bluuebunny/crossref_metadata_2025 huggingface dataset:
A Successful Attempt to Insert Coiled Tubing Through Parted Production Tubing with a Malfunctioned Downhole Safety Valve to Perform Extralightweight Cement Treatment to Regain Pressure Integrity for Plug and Abandonment
Authors: Yi Jae Seok , Lee Jong Yong , Oh Hyun Jung , Nguyen Tan Khoa , Nguyen Tran Thang , Daohmareeyor Tuanangkoon , Wattanasuwankorn Reawat , Kritsanaphak Kritsana
Published: March 2016

This paper discusses an offshore coiled tubing (CT) application to address a complex well situation and well control issue. Multi-engineering designs and 100% yard testing were used successfully during this campaign.

Parted production tubing was identified some 50 m from the surface. The control line of the downhole safety valve failed and one barrier was lost in the well. This paper describes efforts to regain pressure integrity for a plug and abandonment (P&A) procedure in this live gas well. CT was inserted through the parted production tubing in an attempt to regain pressure integrity.

A carefully planned cement placement strategy was critical to operational success. Key challenges and solutions included the following: Wellhead pressure (WHP), friction, and a highly deviated trajectory affected CT pulling capabilities. Therefore, extra-lightweight cement was used to reduce weight inside the CT.The downhole safety valve failed to close, so the downhole tool was redesigned to help ensure that the tool would not stick.

100% Yard testing for the application was performed to simulate onsite, downhole operations.

Well pressure integrity is a primary priority for global operators. An option to regain pressure integrity was introduced and involved running CT and placing cement into the live well. A combination of multi-engineering designs aided this successful CT campaign. The CT was run through the parted production tubing and the failed downhole safety valve. The well was killed and extra-lightweight cement was successfully placed. The operator was able to regain pressure integrity and perform a P&A procedure. The success of this case study indicated that this procedure could be used for future downhole equipment and tubing failures in live gas wells.
Pushing the Limit of Idle Well Management - A Nationwide Industry Approach
Authors: Mokhtar Shahril , Abu Bakar Samsudin , Wibisono Rahmat , Andika Rizky , Budi Astyo , Narasaiah Suluru
Published: March 2016

In Malaysia, idle wells management has been a constant uphill struggle for most operating companies. Year on year, the end result has shown that number of wells restored are usually lower than the number of wells emerging as idle. In the past, idle wells have also been managed in silo by each operating company which internally for them, it does not portray the actual magnitude of the issue at a nation's level. With 50% of the nation's well inventory are idle and with a locked in potential of 80,000 barrels of oil per day (BOPD), it was essential to implement a major management approach change to mitigate this issue across all the operators.

This paper outlines the master plan rolled out by Malaysia Petroleum Management (MPM); the regulatory body of PETRONAS, across the nation to elevate the focus on the identified challenges that hinders more positive results to be achieved in idle wells management across all Petroleum Arrangement Contractors (PACs) in Malaysia.

Based on a collective analysis, several challenges were identified which have been hindering a more positive result to be obtained from previous initiatives by each operator. These challenges includes work scope prioritization, inefficient resources utilization, poor technical solution, disconnection between wells and surface potential, low economics challenge, weather limitation and lack of collaboration with industry key solution providers.

With the steer and monitoring by MPM, all PACs were able to deliver 60% above target of additional instantaneous production and executed 110% above the restoration planned activities. A parallel effort to reduce the number of emerging idle wells was also executed where the number was reduced by 35%. The overall results have managed to contribute a significant amount additional production for the nation and this new management approach is to be continuously emulated.
Wet Lift as an Alternative Subsea Pipeline Tie-In Method for Marginal Project
Authors: Sahroini Nanang
Published: March 2016

Company developed new APN-E/F gas fields in 2011, namely the APNE-A, APNE-B, and APNF. One of the critical scopes of this project was subsea tie-in work, which was the biggest risk to be managed. This tie-in work was a part of the key success milestones that would affect the overall project completion. There were a lot of constraints and concerns that had to be considered during the execution phase of the engineering, fabrication, and installation work. The wet lift method was chosen after a robust selection process from several options e.g. tie-ins using subsea mechanical connectors, the dry lift and wet lift methods. These options were reviewed against the selection criteria of safety, schedule/shutdown time, cost and quality/integrity for the operation. The wet lift tie-in method for the 24" subsea pipeline was finally selected after being thoroughly assessed by the discipline functions.

The implementation of the wet lift method started with the detailed planning of the resources, material, work sequences and timeline schedules. As a result, the work was safely and reliably executed ahead of schedule.
Innovative Approach of Managing Commercial and Physical Constraints for Complex Gas Network
Authors: Yong H. , Daling R. , Timmerarends B.
Published: March 2016

The Sarawak Integrated Gas Network is one of the largest and arguably most complicated offshore gas networks in the world due to its intricate physical layout comprising of more than 20 fields producing with total capacity of more than 4000 MMscf/d, supplying to 3 LNG plants. As there are various operators in the network operating different Production Sharing Contracts (PSCs) and Gas Sales Agreements (GSA), commercial arrangements are essential to govern the production policy of the network to ensure PSC and GSA obligations and/or entitlements are honoured. Gas quality management by blending of gas is another aspect to be considered as each of the 3 LNG plants have constraints on contaminants such as CO2 and H2S and each field has varying contaminant levels. Integrated Production Systems Model (IPSM) is used extensively for the production forecast of integrated gas networks as pressure interaction via surface network between the different wells have a significant impact on the reservoir performance. However, due to the combination of physical and commercial constraints of the Sarawak Gas Network and the additional complexity due to contaminants management, generic IPSM models are unable to accurately handle both physical and commercial requirements. As such, the traditional workflow for Sarawak Gas Network required a workaround where IPSM models are used in combination with post processing spreadsheet to manually tweak production forecasts in order to honour commercial and gas quality constraints. This was cumbersome and also negated the real benefits of IPSM. The recent rebuild of the Sarawak IPSM model with the Shell proprietary tool, "Hydrocarbon Field Planning Tool" (HFPT), addresses this challenge by incorporating the commercial arrangements within the model. This is made possible as HFPT allows for flexible scripting which enables asset specific functionality to be modeled. The approach is essentially a 2 step approach within HFPT, where field capacity is derived based on physical constraints (as per generic IPSM models) and a second step where production nomination is managed with a series of rules designed to mimic operational practices to align production nomination with commercial arrangements and for gas quality management. The Sarawak HFPT model has been used extensively for Business Planning and resource reporting exercises to ensure the production forecasts are robust and credible. With this novel approach, the revamped Sarawak IPSM model is capable of generating production forecasts which integrates both commercial and physical constraints as well as contaminants management without the need to evaluate the commercial arrangements as a post processing step.
Characterising Coriolis Meters for Use in 3-Phase Flow in Marginal Fields
Authors: Marshall Craig , MacGillivray Alick
Published: March 2016

A significant portion of SE Asia's oil and gas reserves are found in marginal fields containing less than 30 million barrels (bbl) of recoverable oil. The cost of the typical infrastructure to develop these fields can be extremely large which results in some fields being too uneconomical to produce. Instead, some fields are tied-back to already existing infrastructure reducing the requirement for the additional expensive processing equipment. This results in larger production capabilities and more fields becoming economical. However, using this tie-back method requires the produced fluids to be measured and the correct volumes allocated back to the individual wells for both fiscal and ownership applications. As part of the industry standard Measurement Guidelines, the maximum allowable measurement uncertainty for these measurements is often ± 1% (k=2).

For marginal fields the production flowrate is often in the region of 2,000-8,000 bbl/day of oil with expected water cuts starting below 10% and rising to over 50% after several years of production. Owing to limitations in tie-back facilities there are situations where gas break-out in the metering stream can occur (due to insufficient static head). This can result in 3-phase flow through the measurement point which is known to increase the error and uncertainty of measurement. In order to meet the measurement uncertainty requirements a new method has been developed that corrects the mass flow based on live measurement data, PVT models and correction curves generated from a characterisation of the meters.

After a baseline calibration, the meter is then tested in 3-phase flow to give an indication of measurement accuracy and repeatability under these conditions. Correction curves are then generated to correct the meters performance with various quantities of gas and water present. From recent tests, the results from the baseline calibration of the meters showed excellent performance in terms of accuracy and repeatability. During the characterisation tests, large errors were present but these were found to be very repeatable for higher flowrates and corrections could easily be applied. At lower flowrates the Coriolis meters were less repeatable.

This paper will discuss the role of allocation meters in the development of marginal fields and provides a case study on a new method of using single phase flow meters under 3-phase conditions. To the author's knowledge, this method has not been used before and represents a novel use of commercial equipment. The paper will describe the measurement process and discuss the additional sources of uncertainty involved in the process. The paper will end with recommendations for future developments in the region to maximise production and lower costs associated with measurement equipment.
Open Source Architectures Development for Subsea Factory
Authors: Radicioni A. , Fontolan M.
Published: March 2016

The future application of subsea processing technologies envisages subsea production systems with an increased level of functional complexity because of the integration of static and rotating processing equipment like pumps, separators, compressors, scrubbers, heat exchangers.

These systems call for high total system availability not only dependent on individual technologies and associated equipment reliability but also on a set of key drivers which shall govern the overall Subsea System configuration.

The field evolution during its life, due to the modification of the production parameters (like changing in production profiles, increased water production, etc…), together with the need for frequent inspection, maintenance and repair (especially for the rotating equipment) have to be considered when defining the key drivers to be evaluated in view of defining the best subsea factory configuration.

Elements such Interchangeability, Re-Configurability,  Expandability, Installability, Inspectability and Retrievability have to be considered within the key drivers and functional requirements to be evaluated in the development of the subsea system architecture of these systems.

The standardization of modules and sub-modules and the standardization of interfaces among modules and sub-modules with Subsea Production Systems or other facilities shall be a key for the optimization of the subsea processing system vs. installation and Inspection, Maintenance and Repair (IMR) tasks.

Sonsub is active, since many years, in the development of proprietary subsea processing technologies. The proprietary solutions includes the Subsea Gas/Liquid Separation System (Multipipe Separator), Liquid/Liquid Separation System (SpoolSep), and The Sea Water Treatment and Re-Injection System (SPRINGS).

The Sonsub philosophy (Saipem brand name and industrial platform for the Subsea Factory) to optimize the subsea factories configuration is to develop "open sources architectures" through standardized Functional Building Blocks and standardization of the relevant interfaces.

The paper illustrates the "open source architectures" conceived by Sonsub for subsea factories and relevant modularization philosophy, mainly focused to its proprietary technologies. Moreover it also describes the proposed standardization principles to allow the integration of a system independent from any proprietary products or equipment and exclusive interfaces, called SUBSEA BUS.
Pull-In and Lay of Dynamic Umbilical Through Shallow J-Tube With Offset Touch Down Point Into Existing Platform
Authors: Eyssautier S.
Published: March 2016

Bayu-Undan is an existing gas field located North West of Darwin comprising of two main platforms, a satellite platform and an export pipeline to the Darwin LNG facility operated by ConocoPhillips. Phase 3 of the Bayu-Undan development included the lay of two flexible pipelines and one umbilical. The umbilical was installed by a leading seabed-to-surface EPIC contractor utilising a multirole construction and diving support vessel in September 2014, which presented a number of specific challenges: The umbilical system was unusual for the following reasons: ?Free-hanging catenary of umbilical to avoid in-place rigid spools (*)?Shallow water depth of J-tube bellmouth?Umbilical ancillaries that were designed before installation challenges were fully understood?The proximity of J-tube and lay corridor to the flare bridgeDetailed engineering on the following topics was completed to address the installation challenges: ?Installation Analysis of different methods for comparison, using a leading finite element based hydrodynamics simulation software?Design of bespoke stern-mounted horizontal lay spread?Rigging design for product limit conformanceThe following factors influenced a successful offshore campaign: ?Good weather?Smooth deck handling of umbilical?Good interface between vessel and platform team

This paper presents a case study of the engineering and installation activities and provides lessons learnt for the entire operation.

(*) the "dynamic" umbilical will be further refered as "free-hanging" umbilical as, being fixed both ends, it didn't experience any real dynamic behaviour.
Real Time 3D Modeling to Optimize Geosteering in Clastic Reservoir – Case Study
Authors: Bashir Faisal , Al-Hawi Maan , Bhuana Indra , Abbas Mazin , Ghamdi Yasser
Published: March 2016

This case study presents the impact of dynamically updating 3D structural and petrophysical geological models to optimize real-time geosteering through stringer sands with high effective porosities in clastic reservoirs. The depositional environment of siliciclastic reservoirs imposes reservoir development challenges due to heterogeneity within the play system and within each sediment. Historically, stochastic modeling techniques have been used to predict the extent of lithofacies between wells where no hard data exists. Combined with a proper understanding of the depositional environment, stochastic and deterministic modeling techniques (selection of which depends on the availability of well control data) can closely simulate the actual distribution of petrophysical properties and their variance within reservoirs.

Reservoir modeling has been used for reservoir studies and production simulation, historically with cell resolutions as coarse as 100's of meters/feet. Such models used to require hours to update. Today, advancements in modeling software and hardware allow higher resolution models to be updated in minutes. These advancements have triggered new opportunities for modeling, allowing model-centric approaches to be effectively integrated into time-sensitive workflows. Geosteering is one of the evolving reservoir development and drilling frontiers where accurate real-time decisions are required to achieve drilling objectives with minimum cost.

This paper demonstrates a new approach to updating an integrated reservoir model in near real-time, both structurally and petrophysically, to optimally geosteer wells through the most productive zones of the reservoir. The proposed workflow assumes the availability of pre-built geological models populated with at least a porosity attribute. Instead of relying on quick-look effective porosity logs, which are subject to many unknown parameters, we present a new methodology to convert porosity models to gamma ray models which can be more easily correlated with the LWD gamma ray log. This minimizes the number of computational steps required to update the model, resulting in faster model updates.

To further accelerate model update, models were sectored (cropped) around the active well. Sector boundaries need to be carefully selected to honor the influence of adjacent wells during krigging. Smaller models allow increased horizontal and vertical resolution, to approximate the well log resolution, without impacting compute time. This high resolution model is then populated with the full field petrophysical properties and used for geosteering. The paper concludes by summarizing lessons learned using this approach, the pros and cons, and possible areas for future enhancement.
Managing Total Circulation Losses with Pressurized Mud Cap Drilling (PMCD) During Completion: Case History of Practical Solution
Authors: Hajiyeva Madina , Osuji-Bells Godwin A. , Rozlan M. Rizwan , Samuel Orient B. , M. Zulkhairi Zahari , Upadhyay Abhishek , Buch Manish
Published: March 2016

Completing well in a carbonate formation is often a big challenge due to occurrence of severe losses in highly fractured limestone formations. In some cases, total losses might lead to prolonged operation time and/or well abandonment with attendant cost implications. Traditionally, Loss Circulation Materials (LCMs) are used to combat losses before completion operation commences. However, there have been limited success with this approach especially in this case where Karst was encountered.

Originated under Managed Pressure Drilling (MPD) system, Pressurized Mud Cap Drilling (PMCD) with continuous seawater injection was introduced in XT Carbonate Oil Development Project. Due to the subnormal formation pressure, seawater was injected continuously down the annulus to maintain the hydrostatic pressure of the hole while ensuring that no formation fluid or gas entered the well bore. By injecting at a rate higher than the loss rate, an artificially induced surface pressure allows for wellbore monitoring while completion assemblies are being deployed.

Prior to running in Lower Completion, a composite bridge plug was set at deepest possible location in production casing instead of the conventional Downhole Deployment Valve (DDV) resulting in the savings of about USD 1 Million. Some modifications were made on initial completion string whereby a sacrificial motor and a bit were included in Lower Completion string design. With the well in static mode, this modified lower completion string which consists of mud motor, drill bit and pre-drilled liner was used to drill out the bridge plug effortlessly. PMCD mode with continuous sea water injection was activated once the plug has been drilled out and while Lower Completion string was run to Total Depth (TD). After setting the Liner Hanger Packer and closing Fluid Isolation Valve, the well was back to static mode and ready for wellbore cleanup and upper completion runs.

Five (5) high temperature wells have been designed employing the above technique which resulted in significant savings in rig time and cost as well as formation damage reduction and increased operating efficiency. This paper summarizes the practical experiences gained during the planning and deployment of lower completion string with perforated liners in a total losses condition with PMCD .
Successfully Managing NPT in a Deep, Deviated, High-Temperature Interval in Kuwait by Bridging Hole-Enlargement Technology and Drilling Efficiencies
Authors: Elberr Ahmed Sameer , Helmy Hesham , Okorie Onochie M , Stringer Jordan , Muselhi Ahmed , Khattab Sameh , Al-Mutari Bandar , Abdelhafiz Hassan , Kumar Akshaya , Gazi Naz H.
Published: March 2016

Objectives/Scope

With ever increasing well construction challenges associated with lithology, downhole temperatures & pressures, the need for high performance concentric hole enlargement has never been more essential to meet the clients well objectives. Hole Enlargement portrays an area of concern by multiple oil & gas operators due to the challenging nature of enlarging a hole that subjects the tool & string members to aggressive dynamic vibrations especially when combined with thermal stresses and unpredictable lithology.

Methods, Procedures, Process

While drilling a challenging deep development well in Kuwait, the drilling engineers considered enlarging a 2,000 ft 6 inch horizontal interval to 7 inch (17% beyond the bit diameter) to facilitate 5 inch liner being run to TD & mitigate restrictions which have resulted in significant NPT due to a 50% shale & 50% lime stone unstable interval. Drilling that section has encountered multiple issues associated with the high downhole temperature in terms of directional drilling motor failures costing the operator 4 tripping cycles to replace failed tools.

Results, Observations, and Conclusions

Defining a hole enlargement operation using a hydraulically actuated underreamer in such challenging well was supported through an extensive application engineering feasibility study from both the service provider and operator, initiating from an operational risk assessment, hydraulic optimization simulations to ensure maximum cooling and cutting delivery efficiency, Torque & Drag analysis, vibration and critical speed interpretation, stuck pipe simulations to effectively analyze jar placement performance. The underreamer was successfully operated in downhole temperatures exceeding 300 degrees Fahrenheit and the 2000 ft interval was enlarged in 2 trips. Additional PDC cutting structure work-rate modeling was utilized to optimize the positioning of the PDC cutters for an enhanced cutting efficiency in addition to real time field support that provides drilling parameter recommendations for weight on reamer, RPM, & ROP for the entire interval to mitigate additional trips and improve drilling efficiency.

Novel/Additive Information

Enhancing drilling efficiency while managing NPT was the defined objectives for both parties while initially designing a hole enlargement application engineering package. This was successfully implemented and saved the operator 3 days of rig time on the planned drilling time.
Managed Pressure Drilling Application to Deploy Lower Completion Safely and Efficiently in Static-Underbalanced Well
Authors: Agustinus Krisboa , Zein Joydi M. , Irawan Fikri , Wuest Chad
Published: March 2016

Completion phase is critical in well construction where drilling operation is achieved in static-underbalanced condition with water as circulation fluid. With utilization of Managed Pressure Drilling (MPD) equipment that consists of Rotating Control Device (RCD), Automated MPD Choke Manifold, and Downhole Isolation Valve (DIV), lower completion string can be deployed safely and efficiently. MPD technique enables safe and efficient transition after reaching target depth and prior running lower completion. The same technique allows instant and manageable bottom hole pressure upon the completion phase.

This paper emphasizes the main benefits of MPD technique while running lower completion in a gas-rich well in South Sumatra. With static-underbalanced fluid presence while drilling to target depth, transition from drilling to completion phase is very crucial. The presence of DIV eliminates the needs to kill the well with heavier mud and chemical additives prior tripping out drill string to surface. DIV isolates the open-hole formation safely while drill string is pulled out and lower completion string is made up on surface. This result in easier fluid management on surface by keeping fresh water as circulation fluids, while avoids chemical settling to the pay-zone which can lead to well productivity issues.

While running the completion string, prior to reaching DIV depth, RCD bearing assembly is installed to enable closed-loop and pressure-able drilling system. The DIV is then opened securely while MPD Automated Choke Manifold manages the desired bottom hole pressure by adjusting the surface back pressure accordingly. Although the fluid weight in the well is static-underbalanced, the bottom hole pressure is managed to be overbalance at all time. Lower completion string is run to bottom then its hanger and packer set subsequently to have the primary well barrier in place for further production purpose.
South Sabah Synergy
Authors: Sukiman S.
Published: March 2016

South Sabah operations consists of two major players namely PETRONAS Carigali Sdn Bhd (PCSB) and Talisman Malaysia Ltd. (TML) of which both are operating in close proximity and codependent by design. Driven by an innovative Petroleum Arrangement, integration between PCSB and TML is inevitable in pursuing synergy within the South Sabah area. The accomplishments achieved shall be a role model for other operators to emulate.

A formal steering committee, South Sabah Synergy Group (SSSG), consists of senior representatives of PETRONAS, PCSB and TML was established with a role to direct and oversee series of working groups. The coordination was made possible by a Joint Asset Working Group (JAWG) which put forward specific opportunities for deliberation and deliver a comprehensive list of synergies. This was done through identifying all opportunities purely on technical prospects and for each of the opportunity, a preliminary analysis of its potential benefits and risks were done followed by capturing all plans that were essential to its realization. Lastly, the identified opportunities were ranked and assessed based on impact against do-ability and the ones identified as "low hanging fruits" became the main focus area.

A potential savings of USD 30 million to USD 50 million are expected over the Production Sharing Contract (PSC) life. This was evident from two years' worth of achievements (1) spare parts sharing has saved USD 200,000, (2) subsurface data sharing has saved USD 3.0 million on core samples acquisition, (3) sharing of drilling rig mobilization has saved USD 1.4 million and accelerated the project by 30 days. In the mid-term opportunities; (1) logistics sharing will save USD 520,000 a year and increase 50% boat availability, (2) a 5-year integrated planning will optimize production downtime and (3) streamlining emergency response will result in an effective and well-coordinated response. The list goes on beyond current scope and vicinity and further opportunities can be realized within the wider Sabah network.

The key success factor is to streamline the mindset and perspective between all parties to focus on win-win strategy by understanding that the ultimate goal of fulfilling synergy will translate into increasing profitability in the most efficient way.
Low Pressure Production Unit LPPU
Authors: Thiruthonder H. , Jothy A.
Published: March 2016

With soaring global demand, depleting supplies of crude oil coupled with the collapse in the oil prices, maximizing oil production in mature fields has become a priority. Such fields account for over 70% of the world's oil and gas production, with a worldwide average recovery factor of 35% for oil. Main challenge encountered by mature oil fields is the well pressure depletion over time. Since pressure depletion is inevitable, it is particularly challenging to continue to produce as there is insufficient reservoir pressure to push the well fluids to the main processing facilities.

The system discussed in this paper is an effective engineering solution designed for topside receiving facilities. The Low Pressure Production Unit ‘LPPU’ is a separation system for boosting the pressure of production fluids from low pressure wells. It is ideally suited for remote wellhead platforms where wells have insufficient pressure to deliver well fluids to production header, space is a constraint, and manning is not required.

Conceptual design of this system is based on the very low, almost atmospheric, operating pressure of the system, wherein the flow from the well to topside becomes easier without the need to inject the well itself with any foreign elements. The system is designed in such a way that it can receive continuous full flow from the well, and still manages –through intricate isolation methodology- to operate in batches. This batch operation arrangement allows for liquid accumulation which is then discharged to the production header after being pressurized.

System adopts different variations based on availability; it either uses HP gas -typically from existing gas-lift compressor from the main processing platform- or compresses the associated gas from the FWS to be used as ‘motive gas’ which is used to pressurize and push down the accumulated liquid towards the delivery of flow to the production header.

A characteristic optimization factor that contributes greatly to the economic and operational attraction of this system is its ability to utilize its equipment to combine solutions for the two challenges of 1-reduced pressure that's beneficial to the well flow, and 2-the higher pressure essential for the production header.
Straits of Malacca Exploration Campaign - Lessons Learnt and Key to Success
Authors: Yoong William Liew Sin , Azmi Fadzliana , Rahim Azral A , Ghani Syazwan A , Idris M Faisal Rizal , Idris M Ramdan , Ibrahim W M Syazwan W , Rahman Hamdan Abd , Sawal M Rizal , Wan Terrence Lawai
Published: March 2016

Straits of Malacca Exploration Campaign marks PETRONAS' first oil/gas well drilling in the region of West Coast of Peninsular Malaysia. Three (3) exploration wells were drilled in a period of four (4) months. This paper will highlight the challenges, lessons learnt and key to success of this fast track drilling campaign in a new region of operation.

The team which was entrusted with the mission to drive PETRONAS' quest of oil and gas in this new region were then given six (6) months to deliver the first well out of three (3) exploration wells. Apart from the uphill task to set up staging base and logistics support in the West Coast of Peninsular Malaysia, the team faced challenges of drilling in one of the world's busiest shipping lane. Navigational safety is one of the main concern here. Besides, two (2) of the three (3) wells were located close area where sea robberies and hijacking were rampant. In terms of drilling operation, two (2) of the wells were exposed to the risk of total losses. This paper will share the approaches taken by the project team in overcoming challenges in three (3) main areas - (1) logistics; (2) navigational and offshore safety and security; and (3) well engineering.

Although faced with numerous challenges together with limitation of time and resources, the project team has managed to deliver all the three (3) wells successfully, meeting all the geological objectives within Authorisation For Expenditure (AFE) cost. On top of that, the drilling campaign was completed with zero Lost Time Incident (LTI) and zero accident. Another notable success in this project is setting up the modus operandi in a new region of drilling within six (6) months. Due to the fast track nature of this campaign, first of the three (3) wells was spudded concurrently with 3D seismic interpretation by taking the risk of relying on 2D seismic data. Halfway through the well construction, Well #1 (Well A) was re-sanctioned based on the findings while drilling and latest 3D seismic data received. Target depth of the well was revised to 3130m TVDSS from initial 2100m TVDSS. Despite all the challenges, the drilling team managed to complete drilling operation of three (3) wells ahead of time by 11 days in total.

Apart from engineering and logistics challenges, this paper will share the experience of drilling in one of the busiest shipping lanes in the world. Lessons learnt and key success factors of this fast track exploration drilling campaign will be beneficial to all oil and gas (O&G) operators, especially to those planning to operate in the Straits of Malacca or any other similar regions in the world.
Managing Constant Bottom Hole Pressure with Continuous Flow Systems
Authors: Riddoch James , Wuest Chad , Toralde Julmar Shaun S.
Published: March 2016

Managing downhole pressure and temperature is critical, particularly in deepwater, high-pressure, high-temperature (HP/HT), extended reach drilling (ERD), and other challenging operating conditions.

A large percentage of all drilling hazards related to wellbore pressure occur when mud pumps are cycled off and on during connections, causing fluctuations in equivalent circulation densities (ECD) and downhole pressure and temperature spikes. These conditions can result in expensive downtime, safety issues, and the inability to drill a well within extreme scenarios.

Continuous flow system (CFS) technology mitigates the hazards of wellbore pressure drilling even while mud pumps are cycled off and on during connections. Unregulated, these cycles can cause ECD fluctuations and downhole pressure spikes. The system ensures constant bottomhole pressure. This variant of Managed Pressure Drilling (MPD) can reduce expensive downtime, minimize safety issues, and enable safe and efficient drilling in otherwise undrillable wells.

This technology can enable the drilling team to decrease nonproductive time by providing continuous circulation, which improves hole cleaning and maintains ECD.

Test results of the use of a continuous flow system under development reveal that the system can maintain bottomhole pressure constant consistently and continuously.
Driving Malaysia's Drilling Performance Improvement via Regulatory Benchmarking
Authors: Ahmad M. Sabri Haji , Iqbal M. , Nordin Jaafar , Bakar Samsudin Abu
Published: March 2016

This paper outlines the initiative of the Online Drilling Database by Malaysia Petroleum Management (MPM) Drilling team, the regulatory body of PETRONAS, for Petroleum Arrangement Contractors (PACs) to set an accurate Drilling Minimum Standard (DMS) which forms the guideline for costing and well budgeting as well as benchmarking for performance evaluation across all PACs.

MPM Drilling is being the regulator, enabler and shaper of the drilling industry in Malaysia, that has been entrusted to ensure all drilling activities in Malaysia are conducted in the most efficient, safe and cost effective manner. To date, various initiatives have been implemented via workshops, seminars, technical committee, discussions etc.

The latest initiative is to establish an Online Drilling Database for all Malaysian drilling activities which will reside within MPM's Drilling team. With the availability of reliable data, MPM Drilling will be able to set a highly accurate DMS which forms a guideline on costing and well budgeting, as well as a benchmarking tool for performance evaluation.

Drilling analysis will be conducted via third party software to determine the best well that can be emulated by others for performance improvement. The results will also be accessible online via PETRONAS's website for PACs to view their relative position. Due to data confidentially the name of other PACs shall not be revealed.

MPM Drilling from time to time shall assist PACs for improvement by sharing accurate data, benchmarking and lessons learnt, aimed to achieve high efficiency with low Non Productive Time (NPT) drilling operation. The data will also enable PACs to plan for effective contracting strategy by identifying and retaining high performing Third Party Service contractors to minimize non-productive time to achieve lower well cost.

It also aims to be the center of cost improvement for the Malaysian drilling industry to support cost saving objectives by all parties for win-win situation.
Acoustic-Induced Vibration: A New Methodology for Improved Piping Design Practice
Authors: Agar M. , Ancian L.
Published: March 2016

Acoustic Induced Vibration (AIV) refers to the high acoustic energy generated by pressure-reducing devices that excite pipe shell vibration modes, producing excessive dynamic stress. Analysis of this risk is an important part of Asset Integrity Management systems as AIV can cause catastrophic piping failure. Existing methodologies address this risk through an analytical assessment. However, these methodologies are not fully known and input parameters are limited. The aim of this paper is to propose an advanced methodology for AIV risk assessment allowing a better understanding of possible mitigation action.

The approach presented for identifying AIV risk is based on a dynamic stress evaluation at pipe discontinuities in order to assess pipe fatigue. Dynamic stress evaluation is performed through a fluid-structure coupling Finite Element Analysis. Pressure fluctuations inside the pipe are predicted and coupled with a pipe structural analysis. This methodology is provided with its validation through measurement on an actual AIV field case, corresponding to a crack initiation due to AIV on an FPSO flare network tail pipe. Piping dynamic behavior and vibration levels on the pipe predicted by this numerical approach are compared to results obtained in the field case study. The comparison shows good agreement between the experimental and computed data, giving confidence in the pertinence of this approach.

The method is then used to quantitatively assess mitigation action efficiency. Existing guidelines are efficient to perform a quick screening of a large number of pipes. However, when it comes to mitigation measures, the limited input parameters used to quantify the Likelihood of Failure restrain from assessing the impact of existing mitigation measures and therefore demonstrating their efficiency. Consequently, the methodology is applied to existing mitigation measures that cannot be quantitatively assessed through existing guidelines such as: the use of sweepolet, forged tee, and full encirclement wrap branch reinforcement. Comparison between computation results with and without mitigation measures make it possible to quantify the impact of such modifications for reducing AIV risk.
Sloshing Reduction Using Floating Mat for Floating LNG Cargo Containment System
Authors: Lee Michael M. S. , Chung Chul , Lee Sang-Gab
Published: March 2016

Every effort has been tried for the reduction of sloshing impact loading to the LNG Cargo Containment System (CCS). And, a new type of floating mat system is recently considered for the further sloshing reduction to mitigate the sloshing impact loading in partial filling of the LNG CCS. In this study, model scale sloshing tests are carried out with partial filled tank heights for the comparison of the reduction effects of a new type of floating mat system on the sloshing induced impact loading, and model scale sloshing simulations, using Multi-Material Arbitrary Lagrangian Eulerian (MMALE) formulation and Fluid-Structure Interaction (FSI) analysis technique of LS-DYNA code. The sloshing response results from model scale sloshing tests are applied to validate the sloshing simulations for the extension of diverse model scale sloshing simulations and full scale ones.
New Method to Reduce Drilling Survey Time, Cost and Risk for Wells Drilled Offshore Malaysia
Authors: Tajuddin Mondali, T. , Tajuddin A. W. Ahmad , Aznor M. Z. , Harbidge P. , Chanson J.
Published: March 2016

This paper discusses on the new method of MWD surveying in drilling operations. It highlights the ability to take surveys faster than the conventional method while minimizing drilling risks. This resulted in a significant time reduction of the overall survey operations.

The MWD survey package normally requires the BHA to be stationary before it can start to acquire new survey data. Previous MWD survey systems monitored drilling fluid flow rate to trigger the MWD survey acquisition. This new MWD survey technique monitors rotation, optimising low noise detection, earlier. The new method takes less survey time, the pumps off time removed from the survey period.

This new method has been utilized in 4 out of 5 wells throughout the drilling campaign. The benefits can be clearly quantified from the comparison between the conventional and new approach. Based on the Drilling Mechanical Logs, the new method has proven to be able to shorten the surveying time by up to 80% compared to conventional. This translated to approximately 8.7 hours of rig time savings for the drilling phase of the project. Apart from time saving, it reduces stuck pipe risk by not having to stop pumping while also minimizing pipe stationary time. With the simplified survey operations, there is less likelihood of facing survey problems related to pump, signal and any other issues that may lead to the need of repeating survey.

Companies operating the exploration and production of oil, gas and water energy resources are continually looking for methods and techniques to reduce the time taken to drill and construct wells. The drilling phase is typically where there is a higher cost due to the drilling rig daily spread cost and the associated added environmental, health and safety risk aspects. Typically wellbore construction process is designed with a specified minimum tolerance for placing the wellbore inside the desired geologic zone or horizon, avoiding offset wellbores and geohazards and surveying the wellbore position sufficiently accurately to enable a relief well to be drill in the event of a well blow out.

Wells drilled during the recent five well campaign, offshore Malaysia have utilised this new method for taking surveys with reduced survey time as part of the new operator Operational Excellence and Drilling the Limit initiatives.
Malikai Topside and Hull Integration
Authors: Si Michael , Lim John , Wong G. J. , Choo C. K.
Published: March 2016

The Malikai platform is the first Shell's Tension Leg Platform (TLP) designed and fabricated outside the Gulf of Mexico. One of the innovative aspects of the project is the first of its kind topside and hull integration: a Mega Jack and Skid System lifted the TLP topside 40m above ground, skidded the topside 90m horizontally across at that height, and set the topside onto the hull structure. On July 19, 2015, the Malikai topside was raised 40m above ground and skidded over the hull before being set down for Topside-Hull integration. The superlift operation, from the commencement of the topside jacking to its final set down, took seven days. This paper describes the concept selection and the operation of the Malikai Topside and Hull integration using Abnormal Load Engineering (ALE) Mega Jack System superlift. The paper also shares the engineering validation, challenges and lessons learned for use with similar future operations.
Processes controlling the annual cycle of Arctic aerosol number and size distributions
Authors: Croft Betty , Martin Randall V. , Leaitch W. Richard , Tunved Peter , Breider Thomas J. , D'Andrea Stephen D. , Pierce Jeffrey R.
Published: March 2016

Abstract. Measurements at high-Arctic sites (Alert, Nunavut, and Mt. Zeppelin, Svalbard) during the years 2011 to 2013 show a strong and similar annual cycle in aerosol number and size distributions. Each year at both sites, the number of aerosols with diameters larger than 20 nm exhibits a minimum in October and two maxima, one in spring associated with a dominant accumulation mode (particles 100 to 500 nm in diameter) and a second in summer associated with a dominant Aitken mode (particles 20 to 100 nm in diameter). Seasonal-mean aerosol effective diameter from measurements ranges from about 180 in summer to 260 nm in winter. This study interprets these annual cycles with the GEOS-Chem-TOMAS global aerosol microphysics model. Important roles are documented for several processes (new-particle formation, coagulation scavenging in clouds, scavenging by precipitation, and transport) in controlling the annual cycle in Arctic aerosol number and size. Our simulations suggest that coagulation scavenging of interstitial aerosols in clouds by aerosols that have activated to form cloud droplets strongly limits the total number of particles with diameters less than 200 nm throughout the year. We find that the minimum in total particle number in October can be explained by diminishing new-particle formation within the Arctic, limited transport of pollution from lower latitudes, and efficient wet removal. Our simulations indicate that the summertime-dominant Aitken mode is associated with efficient wet removal of accumulation-mode aerosols, which limits the condensation sink for condensable vapours. This in turn promotes new-particle formation and growth. The dominant accumulation mode during spring is associated with build up of transported pollution from outside the Arctic coupled with less-efficient wet-removal processes at colder temperatures. We recommend further attention to the key processes of new-particle formation, interstitial coagulation, and wet removal and their delicate interactions and balance in size-resolved aerosol simulations of the Arctic to reduce uncertainties in estimates of aerosol radiative effects on the Arctic climate.
Ideas and perspectives: Heat stress: more than hot air
Authors: De Boeck Hans J. , Van De Velde Helena , De Groote Toon , Nijs Ivan
Published: March 2016

Abstract. Climate change models project an important increase in the frequency and intensity of heat waves. In gauging the impact on plant responses, much of the focus has been on air temperatures while a critical analysis of leaf temperatures during heat extremes has not been made. Nevertheless, direct physiological consequences from heat depend primarily on leaf rather than on air temperatures. We discuss how the interplay between various environmental variables and the plants' stomatal response affects leaf temperatures and the potential for heat stress by making use of both an energy balance model and field data. The results demonstrate that this interplay between plants and environment can cause leaf temperatures fluctuations in excess of 10 °C (for narrow leaves) to even 20 °C (for big broad leaves) at the same air temperature. In general, leaves tended to heat up when radiation was high and when stomates were closed, as expected. But perhaps counterintuitively, also high air humidity raised leaf temperatures, while humid conditions are typically regarded as benign with respect to plant survival since they limit water loss. High wind speeds brought the leaf temperature closer to the air temperature, which can imply either cooling or warming (i.e. abating or reinforcing heat stress) depending on other prevailing conditions. The results thus indicate that heat waves characterized by similar extreme air temperatures may pose little danger under some atmospheric conditions, but could be lethal in other cases. The trends illustrated here should give ecologists and agronomists a more informed indication about which circumstances are most conductive for heat stress to occur.