Distributed temperature (DTS) and distributed acoustic (DAS) fibre optic sensing are now commonly used as key reservoir surveillance tools. This work shows the benefit of continuous downhole monitoring during the lifetime of a well. Fibre optic cables were permanently installed in a doublet injector/monitor well system as part of a CO 2 controlled released experiment at the In-Situ Laboratory in Western Australia. During the completion and injection operations various planned and unplanned events (mud circulation, cementing, drilling, wireline logging, gas and water flows) occurred. The events were monitored from surface to reservoir with DTS and DAS fibre optic cables. The DTS was recorded continuously data starting during well completion throughout the lifetime of the wells while DAS was recorded at specific points in time, mostly associated with borehole time-lapse seismic acquisitions. For the well completion stage, the interpretation of the DTS dataset acquired during mud circulation provided information about thief zones above the reservoir. During cementing and cement hydration, DTS highlighted areas of large breakouts and confirmed cement in-fill in those intervals. During the drilling of an unexpected cement infill, it provided a unique insight into downhole progression of the drill bit. During the CO 2 injection stage, DTS enabled monitoring the phase behaviour at the injector using distributed temperature data combined with a permanent pressure downhole gauge. At the monitoring well, the injected gas breakthrough was clearly detected at reservoir level within 1.5 day after the start of injection. Moreover, the accumulation of the CO 2 over time was captured accurately at reservoir level for a further 3 days. During an unexpected leak in the casing, gas from the reservoir started entering the monitoring well leading to cyclic release of water and gas at the surface. The DAS dataset enabled to pin-point the exact moment the casing leak occurred while the DTS dataset captured the cyclic nature of water and gas leakage. The sensitivity of the tools and interpretation methods are such that the downhole location of the event can be determined within 1 m and the timing within a few seconds. More importantly, the continuous and distributed recording allowed monitoring the events developing in time over the full length of the well. This work highlights the unique benefit of permanent distributed monitoring using distributed fibre optic sensing during the lifetime of a well. The continuous and distributed recording allowed monitoring events developing in time over the full length of the well and provides direct observations for the different events while providing near-real-time information about downhole processes.

Poor conformance & injectivity sustenance is a major concern of Mangala, Bhagyam & Aishwarya (MBA) fields. The presence of high permeability streaks or thief layers between injection and production wells typically results in pre-mature water breakthrough, high water cut and deficient volumetric sweep. As a result, significant oil volumes in the reservoir may not be contacted by the injection fluid. Another concern is of low VRR (Voidage Replacement Ratio) in some of the layers due to reduced injectivity in those sands. Consequently, it has led to poor recovery from those sands. It is also a growing problem with the polymer deposition taking place in the wellbore particularly Mangala (undergoing full-field polymer flooding), leading to challenging wellbore cleanup operations. Several methods have been used in the past, both mechanical and chemical to improve the treatment fluids during stimulation. In this paper, we introduce a novel technique; Radial Jet Drilling (RJD) for Injection & Conformance Improvement which is practical & effective and has resulted in injection improvement of greater than 100% and at-least 3x sustained treatment result over conventional techniques performed earlier. The technique involves running in hole the RJD deflector shoe on jointed pipe (typically 2-3/8") to the target depth & correlated. This is followed up with high pressure coiled tubing to rig up over the jointed pipe string and perform operations in two steps: Milling to establish Casing exit Jetting to create lateral of desired length (30 to 100m) Both operations require separate runs with different downhole assemblies on coiled tubing. The setup allows the operator to jet with fluid of choice depending upon the geological & well fluid understanding. The selection of depths to create desired laterals depends upon sand thickness, formation dip, sand continuity, well deviation, cement quality & few other factors which shall be discussed in this paper. As a result of the created laterals, the injection fluid experiences low pressure drops and bypasses damaged zones/permeability barriers; which ultimately results in improved injection & conformance leading to better sweep efficiency. The other advantage of the technique is the relatively easy integration of tool with existing infrastructure i.e. small horsepower rigs. This paper will document the physics behind the technique, treatment design considerations and implementation for stimulations performed across the fields using Radial jet drilling. Particular attention is paid to multiple injector well stimulation case studies from these fields, the challenges faced, the solutions implemented, results & inferences drawn using post job surveillance. The results observed across the field w.r.t injection & its sustenance performance is consistently greater over conventional methods used earlier.

Banyu Urip, which is the highest producing oil facility in Indonesia with 220 kbd, generates up to 40 MW electrical power to maintain production. Any power blackout results in significant production upset including high flaring. This is exacerbated by usually extended recovery time post power blackout due to complex electrical distribution system. The Banyu Urip facility has experienced production loss due to historical power blackout events, most recently in 2019. This paper provides a case study on optimizing load shedding and gas turbine fuel control system, which could serve as learning for other power generation facilities in various industries for designing a robust blackout prevention system. An integrated blackout prevention system comprises of Electrical Control and Monitoring System (ECMS) as primary load shedding, Gas Turbine Generator (GTG) temperature peaking control, and backup load shedding by under-frequency protection relay is designed. All these load shedding layer of protection cover multiple blackout prevention scenarios or protection system element failure such as GTG trip, overloading, and ECMS failure. Multiple parameter analysis and simulation were performed to determine characteristic of each protection layer. Turbine exhaust temperature response, load, fuel supply, as well as generator frequency are all taken into consideration for the integration of blackout protection layer. Key factor for the seamless integration is timeline of each element to work and for backup element to activate. All must be done within GTG overload capability corridor. ECMS load shedding system is put as the frontline to prevent overload in case GTG trip. As the backup layer, protective relay will enable under-frequency load shedding upon overload and GTG slowdown. GTG temperature peaking control and under-frequency set point are properly designed to ensure that the under-frequency relay is operating. After implementing these optimizations, load shedding is proven to work very effectively and there has been some GTG trip events without blackout nor significant production impact. Evaluation of system performance continues as Banyu Urip Central Processing Facility (CPF) operates. The results will be critical for reliability improvement as well as production continuity assurance. In other words, this also provides a best practice for blackout mitigation to optimize successful power generation facility operation.

In Production operations, asset performance depends greatly on maximizing the run life of equipment while reducing the cost of maintenance. Often, E&P operators have a reactive approach to field maintenance resulting in uneccessary downtime in logistics, inventory management, diagnosing the issues, and in taking the recommended actions. This can lead to higher operating costs and non-productive time. E&P operators are aggressively looking to increase production with operational efficiency gains. In the unconventional fields, a large number of wells have been drilled and put in production with various artificial lift techniques. Proactive well and field production management requires digital enablement of operations, with no data silos and data flowing seamlessly from the subsurface to the hands of the operator. With huge amounts of data being collected, it is imperative to apply data-driven techniques to gain more insights that can be utilized to better manage production. A data-driven approach can provide huge benefits for organisations holding vast amount of reservoir, production, and facilities data. It could provide insights into non-linear multidimensional relationships between parameters so that the field development is better understood and optimized. It could allow companies using a proactive approach towards field operations and equipment maintenance resulting in additional cost savings. This paper presents case studies in which operators optimized production utilizing edge-driven Industrial Internet of Things (IIoT) solutions. These edge IIoT solutions enable fast-loop control through a combination of physics and data-driven workflows, which empowers the operator to proactively manage their assets and focus attention on potentially problematic wells. The solution’s architectural setup and ability to deliver fast-loop control workflows at the edge enables operators to successfully detect and manage potential issues and ultimately improve well performance. Additionally, this approach reduces the dependency upon domain experts to frequently analyze data. The high-frequency data capturing resulted in predicting equipment performance with confidence and allowing remote well management to reduce health, safety, and environment (HSE) risks while decreasing logistics and maintenance costs.

Gas hydrates are ice-like crystals formed by gas and water molecules under low temperature and high-pressure conditions. Avoiding the formation of hydrate plugs is one of the critical tasks that continuously challenges oil and gas operators, especially as oil and gas operations move into deepwater reserves. Common mitigation measures for hydrate formation and plugging include the traditional control methods of injecting thermodynamic inhibitor that assure the operational conditions are outside the hydrate risk region. However, inhibitor injection rates are typically designed based on the worst operating conditions (i.e., maximum pressure and minimum temperature) with significant safety margin. During transient operation such as well start-up, the risk of hydrate formation is higher compared to normal operation and requires significant volume of hydrate inhibitor. This paper presents two case studies that integrate field experience into design to optimize design scenarios for hydrate prevention during gas-condensate well start-up. The first case study shows how the shutdown and start-up scenarios typically considered for design are benchmarked with historical data to avoid unrealistic over-conservatism when creating design scenarios for well start-up. By benchmarking with historical data, the MEG injection rate is able to be reduced by 30%, which in turn increases economic feasibility of the offshore gas-condensate field development. In the second case study, the hydrate inhibitor rate was reduced by 50% by adopting current field practice into design and using state-of-the-art hydrate kinetic modelling to determine the likelihood of hydrate formation and the transportability of hydrates in flowlines. Combining field experience into design reduces constraint to the hydrate inhibitor distribution system, optimizes usage of topside facilities and aids in the development of hydrate management strategy for the field as a whole.

Online pipeline management systems provide real-time and look-ahead functionality for production networks. However, they are limited by a dearth of data to inform their predictions. This represents a barrier to a true, high-fidelity ‘digital twin’ where greater integration with new sensor technologies is needed to bound model predictions and improve their reliability. In this work, we present a novel MEG (Mono-ethylene glycol) sensing system from OneSubsea, the AquaWatcher v2.0, and validate it in our newly-constructed HyJump flowloop. The HyJump flowloop has a unique subsea jumper-like geometry, with three low points and two high points and is equipped with a MEG sensor - mounted on the second low point. The sensor features an open-ended microwave frequency probe mounted flush to the pipe wall which measures the apparent permittivities of the liquid phases in the vicinity of the probe tip. It can determine the MEG concentration or water salinity by processing the measured permittivities, and has further shown that it may be able to detect hydrate deposition. Experimental work was performed to test the performance of this novel equipment while enabling a more accurate calculation of the overall mass balance in the flowloop. An experimental campaign was conducted where, in each measurement, the jumper low points were loaded with aqueous solutions of MEG at mass fractions between 10 and 30 wt%. The entire loop was then pressurized with Perth city natural gas to 1200 psi. The pipe wall temperature was controlled with a cooling jacket in the range of 25.2 °F to 35.6 °F. These conditions simulate transient shut-down and restart operations with a high probability of hydrate formation. Results illustrate that the MEG content readings measured by the sensor were consistently accurate within a 5% relative deviation with respect to the nominal values. Further, flow restrictions due to hydrate deposition were assessed in their severity through differential pressure measurements, where it was observed that the measured MEG content oscillates significantly during hydrate sloughing-type events. The HyJump flowloop facility offers a unique testbed for new subsea sensors, enabling performance evaluations with internal fluids at subsea conditions. The deployment of these novel sensors in the field will both improve the performance of integrated pipeline management solutions and assist operators in optimizing MEG injection dosages to enable higher fidelity hydrate management in subsea pipelines.

HTB underground gas storage (UGS) is a gas storage facility rebuilt from a depleted gas reservoir. It is located in Changji Xinjiang Province, in northwestern China. With designed working gas volume 45×10 8 m 3 and peak working rate 27×10 6 m 3 per day, HTB UGS is the biggest UGS constructed in China. Since commissioning in June 2013, HTB UGS has been injecting gas 113.8×10 8 m 3 , and withdrawing gas 78.2×10 8 m 3 until now. In order to analyze its production performance after 7 years operations, we figured out a systematic analysis method. First of all, we built a production database for HTB UGS, collecting daily injection-production data, tubing pressure, and kinds of testing data of the storage. Also, we built a database for all 30 injection-production wells recording their geologic information, drilling information, gas injection-production information, etc. Based on detailed data, we analyzed the operating characteristics of the HTB UGS from 6 aspects: injection-production gas volume, liquid production volume, operating pressure, reservoir connectivity laterally and vertically, sealing of the trap and well-patten spacing. It shows that 1) gas injection and production volume of the storage increases year by year, accounting for 20% working gas volume of UGS in China. 2) Oil and water production are relatively low. The gas is becoming more and more like dry gas. 3) The operating pressure during gas injection almost reaches maximum allowable storage pressure (34 MPa); while during gas withdrawal it reaches 26 MPa, far above the minimum storage pressure (18 MPa). 4) Overall reservoir connectivity is good in the lateral direction and it is disconnected in the vertical direction between E 1-2 z 2 1 and E 1-2 z 2 2 . 5) The storage is well-sealed and there is no gas leakage. 6) The well-patten covers 80% of the gas storage. To sum up, HTB UGS works well generally from 2013 to 2020, playing an increasingly significant role in summer and winter seasons in China. However, in order to guarantee gas withdrawal in limited time (120 days in winter time in China), well pattern infilling is still needed in layer E 1-2 z 2 2 . The construction of UGS in China started in 1999. At present, 27 gas storage facilities have been built and it is planned to build another 23 to generate more than 400×10 8 m 3 working gas volume by the end of 2030. However, a systematic performance analysis method for UGS has not been applied. This paper will offer the reference for production performance analysis of UGS.

The focus on digitalization and how to reap the benefits from it, is increasing in the oil and gas industry. To make this happen subsea by using machine learning and neural networks on mechanical products, we need to understand how we can digitize them. In this paper we will show how we can generate a true digital twin that could enable the step change in how we monitor and understand the mechanical products placed out of reach for normal preventive maintenance. We look at the industry’s current information philosophy regarding mechanical products; from idea to development and testing to installation and operation. Where the products are currently designed to end up with a nominal 3D model, test components and the verification that they are fit for purpose is made through a test scope simulating certain scenarios defined by the industry. The products are then installed, and their condition is assumed to be fine until evidence of the opposite is apparent, and the time window to perform mitigative intervention is gone. Creating true digital twins of mechanical products will require more data. In recent tests we have focused on generating data points to understand the response/behaviour of the products in multiple scenarios and utilized this data to describe the behaviour accurately and numerically; from this we can generate a digital representation of what state the products are in. The results are based on recent work in developing a digital twin for mechanical products. In this work we have proven through documented testing and quantitative analysis that we can generate a validated numerical model for mechanical products. This will form the basis for understanding the state of the products and predict when intervention/maintenance is imminent for the operator. Using this model and method, condition monitoring of the mechanical products can now be enabled with relative few datapoints extracted in time intervals, and through the use of its numerical representation, establish an actual condition history of the product itself. Further this model would enable a deeper understanding of the actual operational effects, to which the product is exposed during its lifetime, leading to more precise and cost-efficient industry requirements and system knowledge.

The operator, rig contractor and services company formed a trilateral collaboration to plan the safe plug and abandonment of four onshore wells located in a densely populated region of Indonesia. These wells, located in scattered locations, posed a significant logistical challenge for project mobilization and moves between the wells. Well information was incomplete due to a change in asset ownership. Some of the challenges faced in these wells were: Well integrity issues resulting from the presence of H 2 S and CO 2 Sustained casing pressure Surface water safety Fluid losses Personnel safety and future well integrity was crucial to this operation. Consequently, plans were developed to conduct the operation safely and efficiently, as well as to provide solutions that mitigated well integrity challenges. The method adopted for this project was to approach this as an integrated project where the collaboration team was responsible for planning, executing, monitoring and closing out all segments of the project. Well information from the previous field operator was analyzed and a solution to safely plug and abandon these wells was created. Because inadequate well information posed a major challenge, the collaboration team planned multiple contingencies. An abandon-the well-on-paper (AWOP) workshop was organized to review and refine the execution plan. An intelligent coiled tubing system, which could be used for simultaneous logging and pumping operations, was selected as well as an efficient and environmentally friendly mechanical pipe cutter that did not use explosives or hazardous chemical substances for tubing severance operations. The sustained casing pressure challenges (in previously fully cemented/non sealing annuli) were addressed by using advanced milling technology for section milling. The early engagement plan enabled development of a project execution strategy that clearly outlined equipment mobilization schedules from various locations in Indonesia. Because of the collaborative projects structure, local personnel recruited for this project were quickly on boarded and integrated with the rest of the project team. This approach led to the safe and efficient execution of the plug-and-abandonment scope of work, with zero HS&E incidents and 167 perfect HS&E days during project execution. Extensive testing of cement mix water was introduced to this project. The testing improved the cement design and enabled accurate plan transition times that reduced waiting on cement. Based on lessons learnt from the first well, extensive logging operations were performed to determine the formation temperature and specific leak locations in the casing. These pre-cementing logging operations helped in collecting accurate well temperature and pressure information that aided the design of cement recipes for the barriers placed in these wells.

Surveillance of well work-overs and downhole operations is not trivial but is becoming increasingly feasible with recent improvements in the technology of fibre optics. Well cementing operations are critical for providing zonal isolation over the life of a well. However, there are limited downhole options to monitor and inform operations in real-time. Installing a permanent fibre optic cable enables surface to reservoir permanent surveillance. In this work, fibre optic cables were deployed in 4 different wells using different configurations and test passive and active distributed temperature sensing (DTS) setups to interpret the quality of the cement injection and hydration processes. Well cementing can occur during well installation and decommissioning. For 3 wells, fibre optic sensing cables were installed for the purpose of monitoring the casing cementing installation, detect zones of isolation and any background lateral flow in the formation. For one of the well, fibre optic cables were installed inside casing to monitor a full wellbore decommissioning cementing operation. Following the same process, datasets were acquired prior to and during cement injection. Dataset acquired during mud circulation highlights interval of thief zones and potential leakage zones for the cement into the formation. The real-time surveillance of cement injection informs about the top of cement but also the in-fill of breakout intervals and the blockage of thief zones. The long-term surveillance of the vertical temperature distribution enabled to determine the timing and intensity of the cement hydration process and provided a unique insight on the quality of the cementing operations and its possible correlation to breakout intervals and thief zones. Active DTS was also used to confirm the completion installation as temperature diffuses differently depending on the presence or absence of gravel pack and the thickness of the cement sheath. Our results show that downhole surveillance of cementing operations is possible using DTS. This technology enables high vertical accuracy in real-time and long-term surveillance providing insights on the quality of the cement bond. In this case study, DTS has proven to be a very valuable and reliable tool throughout the cementing operations at 4 wells.

Design, evaluation and approval of a field development plan is generally very iterative, requiring meetings, design and execution of simulation models, then financial reviews, back to updating and running the models, then financial evaluations again, and on and on. This paper presents a system (tools and processes) designed to significantly reduce the iterations of simulation runs and financial reviews. This is accomplished through implementing financial logic directly inside the model. This novel ability assesses and controls individual well operations every time step, eliminating the need to modify (and rerun) a model after every run due to financial review indicating a well is losing money and needs to be shut in or modified. Even with the simple model presented, with 23 wells, at least one new iteration would be required every time post run financial analysis indicates a well's operation needs modification due to its financial performance. This would require a minimum of 23 additional runs because changing a well will also impact the performance of other nearby wells. The system presented also provides the flexibility to configure multiple parameters into the model, enabling the automatic execution of multiple combinations of operational and financial scenarios. Such a capability enables the rapid analysis and review of parameter impacts resulting in the confidant selection of the best operating for the organization. The impact of financial realities is demonstrated through the simulation of operating five different field scenarios, each with its own combination of producers and injectors. A variety of operational and financial parameters were included. The results indicate that including financial parameters and decisions inside the simulation run significantly improves the usefulness of the production forecast and provides considerable efficiencies in the modeling and analysis processes.

The Gorgon gas plant produces 15.6 Million Tonnes per Annum (MTPA) Liquified Natural Gas (LNG) from the Gorgon and Jansz-Io subsea gas fields. First LNG production commenced on the Barrow Island, Australia facility in 2016. One of the first systems commissioned was the wastewater treatment, collection and disposal system, a critical support utility for production operations. The Produced Water Disposal (PWD) facility is unique on Barrow Island due the location's national nature reserve status, and all treated waste must be disposed downhole. The objective of this paper is to review key lessons from design, startup and steady state operations. Perspectives will be given on facility/well management and production operations of PWD at the Gorgon plant. Wastewater on Barrow Island is generated from several sources: Condensed water originating from hydrocarbon gas (separated at gas dehydration and Mono-Ethylene Glycol (MEG) regeneration facilities), drainage and runoff water from the plant, treated sewage effluent and other ad hoc liquid waste. These sources are collected and treated before the final product is pumped into two available onshore disposal wells. One of the challenges initially faced was that the disposal water quality did not meet the design specification required to maintain well performance. This problem reduced as the plant reached steady state operations and the team gained a better understanding of well performance over time. Other current challenges include hydrocarbon carryover and water polishing, so Engineering and Operations work together closely to ensure reliable water disposal and hence LNG production. This case study will explore the success and lessons learnt in Gorgon PWD through a summary of field data, facility descriptions and experiences. An overview of the design will be given along with photographs of key components. The required design performance will be compared against actual operating data. In the new energy landscape, the Upstream Operators' social license to operate centers around our environmental performance. In our work we demonstrate that it is possible to treat and dispose of waste liquids responsibly while generating cashflow through LNG production.

An innovative digital solution to transform pipe fit-up operations had been developed. It relies on an algorithm providing a full batch of pipes compatibility analysis, and a smartphone app to be used in full autonomy by welding staff providing live fit-up outcomes. This results in optimized welding assembly operations. Providing pipe-end dimensional measurement and using pipe-end identification technology, the algorithm provides a deterministic analysis of the data to accurately predict the Hi-Lo resulting from all possible pipe-end combinations and then anticipate operational constraints. The developed app provides tailored recommendations to mitigate risks associated with Hi-Lo specification compliance (such as grouping, quarantine management or non-compatibilities identification) considering operational constraints such as quarantine capacity, welding line cycle time or even accessibility. During welding operations, no sequencing is required. By scanning two random pipes intended to be welded together, a smartphone app provides live recommendations on the pipe rotations to respect welding requirements. The solution also includes quarantine management, displaying real-time notifications to reintroduce pipes that have been segregated due to limited compatibility. This results in secured line pipe assembly workflow, improved weld quality and production time reduction. Innovation lies into bringing full autonomy: in the field, the solution is a simple mobile app to be used by the existing personnel. No additional workforce on-board is required. Additionally, compared to existing solutions, the developed tool brings a deterministic analysis instead of a probabilistic one, and does not require sequencing - thus removing the need for extensive pipe handling.

PWC is now a field proven method for restoring cemented isolation in casing annuli and has been successfully applied to casing exit repairs, zonal isolations as well as side-track and permanent abandonments. It is a viable alternative to section milling or cutting and pulling casing, with field history also demonstrating that it offers more reliable results than simple ‘perf and squeeze’. It is now accepted in many regulatory locations and is used by a large number of major operators around the world, but it is important to understand the limits of its application. This paper focuses on illustrating the application envelope for PWC in well abandonment. It will examine the trade-off of service costs versus saved duration, highlighting where a low rig spread rate may drive a decision towards choosing an alternative conventional approach. Furthermore, the paper features and discusses the well parameters such as casing sizes, hole angle, rig capability and annulus content which are key parameters when designing a PWC operation. Operators and Service Companies have undertaken a large portfolio of Computational Fluid Dynamic (CFD) modelling of PWC operations and more than 70 operations have been subjected to verification by cement quality logging. The paper considers the options for PWC barrier verification and shares when and how CFD and historical cement quality logs from the track record to date has been used to provide confidence in, and verification of, subsequent operations.

A 7-in. single-trip multizone (STMZ) gravel pack system was installed successfully in two wells in the T field, Sarawak offshore. This paper highlights the system performance and knowledge obtained during this first-time installation performed in Malaysia. The most common sand control techniques established in the H, I, and J sands of this mature field include stacked gravel pack, 9 5/8-in. single-trip multizone gravel pack, and openhole standalone sand screen (OHSAS) systems. Internal gravel pack completions have provided proven, robust sand control for the sand-prone reservoirs in the T field and can save four to five days of rig time depending on the well configuration, compared with the standard stacked gravel pack completion, which was initially planned during the field development plan (FDP) stage. This paper presents the extensive technical works performed post-FDP approval to ensure the change from the 7-in. stacked gravel pack to the 7-in. single-trip multizone gravel pack completion was executed safely and efficiently and most importantly able to maximize the recoverable reserves from the multiple unconsolidated reservoirs. The technical challenges, such as unexpected drilling of additional zones, limited annulus clearance between the 7-in. liner and gravel pack tool string to reverse out proppant efficiently, intersands spacing, and gross sand interval constraints within certain tolerance because of bottomhole assembly (BHA) limitations, are also discussed. The 7-in. single-trip multizone gravel pack installation helped reduce rig time and provided a cost savings of nearly USD 1.1 million. Subsequently, the two oil-producing (OP) wells (two OP wells and four OP strings) are producing sand-free at higher than expected reserve and flow rates.

The super-giant field under study is one of largest oil producers in Middle East and been producing for more than 50 years from a multilayered carbonate reservoir. Long-term sustainability of production of the field is a key mission for the field operator and national oil company, considering both productivity and recovery of the field. Gas lift has been considered as an effective and economically feasible method to increase production of the wells and as a solution to revive the closed wells and to maintain the production of flowing wells. Prior to full field implementation, a gas lift pilot has been initiated in the field. The objective of the pilot is to collect further essential information and evaluate the challenges prior to the full field implementation. At the well scale, managing the well lift rate allocation, monitoring the performance of gas lift valves and running diagnostics, and optimizing the production rate are the main challenges for the gas lift pilot. At the full field network level, the backpressures of the lifted wells are affecting the production of the other wells producing naturally. A commercial three-phase flow simulator was used to build the well models as well as the pilot network, with certain boundary conditions to develop a scalable solution to enable the operations and headquarters teams to provide a timely solution to the mentioned challenges. To integrate all inputs from various disciplines, the information from the monitoring activities and from reservoir saturation and production logging tools in addition to well test data and gas lift surveys was used to develop the solution. The gas lift management solution was evaluated in the pilot area to diagnose the gas lift valves, validate well tests, optimize gas lift allocation, enhance well production, and perform field-wide production optimization The solution also reveals gas lift candidate wells with the potential to increase the production and directs redistribution of the lift gas in the pilot area to minimize gas utilization. Additionally, to introduce scalable solution which can be utilized at very large wells count, automation of the workflow process has been considered to provide efficiency for engineers which will get advise from the solution.

A successful cement job is a crucial element of obtaining and maintaining well integrity and ensuring safe and efficient hydrocarbon production. The success of cementation starts with a full understanding of good parameters such as formation characteristics and depends on a properly designed slurry and spacer system. The most challenging part of cementing a wellbore is cementing one with a low fracture gradient. There's a high risk of formation breakdowns and hole instability if maximum allowable equivalent circulation densities (ECDs) are exceeded. In addition to severe losses and formation damage, the outcome includes inefficient placement of the cement that warrants time-consuming and costly operations to assure zonal isolation. In Kuwait, first trial of a new generation of an environmentally friendly enhanced aqueous spacer system was used successfully in a highly deviated well for cementing the production casing covering shale formations. This paper discusses the design of the enhanced aqueous system and its technical features and benefits, which helped improve the cement bond and achieve zonal isolation.

In the drive for remote operations, reducing operator costs and reducing emissions and CO2, digitalization of sensors and control systems is imperative. To date, valves on wellheads and trees have predominantly been controlled by hydraulic actuators that are not ideally suited for fully remote operations. A new, innovative, electric actuator has been developed under a Joint Industry Project (JIP) by Equinor, Baker Hughes and TECHNI. This actuator is designed for fail-safe, critical operations offshore and is subject to stringent safety design requirements. The key motivation is reducing CAPEX and OPEX for offshore installations, while increasing availability of wells while providing improved monitoring and condition based, predictive maintenance. The electric actuator that was developed in the program has a patent pending fail-safe mechanism with extremely fast closing time (less than 1 second) to ensure well containment during critical situations. The actuator is designed to be a drop-in replacement for NoBolt™ CHA actuator solutions and is suitable for most standard wellhead and tree designs, sizes and pressure ratings. In the new all-electric design, a multitude of sensors in combination with an OPC-UA architecture, enables data-driven insights from the systems in operation. The program was started in 2017 and has resulted in a system at Technology Readiness Level (TRL) 4 (on 0 to 7 scale) with TRL 5 testing planned in 2020 yielding it ready for field installation.

This paper will discuss a past Hydraulic Analysis Limited (HAL) project and the challenges of commissioning a Water Injection (WI) system. The paper will demonstrate how the use of an accurate pipeline simulator which models the full control system can reduce both commissioning time and risk by identifying issues early. The simulator can then be used to modify and tune the control systems prior to and during commissioning. A computer simulator of a Water Injection system on a Floating Production Storage and Offloading (FPSO) vessel was constructed, including all pipework, pumps and control systems. The simulator was initially used for a design based hydraulic and surge analysis study. During commissioning, the simulator was updated with as-built information and was then used as a commissioning support tool to tune and optimise the various control systems prior to commissioning. All commissioning tests were simulated and assessed before being carried out so that potential issues could be identified and resolved using the simulator. The simulator identified a number of unforeseen issues associated with the start-up of the hydraulic systems. If these issues had not been identified early then there would have been significant delays to the project. The number of hours expended during commissioning was significantly lower than expected with little ‘fire-fighting’ of problems. The simulator was used on a daily basis to check every commissioning activity via a morning web conference meeting and screen share to run through the simulation results and show the expected pressure and flow readings for that days tests. The expected pressure and flow readings could then be compared to the actual readings during the commissioning tests, ensuring a high level of confidence. By comparing the simulator output to the actual site pressure and flow readings, any unexpected system response was rapidly identified and the system was safely shutdown prior to unacceptable operating conditions occurring. The cause of the problem was then identified and resolved through modifications to the FPSO control systems.

Objectives/Scope This paper covers the Shwe Offshore Platform (SHP) MEG Regeneration System upgrade works implemented to reduce excessive MEG losses and improve operation of the System. Methods, Procedures, Process The SHP MEG Regeneration System processes MEG used in the topsides for hydrate inhibition in the Low Temperature Separators (LTS) and at the four subsea wells. Since start-up of production in 2013, SHP has suffered from excessive MEG losses and operational difficulties. Later in the field life, MEG injection to subsea wells was discontinued due to contamination with salts from formation water, and Kinetic Hydrate Inhibitor (KHI) injection was introduced. Extensive evaluation of data, laboratory tests and field trials were carried out to investigate the causes of the excessive MEG consumption and operational difficulties. The upgrade of the MEG Regeneration System was finally completed and put in service since May 2018. Results, Observations, Conclusions The followings have been identified as the direct causes for MEG losses and operational difficulties; Poor efficiency of Glycol-Glycol Heat Exchangers (HEXs), causing low operating temperature of the Rich MEG Flash Drum and poor condensate/Rich MEG separation, resulting in MEG losses via Flash Drum condensate outlet. Excessive condensate in the Rich MEG reaching the Reboiler and resulting in contamination of the Lean MEG and downstream section (injection spray bars). Low water loading in the MEG Regeneration System resulting in lack of reflux and MEG losses via Reflux Drum. MEG carryover from LTS to the Export Gas Compressor (EGC) Suction Scrubbers, caused by foaming in the LTSs. In order to resolve the issues above, a number of modifications were implemented. New Glycol-Glycol HEX and a Liquid-Liquid Coalescer Filter were installed to provide better separation of condensate from Rich MEG. Also re-routing of the EGC Suction Scrubbers liquid outlet back to the MEG Regeneration System to recover the carried over MEG. Significant reduction of MEG losses was achieved, in the range of 70%, and overall system performance has improved. The main outcome of such improvement is that the condensate content in Rich MEG has been significantly decreased to below 500ppmV from above 1vol% due to the increase of Rich MEG Operating Temperature in Flash Drum and introduction of the Liquid-Liquid Coalescer Filter. Novel/Additive Information This paper was written to describe the method used for resolving the problems with MEG losses, excessive condensate in the Rich MEG, and MEG carryover. It also explains the data evaluation, preparation, execution, and the results of the MEG Regeneration System Upgrade work.