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Collaborating Authors
Sarawak Shell Berhad
Alternative Solution for Deepwater Shallow Flow Hazard: Case Study from Shell Deepwater Project
Hoe, Yijing (Sabah Shell Petroleum Company Limited) | Heu, Tieng Soon (Sabah Shell Petroleum Company Limited) | Lee, Shan Yik (Sarawak Shell Berhad) | Mohd-Radzi, Razif (Sarawak Shell Berhad) | Yeap, Fabian (Sarawak Shell Berhad) | Edwards, Joseph (Shell USA) | Charan Suri, Chitra (Baker Hughes) | Lo, Rex (Baker Hughes)
Abstract Gas bubbling was observed immediately post top-hole riserless cementation from the subsea conductor and wellhead in Field-A deepwater wells in Phase-1 and Phase-2 development campaigns. This has led to continuous underwater ROV monitoring and gas sampling requirement for structural integrity assessment. Foam cementing was considered but deemed impractical due to high logistical cost and limited regional experience. Conventional gas-tight cement with complex cement blend were attempted in another deepwater campaign with similar challenge but yielded inconclusive results. Traditionally used to remedying lost circulation, thixotropic cement is a cement system where gel strength develops rapidly under static condition. In this case study, the thixotropic property was combined with shortened transition time properties to create a formulation that exhibits both aggressive gel strength development and a quick critical gel strength period post cement placement. However, pumping such cement system in big volume presented inherent risks where cement could prematurely gel up and harden in surface lines. This can potentially lead to CLIP, and in more severe cases, even total well loss. Comprehensive risk assessment including slurry design, sensitivity testing, quality control, and field trial were conducted prior to the execution. Saturated brine-based drilling fluid was utilized during drilling operations to enhance shale inhibition and prevent hole washout. No bubbling was observed in all four wells in campaign after the cementation with thixotropic gas-tight system. Early planning and testing allowed for the successful implementation of this new cement system despite logistical challenges caused by the Covid-19 pandemic. Cement trial mix played a key role for the crew to understand the slurry behavior and access the equipment readiness. The outcome of this case study presents a promising solution for mitigating shallow flow hazard especially in Asia Pacific region where foam cement is not easily accessible.
- Asia (0.68)
- North America > United States (0.15)
- North America > United States > Texas > East Texas Salt Basin > Shell Field (0.98)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 186 > Field A Field > Silurian Tanezzuft Formation (0.98)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation (0.98)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
Enabling Safe Drilling and Completion Operations Through Negative Margin Formations with Managed Pressure Drilling and Wellbore Strengthening
Radzi, Razif Md (Sarawak Shell Berhad) | Wan, Joachim (Sarawak Shell Berhad) | Mathew, Magdeline (Sarawak Shell Berhad)
Abstract While wellbore strengthening techniques have been proven successful in strengthening weak permeable zones to achieve higher fracture gradients, the extent of their effectiveness is variable. This paper discusses an integrated approach where Managed Pressure Drilling (MPD) is incorporated and designed in conjunction with wellbore strengthening strategies to drill wells with formation strength below borehole stability requirements, thus allowing fail-safe outcomes from depleted drilling and completion operations, ultimately reducing the consequence of failure, and simplifying recovery efforts. There are two main benefits of incorporating MPD. First, MPD enables a reduction in the required drilling margin, and this in turn prevents an over-reliance on the effectiveness of wellbore strengthening strategies. Second, MPD provides the ability to reduce downhole pressure, reducing the consequences of unexpected loss circulation events. Mud weight selection was carefully engineered with several factors taken into consideration, including shale inhibition, impact on completion operations, and consequence of MPD system failure. Eight hole sections across four deep-water subsea wells were initially designed to be drilled with wellbore strengthening strategies alone, however, a loss circulation event led to challenging remediation and recovery efforts. Upon incorporating this MPD design, while seven other hole sections were drilled successfully without any loss circulation events, one hole section encountered loss circulation, and this design allowed an instant reduction in surface back pressure to stop the losses, effectively "failing safely". Four lower completion operations were also successfully executed with this design incorporated.
Case Study: Oil Production Optimized With Autonomous Inflow Control Devices Offshore Malaysia
Konopczynski, Michael (Tendeka) | Moradi, Mojtaba (Tendeka) | Krishnan, Thanushya (Sarawak Shell Berhad) | Sandhu, Harwinder (Sarawak Shell Berhad) | Lai, Chin-Lin (Sarawak Shell Berhad)
_ Advanced well completions have proven to be an effective method of moderating gas breakthrough while producing a thin oil rim when placed in a heterogenous, carbonate reservoir. In addition, several studies have proven that the application of autonomous inflow control devices (AICDs) acts as a type of insurance policy against geological and dynamic reservoir uncertainties to reduce the risk and variation in the expected oil production profiles. During 2019 and 2020, Sarawak Shell Berhad conducted development campaigns in the central Luconia province in a thin oil rim carbonate reservoir offshore Sarawak, Malaysia. The horizontal, approximately 6,000-ft development wells were expected to intersect with different geological layers with varying rock properties, resulting in an uneven reservoir influx toward the wellbore. Oil production from these wells was expected to suffer severely from early gas and water breakthrough. To produce the oil rim without the risk of early gas production, global production optimization specialist, Tendeka, incorporated FloSure AICDs in the lower completion design at the reservoir interface along the horizontal section of the wells. As an active flow control device, the technology delivers a variable flow restriction in response to the properties of the fluid entering the wellbore and the rate of flow passing through it to help manage gas coning/cusping risks. The fluid is then lifted to surface with natural in-situ gas lift built into the upper completion. A three-phase development was planned for the field, and to date, two phases have been completed. New-Generation ICD The first AICD completion was installed in Norway in 2008 and widely implemented in the Troll field in 2013 with very encouraging results (SPE 159634). However, its use is relatively new to both the Asia Pacific region and this type of application. Similar to a standard ICD which balances the influx of reservoir fluids, the FloSure AICD will delay the production of unwanted effluents prior to their breakthrough (proactive solution). However, once a breakthrough occurs, the device restricts the production of unwanted effluents with lower viscosity, such as gas (in light oil applications) and both gas and water in viscous oil production (reactive solution) (OTC 30403, OTC 30363, SPE 193718). The device delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through it. Flow enters the device through the nozzle in the top plate of the body. This impacts the disk and spreads radially through the gap between the disk and the top plate, then turns around the top plate and is discharged through several outlet ports in the body (Fig. 1). The overall geometry of the device is critical to its ability to balance these forces effectively and create the desired fluid-dependent pressure drop. Field A employed 7.5-mm AICD valves to match the performance of the devices to the potential well flow rate. The oil, water, and gas viscosities are 0.40 cP, 0.27 cP, and 0.018 cP, respectively, at downhole flow conditions.
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (9 more...)
The Four Pillars for De-Risking Fluid Loss Potential Along Fault Damage Zone: A Framework for Well Designs and Drilling Operations
Chan, A. W. (Shell Global Solution U.K.) | Brem, A. G. (Independent Consultant) | Abd Rahim, M. H. (Sarawak Shell Berhad) | Numpang, A. (Sarawak Shell Berhad) | Chong, S. (Sarawak Shell Berhad)
ABSTRACT: Fluid loss along faults can pose significant operational challenges from drilling & completing wells to maintaining containment during fluid injection. While faults and fractures can be ubiquitous in the subsurface, not all of them pose the same threats to hydrocarbon extraction activities. During a drilling campaign in semi-consolidated deepwater clastics, a generic link between faults, fluid loss events, fluid circulation pressure and the fault strength parameters was established. In order to reduce the risks of fault-induced fluid loss along any proposed well path in future drilling campaigns, we developed and successfully implemented an integrated screening method that incorporates the observed correlation. The de-risking framework includes four elements (Geological, Geometrical, Mechanical and Dynamic considerations): Geological consideration highlighted the lithological influence on fault zone architecture and the confidence level on fault presences; Meanwhile, the placement of a well path relative to fault(s) will affect the exposure to potential leak paths; Thirdly, mechanical threshold of a fault will change the safe operation margin; And lastly, dynamic interaction between fluid and the fault zone during operation can alter fluid loss potential. Our proposed framework provides subsurface geoscientists and well engineers an efficient tool to quickly rank the integrated threats of fault-induced lost circulation to improve well design, optimize drilling and completion strategy along with appropriate level of mitigation and recovery measures. Unlike typical fault stability analyses that are primarily based on static fault zone architecture and/or stress-based slip potential, the integration and incorporation of engineering activities offers the missing link to de -risk and mitigate the threats posed by along fault fluid migration potential. With minor modifications, this framework can be extended for risk assessments related to containments, caprock or seal integrity evaluations related to other activities such as exploration, enhanced oil recovery or carbon capture and sequestration.
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Well Drilling > Well Planning (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (2 more...)
Optimisation of Oil Production with RCP Autonomous Inflow Control Devices in a Field in Offshore Malaysia, A Case Study with Shell Malaysia
Krishnan, Thanushya (Sarawak Shell Berhad) | Sandhu, Harwinder (Sarawak Shell Berhad) | Lai, Chin-Lin (Sarawak Shell Berhad) | Konopczynski, Michael (Tendeka) | Moradi, Mojtaba (Tendeka)
Abstract During 2019 and 2020 the field operator conducted development campaigns in a thin oil rim carbonate reservoir offshore Malaysia. The horizontal development wells were expected to intersect heterogeneous formations with varying properties resulting in an uneven reservoir influx toward the wellbore. Oil production from these wells was expected to suffer severely from an early gas breakthrough. These challenges were recognized to be mitigated by deploying Autonomous Inflow Control Devices (AICDs), installed at reservoir interface along the horizontal section of the wells. The AICDs can manage the reservoir fluid influx entering the wellbore and therefore optimise the well performance. To improve oil production and ultimate recovery, AICDs were incorporated in the lower completion design for the development wells. The Rate Controlled Production (RCP) AICD was chosen for this application. It is an active flow control device, delivering a variable flow restriction in response to the properties of the fluid and the rate of flow passing through it. This paper summarizes the integrated technical learnings from this project. An integrated workflow was followed to design and deliver the AICD applications successfully for the operator in an offshore light oil reservoir with huge uncertainties in remaining oil thickness and reservoir properties. The wells with a horizontal length of ~6000 ft were drilled in a relatively thin oil formation. The well intersected different geological layers with different rock properties. The lower well completions comprised of RCP AICD valves, shrouded with debris filter screens with an in-situ gas lift system in the upper completions helping to lift the fluids to the surface. The wells were segmented into compartments with blank joints and swell packers and tailored AICD placements based on individual well's real-time log data to properly restrict the production of unwanted fluids. Through teamwork between the companies, the wells were successfully completed with AICDs. The final modelling was performed just in the time span between reaching target depth and running the completion. Over two years of production, the wells completed with AICD not only have not seen any problem in terms of solid production, but they have also successfully exhibited limited GOR development which enabled oil production optimization. A PLT was also run recently in one of the wells to analyze further the zonal contribution of each section of the well and how AICD has effectively choked back the gas in selective zones. The results show that the AICD completion ensured a balanced contribution from the entire 6000 ft long horizontal section in the well despite the heterogeneity of the carbonate reservoir and has potentially reduced the gas production significantly to enable more optimized oil production within gas offtake limits in the reservoir management plan.
- Asia > Malaysia > Sarawak > South China Sea (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (12 more...)
Optimization of Pipeline Welding Qualification, Production and Effective Field Joint Coating Application
bin Ahamad, Ir. Edment Fashah (Sarawak Shell Berhad) | Ong, Ir. Hock Guan (Sarawak Shell Berhad)
Abstract Over the years, offshore underwater pipelaying has been regarded as complex activities ranging from procurement, manufacturing of mother pipe material, welding procedures, and welders qualification until offshore installation at the lay barge. Each project has different complexities subject to the appointed pipelines installation contractor depending on their preference methods and best practices. This article presents how continuous improvements are being made in recent pipeline installation projects by considering the benefits that were learned from all past project's experiences. Multiple simplifications were conducted recently to gain cost and time reduction while maintaining technical integrity and personal safety requirements. Simplification of WPQT and WQT qualifications with minimum welding test coupons preparation had resulted in significant cost avoidance and reduction of a 66 days from the original plan. The new deployment of the innovative FJC system has significantly improved personnel safety, reduced manpower requirement and resulted in faster application. Few strategies were put in place to minimize the welding repairs and allow concurrent activities to speed up the offshore welding progress. The overall improvement for one of the recent pipelay activities has led to the highest pipelay rate in SMEP with record of – 337 jts/day (10") & 256 jts/day (16") over the campaign and achieved 16 days early completion from the original pipelay campaign schedule.
Delivering Best-In-Class Shallow Water Tender-Assisted Drilling Wellhead Platform, a New Chapter
Michael, Michael (Sarawak Shell Berhad) | Chow, Wan Han (Sarawak Shell Berhad) | Loh, Khian Aik (Sarawak Shell Berhad)
Abstract This paper demonstrates another success story on delivering a new Best-In-Class Tendered Assisted Drilling (TAD) Wellhead Platform. A clear target/goal to achieve project value driver, ie. reduce CAPEX and accelerate project maturation speed. With demonstration of good front-end development work and project delivery strategies set from the beginning of the project, a series of strategic approach to deliver competitive scoping and requirement with the intent of achieving cost saving and minimize fabrication duration by meeting targeted weight reduction for both Topside and Substructures. The ultimate purpose of all these strategic approaches is to develop a set of standard template design and efficient project execution strategy for new TAD Wellhead platform that is replicable in Shell. Civil, Structural and Offshore Engineering discipline in Shell has leveraging past project good practices, lesson learnt and benchmarking against internal and external project to develop a fit-for-purpose design. Initial findings from the benchmarking study indicated at water depth of 143m in Sarawak water, jackets are launch-installed, typically. The continuous improvement exercises aimed to reduce both Topsides and Substructure weight, which eventually creates opportunity for jacket to convert from launch-installed in the initially concept to lift-installed jacket. Some of key successes from this improvement journey includes topside deck level/footprint optimization, optimized topside structural framing and deck leg spacing to have a small work-points from top, elimination of jacket dummy leg thus reduce overall jacket footprint/weight, lean foundation design, e.g. 1 skirt pile per leg etc. However, the key challenge to the lift-installed jacket concept at the water region of 140m remains at jacket lift weight that is limited by the typical heavy lift vessel crane capacity and it requires a stringent weather window limit. Hence, weight management, i.e. set NTE weight on the jacket lift weight is paramount and it needs to be managed from engineering phase all the way to offshore installation. The outcome of the continuous improvement journey showed tremendous satisfying result to save project cost and schedule. With massive reduction of jacket weight (>50%) thus it reduces fabrication schedule, and unlocks provision of yard flexibility that invites more competitive bidding from EPC contractors (especially small fabricator) thus potentially reduce overall EPC cost. The significant improvement in steel quantity reducing overall jacket steel material procurement cost and fabrication cost. Elimination of jacket loadout via skidding facility (for launch type jacket) that further reduces fabrication cost. This is the first lift-installed jacket in Shell Malaysia at this water region. Leveraging on project knowledge and learning, specific technical specifications for L2 TAD Wellhead Platform design and installation aids have been developed in shell, with the intent to standardize and simplify technical requirements.
Corrosion Management of Wet Gas Sour Gas Carbon Steel Pipeline with Corrosion Inhibitor and Mono-Ethylene-Glycol in NACE Region 3
Leow, Chun Ho (Sarawak Shell Berhad) | Ong, Hock Guan (Sarawak Shell Berhad) | Lee, Rachel (Sarawak Shell Berhad) | Khoo, Cheng Ai (Sarawak Shell Berhad)
Abstract This paper will present corrosion management of a wet sour gas carbon steel export pipeline using continuous and batch corrosion inhibitors with mono-ethlene-glycol (MEG) as hydrate mitigation strategy in NACE MR 0175/ ISO 15156 region 3 (severe sour). The wet sour gas carbon steel export pipeline corrosion management via continuous CI and batch inhibitors with closed loop MEG regeneration system is rare worldwide. This is especially challenging when the case study may potentially be the longest wet sour gas, large diameter carbon steel pipeline (approximately 207km × 32 inch) in the world thus far. Pipeline corrosion management and hydrate management aspects when being reviewed holistically, it could provide significant cost savings yet safeguarding the overall technical integrity of the pipeline. The overall corrosion management leverages on Shell's many years of JIP and operating experience in sour service including the pipeline material specification, corrosion management, inspection, and maintenance philosophy. Reliable correlation between reservoir properties and uncertainties severe sour service, flow assurance, chemical behavirous, operating experiences etc were considered to best represent the operating envelope for this wet sour gas carbon steel pipeline. This includes the testing and selection of continuous CI and batch inhibitor, corrosion monitoring, operational pigging, maintenance, and inspection requirements throughout the field life.
- Asia > Middle East > Saudi Arabia (0.28)
- Asia > Malaysia (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Implementation of Key Risk Mitigation Strategies and Learnings Enabling Successful Efficient Execution in Malikai Phase 2 Project Mooring Campaigns
Amurol Jamal, Sharizal bin (Sarawak Shell Berhad) | Hii, Tiing-Poh (Sarawak Shell Berhad) | Ang, Zhili (Sarawak Shell Berhad) | Yip, Kenneth (Sarawak Shell Berhad) | Lim, Tee Bin (Sarawak Shell Berhad)
Abstract Malikai Tension Leg Platform (TLP) being the first TLP in Malaysian waters, was installed in 2016 at a water depth of 500m. The mooring system was designed with tender-assisted drilling (TAD) features to allow for station keeping activities during drilling operations. Malikai Phase 2 is brownfield project to develop six infill wells to be drill using existing well slots available on TLP. To drive project value of replication and standardization, similar TAD vessel was used as per Phase 1 campaign. The project execution strategy emphasizes on the reuse of Phase 1 mooring component to lower the CAPEX and re-certification of the mooring component were done to maintain the integrity of the hardware. Existence of porkmarks and large part of geo-hazard on the Malikai seafloor, remain one of the main challenges to safety pre-lay polyester on the selected routes. Furthermore, due to Covid-19 pandemic the shipment of the polyester ropes was delayed. Improvement was made in the offshore installation methodology with introduction of the direct hook-up methods to eliminate the risk of polyester damaging during pre-laid, eliminate the chain twists issue on ground chain section and that also help in preserving project schedule. The development of innovative contracting and supply chain management strategies such as competitive bidding exercise and leverage on contractor expertise to drive the efficient execution. Virtual working setting is a new way of working in marine assurances due to Covid-19 travel restrictions. This paper will provide a board overview of various aspects of Malikai Phase 2 brownfield development during pandemic condition while highlighting key success factors and lesson learned for future projects.
- Asia > Malaysia (0.29)
- North America > United States (0.28)
- Health & Medicine (1.00)
- Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Deployment of Small Area Exposure Radiography S.A.R Technology to Maximise Multiple Work Fronts in Operating Offshore Facility
Sivarajah, Jothi (Sarawak Shell Berhad) | Hassan, Emran (Sarawak Shell Berhad) | Toh, Jason (Sarawak Shell Berhad) | Lim, Tee Bin (Sarawak Shell Berhad)
Abstract Malikai Phase 2 project is a brownfield infill drilling project consisting of 5 new infill wells with 1 sidetrack scope. These new wells are tied into existing Malikai Tension Leg Platform (TLP) production facilities for offshore processing prior to export. Offshore execution activities were heavily congested with multiple works fronts from Drilling, Mooring, Hook-up Commissioning alongside existing production and maintenance operations of the Malikai facility requiring prioritization via simultaneous operations (SIMOPS) activities. The paper highlights the challenges of conventional radiography for inspection activities post pipework welding, which is usually scheduled within windows of low activities i.e. in the night with lower risk of personnel exposure to possible radiation. Since drilling operations runs 24 hours continuously, it renders almost impossible for conventional radiography inspection activities to take place as required. This paper also describes the benefits with the introduction of SAR technology, the radiation exclusion zone can be set to less than 5 meters, thus allowing the topsides facilities pipework welding to take place concurrent with drilling and operation activities, achieving project success factors of optimized manning requirement and earlier than plan First Oil Date (FOD). Advanced NDT technologies in the market like small area radiography and phased-array ultrasound were evaluated. Considering the piping diameter/wall thickness & material being Stainless Steel/Duplex SS (coarse grain welds – requires more extensive PAUT qualification), the final decision was to use SAR. A demo was conducted onshore with representation from various internal stakeholders. Necessary approvals from local regulatory bodies were obtained to facilitate the use of this technology for offshore assets. The team further evaluated the implementation in our offshore facilities in a HAZID workshop, collaborating with several contractors and asset counterpart to assess the hazards and risks associated with SAR. Results were then compared and used by the execution team to develop procedures suitable for offshore use. The paper compares past experiences of hook-up and commissioning activities using conventional radiography methods. By using SafeRad technology, the project can continue with the topsides' fabrication work simultaneously during drilling instead of conducting the pipework fabrication activities in series after drilling is completed. This allowed project team to be able to continue the fabrication works and subsequent pre-commissioning and commissioning activities whilst drilling in progress. As a result, project is able to liquidate the critical path in hook-up and commissioning activities and ultimately contributed to the project delivering early project ahead (circa 6 months) of the first oil milestone.
- Health & Medicine > Nuclear Medicine (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > East Texas Salt Basin > Shell Field (0.98)
- Africa > Middle East > Libya > Al Wahat District > Sirte Basin > Sabah Field (0.98)