration of the test, a clear fluid system of lower weight (14.6 lbm/gal) was used for reliable functioning of the annulus pressure-operated DST tools after a hermetical test and heavy kill mud (15.7 lbm/gal) was used for the well kill operation. Deploying a full suite of annulus pressure-operated, multicycle DST string rated for HP/HT conditions permitted the testing of the well to be performed safely and efficiently without any breach to safety and service quality. The initial cleanup, three-bean study, and downhole buildup were successfully completed. Temperature recorded in this well at the 7-in. retrievable packer depth was 436°F, and the reservoir temperature was extrapolated to approximately 460°F. The reservoir was successfully tested with an annulus pressure-operated multicycle DST string designed to withstand the challenging HP/HT environment. The operation set a new global record, which is the highest recorded bottomhole temperature during DST using the service company's retrievable packer and multicycle DST tools.

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).

While industrial revolution 4.0 transforming the manufacturing industry with the adoption of computers and enhanced with smart and autonomous system that comes with big data and machine learning capability, operators in oil and gas industry also embarked on its evolution, advancing in end-to-end project delivery efficiency through simplification and transformation, with the objective to deliver best-in-class project in a consistent manner. This paper demonstrates a few key changes implemented by Civil, Structural and Offshore Engineering discipline to support the project delivery evolution by referring to a recent wellhead platform project Shell delivered. The principles of simplification and transformation were embraced since the early front end development phase, started from competitive scoping through the development of an intent/requirements-based technical requirements tailored to the project, considered all the key and relevant lessons learnt from respective operator combined with widely referred industry specifications. An intend-based design driven by efficient execution strategy has also shorten the fabrication and installation duration where early Mechanical Completion can be achieved by carefully bringing forward certain scope to front-end loading (FEL) with contractor's commitment to work within a stretched, proper-defined boundaries. Another key change project implemented is through the enhancement in supply chain model that aims to accelerate the delivery schedule. Contractors were empowered and took full accountability under the EPC contract, after alignment of project intent, goals and owner/contractor interest. Cross-organization collaboration between operating units also allow project and/or sub-systems across projects to approach market in a joint campaign, benefits all parties from economy of scale. The ultimate purpose of having efficient project delivery is to drive CAPEX down, enable more marginal fields development become economically feasible. Through the standardization of design requirements and smart replication, this will become the new baseline (in term of cost and schedule) to deliver future standard wellhead platform and transforming wellhead platform delivery to something like block manufacturing industry.

Casing while drilling is seen as a cutting edge technology which enables operators to save time and successfully deliver a well's objective. The reliability of the system often results in the technology to be deployed in challenging environments. In this campaign, operator encountered an unforeseen layer of carbonate (thief zone) during the first well of the campaign which resulted in a change of direction in the well planning and engineering of subsequent 2 wells which were drilled through a dual splitter wellhead system. This paper will discuss on the strategies, challenges and operational steps taken to successfully drill through and cased off the said carbonate formation, by using Directional Casing while Drilling (DCwD) in dual splitter wellhead system. Casing while drilling has shown high reliability in combating top hole section drilling with fluid losses and hole stability issues. However, there are only a handful of cases worldwide where DCwD has been deployed in managing severe losses conditions such as total loss. The presented case took place in a matured development field where severe losses occurred after unexpectedly penetrating a carbonate formation in top hole section which was not experienced in any of the nearby offset wells. To mitigate the wellbore issues, DCwD was utilized for the subsequent wells. Several different approaches were taken in completing both wells in a dual splitter wellhead system. The engineering design, drilling practices, cementing strategies and best practices which were refined over time based on lessons learnt during the campaign will be shared in this paper. This information is coupled with analysis and reasoning behind each procedure that were used to complete these wells. Both wells were successfully drilled and cased off, with less time spent to combat formation related challenges compared to conventional drilling. Intended top of cement in the annulus was achieved by improving the cementing strategy which minimizes time and cost to seal the thief zone. A few new challenges emerged during the execution and these challenges are discussed and addressed in this paper. Even though there are numerous challenges in completing both wells, it can be concluded that DCwD is a viable technology in helping to mitigate wellbore issues (total loss carbonate section). The change of strategies to deploy DCwD has proven to be viable with 2 wells successfully drilled and cased off under splitter wellhead system. The concept, challenges and best practices presented in this paper will help to provide valuable reference as well as a guideline for future similar operations.

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.

In today's business paradigm, early monetization of resources is a key competitive edge. This requires an effective development plan fostered via sound cost-benefit analysis followed by the systematic and timely implementation of said plan. The drive to obtain faster oil has led to a comprehensive collaboration between PETRONAS and PSC Contractors in one of its biggest oil fields. Daisy Field is situated 170km off the coast of Terengganu, Malaysia and the first oil was discovered in 1991. The field reached its peak production in 1999 (90,000 bopd) and has undergone steep decline since then, with current average production of ~25,000 bopd. Using extensive historical surveillance and production data, an initiative was taken to identify and unlock remaining reserves. A new approach to an existing engineering technique called Locating the Remaining Oil (LTRO) has been applied in Daisy Field as an alternative to time consuming static-dynamic modelling. This new approach integrates cased hole log information, production data and decline curve analysis in order to identify bypassed or undrained oil that can be monetized through behind casing or infill drilling. This paper is a case study on the utilisation of LTRO for brownfield rejuvenation. LTRO is a low-cost but effective solution for idle well reactivation; it may accelerate identification of opportunities, which could be exploitable even during low oil prices, as prevailing currently. Following its deployment within the collaboration, reserves addition has been realized, value created and the cycle time for brown field development plan approval was reduced significantly. This paper will also demonstrate how integrated collaboration between host government, operator and service provider can be a good synergy for effective brownfield rejuvenation.

Human Factor Engineering (HFE) addresses interactions in the work environment between people, a facility and its management. FLNG projects bring new HFE challenges with more equipment items that are often larger and often more sophisticated than previously deployed offshore. Deployment of HFE is most cost efficient when started in the early design stages. Timely application of HFE can bring many benefits such as: Designing to allow operation and maintenance throughout the facility’s life considering every single task requiring handling of mechanical components and verification of the FLNG operation and maintenance teams’ resources. Holistic material handling system design Better construction planning This paper will present the findings and lessons learned from engineering and construction of recent offshore LNG facilities by TechnipFMC. The perspective of operation and maintenance teams is considered in the HFE process to ensure that experiences and needs are incorporated in the new design. The findings and lessons learned are summarized under keywords for further discussion and recommendation. Codes, standards and guidelines that are relevant to HFE and material handling are discussed to establish if there is adequate coverage of the requirements for the design, construction and operation of FLNG. Although the discussions of human factors are based on case studies from offshore facilities such as FLNG and large gas processing platforms, the observations and recommendations could be extended to other types of oil and gas facilities.