bluuebunny/crossref_metadata_2025 huggingface dataset:
Zirconium Crosslinkers: Understanding Performance Variations in Crosslinked Fracturing Fluids
Authors: Almubarak Tariq , Ng Jun Hong , Nasr-El-Din Hisham A. , Almubarak Majed , AlKhaldi Mohammed
Published: November 2020

Borate crosslinkers are the most commonly used crosslinker in fracturing fluids. However, they exhibit lower performance at high temperature, high pressure, high water salinity, and low pH applications. Consequently, zirconium crosslinkers are utilized to address these limitations. Zirconium crosslinking chemistry is complex and depends on many factors such as pH, metal to ligand ratio, ligand order, ionic strength, and type of polymer used, which in turn influence the delay time, thermal stability and shear resistance performance.

This work evaluates the rheological performance of four different zirconium crosslinkers with a biopolymer and a synthetic polymer. The tested crosslinkers are manufactured in different chemical structures. The two polymers tested are 40 lb/1,000 gal CMHPG and 40 lb/1,000 gal synthetic polymer. The rheological performance was measured through HPHT rheometer (100 s−1 shear rate) at 200-400°F for 2 hours. The shear tolerance performance was also evaluated under a custom shear rate schedule (100-1000 s−1).

The results show significant variation in crosslinking performance due to the changes in crosslinker chemical structure and type of polymer used. Zirconium lactate and propylene glycol crosslinker shows the highest enhancement in shear and thermal stability with CMHPG based fracturing fluids. Surprisingly, the same crosslinker performed the least with synthetic polymer-based fracturing fluids. However, Zirconium triethanol amine and lactate showed significant enhancements in shear and thermal stability with synthetic polymer-based systems. The results also show and discuss the influence of systematically changing crosslinker ligand order in CMHPG and synthetic polymer-based fracturing fluids.

The work studies the influence of the zirconium crosslinker chemical structure on the rheological properties of both biopolymer and synthetic polymer-based fracturing fluids. The performance evaluation shows that delay time, shear and thermal stability can be enhanced by manufacturing the appropriate crosslinker chemical structure, thus reducing additional additives required used and saving cost.
Practical Aspects of Cost-Effective Solution for Global Lateral Buckling Mitigation with Residual Curvature Method for Subsea Pipelines
Authors: Mak Kok Wah , Ngai Tommy , Paul Eldho
Published: November 2020

Practical aspects and the application of lateral buckling mitigation for subsea pipelines with Residual Curvature Method (RCM) are discussed in this paper. The main purpose of this paper is to promote the RCM in the Asia Pacific region as a practical and a cost-effective alternative to the existing buckle initiation methods for subsea pipelines.

The RCM is assessed and compared with two existing buckle initiation methods (i.e. sleeper and zero-bend radius) using finite element analysis. The build-up of the effective axial force is the key driving mechanism in inducing a buckle in the pipeline. The effective axial force builds up along the pipeline with buckle length and the critical buckling force for buckle mitigation methods mentioned above are presented for comparison.

Some practical aspects and design considerations of the RCM are also discussed. The local residual curvature section, which so far has been applied with reel-lay vessels can be implemented with S-lay vessels as a buckle mitigation scheme. Discussion on a proposal to consider the use of RCM with S-lay vessel is also covered. Additionally, the advantages and disadvantages of RCM are compared with respect to the technical challenges, the construction cost and time, handling operations and installation.

This paper shall provide some good exposure to practising engineers and local/international operators in the Asia Pacific region with a relatively new and efficient method for lateral buckling mitigation and has, to date, been utilized for shallow water pipelines installed by reel-lay vessels.
Drilling Minimum Standard as Regulatory Benchmarking for Drilling Performance in Malaysia
Authors: M. Yunus M. Nasir , A. Tarmizi M. Farid
Published: November 2020

As part of Drilling cost optimization initiatives, Malaysia Petroleum Management (MPM) Drilling as the regulatory body of PETRONAS has been enforcing Drilling Minimum Standard (DMS) as Drilling performance benchmarking to Petroleum Arrangement Contractors (PACs). This paper explains the Key Performance Indicators (KPIs) & Well Complexity Categorization contained in the latest version of DMS.

DMS uses 3 main KPIs to benchmark PACs’ Drilling performance specifically Drilling Days per Thousand Foot (DDPTF), Drilling Cost per Foot (DCPF) and Well Cost per Foot (WCPF). Numerous versions of DMS were iterated from time to time to reflect on the ever-changing Drilling operations. Utilizing Online Drilling Benchmarking System (ODBS) developed by MPM Drilling as the data source and benchmarking tool, DMS has been updated with the inclusion of latest Daily Drilling Reports (DDRs) data over a span of 7 years covering more than 500 wells. KPIs figures for each category from previous DMS version were compared with latest actual Drilling KPIs figures prior to the revision.

The latest DMS version maintains the same well complexity categories of the previous DMS while introduces a new Sidetrack complexity category based on the number of hole sections. In conclusion, the newly updated DMS version introduces more pertinent KPI figures thus, reflect on MPM efforts to improve drilling performance from the costs and time perspectives. With the availability of reliable data in ODBS, MPM Drilling set a highly accurate DMS for performance improvement mindset within the PAC's throughout the Drilling industry in Malaysia context.
Pioneering Slickline Deployed Through Tubing Gravel Pack in Malaysia; Successful Case Study and Lessons Learnt
Authors: Mappanyompa Ertiawati , Trinh Ba Loi , Mazzlan Khairul Akmal , Aripin Izura , M Sulong Etiqah Siti , Nik Khansani Nik Zarina , Picou Robert , Salahudin Sharifudin
Published: November 2020

Formation sand production is a major concern in brown field operations, especially as the field depletes and water production commences. There are many methods to control sand production in primary well completion; however, it becomes more challenging in producers where no primary sand control is installed initially, and it starts producing sand later in the well life.

Selecting the right method for remediating these wells has become a hot topic with both Operators and Service Providers alike striving to discover effective and economical solutions for their brown-field operations. Currently, the solutions for through-tubing sand control in existing producers are screen hang-offs, through-tubing gravel packing1 (TTGP) and chemical sand consolidation.

Through-tubing sand screen (TTSS) hang-offs above the producing zone, is an inexpensive sand control method. Unfortunately, these installations are typically short lived, often requiring regular well interventions due to screen plugging or erosion, or sand clean-out operations to remove sand accumulated in the production tubing. Alternatively, TTGP is a robust method to control sand production; however, more equipment is required to deploy the gravel pack which subsequently increases costs significantly in offshore applications. To simplify TTGP and make it economical, a major Interventions Service Provider devised a methodology to install TTGPs utilizing Slickine that reduces the overall installation cost tremendously. The methodology has been proven a great success in the US Gulf of Mexico where over 1,200 applications have been installed.

The pilot implementation of slickline deployed through-tubing gravel pack (SL-TTGP) was executed in three S-Field wells in late 2018 which were shut-in due to higher than permissible sand production. These were challenging intervals in that they were uphole recompletions between cement packers in dual string 9-5/8" casing which had produced sand.

The results from the installation proved that the methodology provides effective sand control and enables reinstatement of production from these wells. Further, the installations were achieved with lesser resources and at lower costs; less than half that of a CTU deployed TTGP. This success has led to further installations in the following year.

This paper presents in detail the case study of the pilot implementation of SL-TTGP, key successes, as well as critical lessons learnt during execution and production phase. It includes the challenges, risks and their recommended mitigation plans, as well as the well performance comparison before and after the implementation both in terms of production and sand count.
The Occurrence, Saturation and Distribution of Gas Hydrate Identified from Three Dimensional Seismic Data in the Lw3 Area: The Northern Slope of the South China Sea
Authors: Yan Chengzhi , Shi Hesheng , Wang Xiujuan , Li Yuanping , Li Jie
Published: November 2020

Gas hydrates with high saturation in clayey silt sediments have been identified from several gas hydrate drilling expeditions in the South China Sea (SCS). However, the spatial distribution is not well delineated due to the limitation of two dimensional or pseudo-three dimensional seismic data. The three dimensional (3D) seismic data acquired by oil & gas exploration was reprocessed using high-density velocity analysis, which can be used to show the detailed mapping and characterization of high concentration gas hydrate in the LW3 area, SCS. The well log data and core samples have indicated that pore-filling gas hydrates have various saturations and thickness in the study area, but the spatial variations are still poorly defined. High-resolution broadband inversion without well constraint was conducted based on the high-resolution velocity analysis, which dramatically increased the accuracy in detecting thin gas hydrate-bearing layers. Rock physical models were involved to quantitatively predict gas hydrate saturation, which has been used to describe the gas hydrate-bearing layers with a thickness ranging from 5 to 6 m. Multi-attribute analysis extracted along the base of gas hydrate stability zone (BGHSZ) was used to predict the gas hydrate distribution. Gas hydrate distribution identified from the reprocessed high-resolution 3D seismic data indicate that gas hydrate-bearing layers are mainly located at four ridges of the migrating canyons in the Liwan 3 area. The thickness and saturation of gas hydrate distribution at the third and fourth ridges are better than the other two ridges. The gas hydrate saturation is over 40 % with a thickness exceeding to 70 m. Moreover, the thin gas hydrate layer is interbedded with thick layer at the forth ridge. However, the gas hydrate saturation is over 70 % with a thickness of 30 m at the third ridge. The gas hydrate distributions exhibit obvious heterogeneous at each canyon zone. The accuracy prediction and delineation of gas hydrate distribution are very important for assessing gas hydrate test production responses and scenarios.
Self-Installing Platform with Conductor Guide Support Frame System
Authors: Kuan EngYeow , Yee KienPeng , Tan Jaime HuiChoo
Published: November 2020

In a conventional shallow water field development with dry trees, fixed platforms are utilized to support the topsides processing facilities, dry-tree wellheads and well conductors. The fixed platform can be a fully integrated platform or a dedicated process platform and a wellhead platform. A new innovative integrated processing and wellhead platform concept by means of a suspended conductor guide support frame which is retractable, provides an alternative for the structural design of facilities for dry-tree field developments. This conductor guide support frame concept is developed for a Self-Installing Platform (SIP) such that it can support well conductors and dry trees, besides the processing facilities similar to a conventional fixed platform and does not require the mobilization of a heavy lift vessel for installation. Being self-installable, it can be easily deployed and redeployed at different sites and hence is suitable for marginal fields developments. A case study has been performed on this concept and the in-service structural stress and fatigue performance of the conductors have been verified based on design parameters for a typical development offshore Peninsular Malaysia. The range of suitable applications of this SIP with conductor guide support frame concept is presented.
Deepwater Flowlines and Risers Decommissioning
Authors: Jaafar Azam Syah , Obaidellah Ahmad Taqiyuddin , Karim Khairul Anuar , Hussien Hayati , M. Ali M. Nazmi , M. Yunus M. Jeffri
Published: November 2020

Operators around the world are reviewing their aging assets, and are coming to clench with the reality that some offshore fields are no longer economically viable. The North Sea and the Gulf of Mexico have seen numbers of decommissioning activities. In other regions, decommissioning activities had started to emerge, now and in the coming years. Decommissioning, an easy-look-but-massive-task come with unique challenges and cost ranging in the billions. Delivering an effective decommissioning especially when dealing with deep-water operations are paramount as to secure the economic value from the assets. Health, Safety and Environmental (HSE) concerns are always vital in any decommissioning process. The target is to effectively reduce the long term risks to other benefactors of the sea while the associated short term risks to those responsible for decommissioning operations are minimized. A major part of any decommissioning project is the decommissioning of subsea pipelines including the flowlines and risers.

Referring to a field case example from one of PETRONAS's deepwater field decommissioning project in Atlantic Ocean, a numbers of techniques had been considered for decommissioning of subsea pipeline system which sited in 700m to 960m water depth, ranging from preservation for potential future use, leaving in-situ or full recovery. Noted that each subsea pipeline decommissioning technique should be considered on its own merit, thus the assessment of each decommissioning technique had been based on many parameters, amongst others, size of pipeline, type of pipeline (e.g. single pipe, pipe-in-pipe, flexible), type of fluid in the pipeline, operational environment (location), production history, Inspection, Repair and Maintenance (IRM) records, HSE considerations, connection to other facilities, technical feasibility (including potential use of advanced technologies), regulatory authorities requirements and socio-economic considerations.

This paper covers only at specific of PETRONAS deepwater subsea flowlines and risers decommissioning experiences. It outlines the activities done starting from desk top activities (e.g. planning and concept) up to operational activities (e.g. pigging, flushing, cleaning, disconnection, retrieval or leaving in-situ). Different considered scenarios are discussed and potential advantages and disadvantages of each scenario are presented.
Breaking the Norm: Spudding the Well Riserless with Directional CwD BHA For Surface Casing Enables to Reach Shallow Reservoir
Authors: Shahrul Amar Muhammad Shafiq , Za'ba Muhammad Afiq , Bayking Elias , Phan Van Chinh , A. Rahman Iz'aan 'Irfan , Rj Hassan Rj M. , Khazali-Rosli Khairul Amir
Published: November 2020

Shallow Hazard was detected and prevents this exploration wells to be drilled vertically above the prospects. Thus, a directional well was planned 60m away from the intended surface location. The challenge was to use the same spudding method as the normal vertical well used by the operator in this area. A Casing while Drilling (CwD) level 2 was the norm in this field to spud the surface casing vertically. However, with this shallow hazard, this must be drilled directionally to achieve the intended reservoir. Kicking off deeper will cause the dogleg severity to be high in the subsequent section as the reservoir TVD is as shallow as 1200m.

A feasibility study was done to understand the requirement and the complexity in ensuring the objectives of the wells achieve. Numerous discussions with different expertise from the operator, contractor and drilling engineering to outline the technique, BHA design, drilling parameters, and the risk mitigation in case of any shallow hazard struck. Bit and reamer studies with Dynamic BHA Vibration modeling were performed to define stable drilling parameters and predicting the BHA capability.

With the systematic technical approach, the BHA spudded smoothly until a planned depth before the reamer activated and BHA started to rotate and drill. Kicking off is a challenge with heavy CwD BHA in this soft unconsolidated formation with few stringers observed along the way. 50% of the total meterage was used to slide with WOB ranging from 3-5 klbs to bring the trajectory towards the planned inclination 22 deg and reached TD as per plan depth.

This paper presents the technique and risk evaluation, workflow on offset well data analysis, BHA design process, customized bit/reamer selection and a dynamic vibration analysis to deliver this special Directional CwD Level 3 Technique. The successful of spudding and drilling this surface section had enable the operator to achieve this shallow prospect exploration target.
Spotlights of the Lessons Learned from Thap Raet West EOR Pilot
Authors: Pancharoen Monrawee , Kiravanich Parntip , Laochamroonvorapongse Rapheephan , Nopichai Sombat , Kulthamrong Theeraphot , Sardsangjun Pimporn
Published: November 2020

Sirikit Oilfield (S1) is the largest onshore oilfiled in Thailand. The production has started in 1982 with waterflooding implemented in 1995. Chemical Enhanced Oil Recovery (EOR) is considered as one of the potential mechanical to improve field recovery. Surfactant reduces interfacial tension leading to a decrease in oil saturation while polymer increases injected water viscosity and improves flooding performance. As a result, oil recovery is expected to increase beyond conventional waterflood operations.

Following positive laboratory results, an inter-well chemical EOR pilot injection was implemented in the TRT-W area with a single injector-producer well pair. Reservoir simulation study was performed to determine pilot injection strategy, and the expected performance prediction from the process. Chemical quality control and measurement protocols were established by using titration method for surfactant and chemial oxygen demand (COD) method for polymer measurements. Oil saturation logging was performed in nearby producer to confirm the effectiveness of surfactant in reducing oil saturation at reservoir conditions. Production rate and water cut were monitored to observe any changes in well production. The injection period lasted for 14 months, from September 2017 – November 2018.

Several tools and techniques were deployed to ensure that the designed conditions were met and able to effectively evaluate the pilot injection results. A reduction of oil saturation was achieved by the surfactant injection, as evidenced from oil saturation logging results. It was a positive indication that the surfactant has worked as planned in the reservoir. Oil production and water cut were monitored by routine production test. However, significant improvement in oil production was not observed. During the pilot, no surfactant was produced in the monitored producer. Potential causes of lower-than-expected oil recovery were identified as change in water quality and high surfactant adsorption in the reservoir. A number of operational issues were also encountered during this pilot including facility disruption and artificial lift failure.

Further investigation is required to develop an appropriate surfactant formulation with a wider range of working conditions and, most importantly, identify ways to mitigate the high adsorption issue. Lessons learned from this pilot in terms of facility design, water quality control, pilot monitoring program and contracting strategies will be incorporated in the design and execution of future EOR pilot implementations in the S1 field.
Case Study on the Nano-Polysilicon Materials' Depressurisation and Injection-Increasing Technology in Offshore Bohaibay Oilfied Kl21-1
Authors: Feng Qing , Li Nan Xiao , Huang Jun Zi , Li Na , Li Song Jing , Tian Miao , Zeng Ming , Yang Xing Wei , Wang Hua Shao , Wang Fei
Published: November 2020

Due to low reservoir permeability and interlayer contradictions, high water injection pressure and low water injectivity index have become a big challenge in the waterflooding development of low-permeability reservoirs. Therefore, new pressure-lowering and injection-increasing technologies have been desired. Nanotechnology offers various creative ways to solve the problems of oil and gas production that also provided a potential oilfield chemical in pressure-decreasing application.

However, successful pressure decreasing nanotechnology have rarely been reported. This manuscript reports nano-polysilicon as a new depressurization and injection-increasing agent. The stability of nano-polysilicon was studied in the present of various ions, including Na+, Ca2+, and Mg2+. This study finds that the addition of nanomaterials can improve porosity and permeability of porous media. Injection / draw down test method is taken to evaluate injection effects of nano-polysilicon into water wells, and flow resistance changes are investigated by infectivity index curve. Through injection performance evaluation experiment, it is found that the nano polysilicon technology has the ability to improve the permeability and weaken flow resistance of fluids.

Field test results prove that biological nano-polysilicon technology has obvious effect on pressure reduction and injection-increasing. After the operation of test wells, injection-increasing nano-polysilicon technology has excellent performances with increasing injection rate by 40% and pressure drop by 10%. This work presents the first successful oilfield test of nanoagents in pressure-decreasing application that offers a novel, simple and pollution-free oilfield chemical. The importance of this work is not in stability and salt tolerance of nanoparticle but rather in their first real field application of depressurization, which takes an exciting example for nanotechnology to effectively solve another real difficulty in petroleum engineering.
Design and Safety Considerations to Perform Coiled Tubing Operations in Large-Diameter, High-Temperature Geothermal Wells
Authors: Singh Ishaan , Aryo Wijoseno Danny , Wolf Kellen , Sorman Ignatius , Dutta Shaktim
Published: November 2020

The wells in the "A" geothermal field located in the Philippines, have high bottomhole temperature (BHT) of 600°F and bottomhole flowing pressure (BHFP) of 2,000 psi. The productive section in this field has "shallow" and "deep" reservoirs which are separated by a low-permeability formation. The interaction between the reservoirs is hence limited except through the wells resulting in intrazonal flows under shut-in conditions. As observed with time, these flows have been upflows making the overall production very stable. However, in recent years, it has been found that the cooler fluid inflow from the shallow reservoir has relatively increased, causing reduction in production levels. Under flowing conditions, this has resulted in both flow instability and downflows in wells, which in turn have decreased the individual well production capacity. In order to activate and enhance well production, coiled tubing (CT) nitrogen lift operations were required to be performed to unload the cold water in geothermal wells, hence enhancing steam production.

The wells in this field are completed with large completion sizes (7-in., 9.625-in., and 13.375-in.) and have high BHT (600°F), which makes conventional coiled tubing operations highly challenging. Because the coiled tubing operations in geothermal wells are limited as compared to the conventional operations, planning and executing these for the first time in the "A" field was challenging operationally and technically. As such, surface equipment failure risk was high, putting at risk successful coiled tubing operations.

To gain further understanding of operations in high temperature and cold water downflow environments, CT simulations were combined with simulations from the geothermal reservoir to overcome modeling limitations. The outcome helped designing a new cooling loop system and allowed optimizing the nitrogen lift technique. As a result, two large-diameter geothermal wells were lifted safely with 2-in. coiled tubing in the Philippines.
Doing Less with Less with Fit for Purpose FEA Solution in Asset Support
Authors: Chow Wan Han , Bolhassan Rosannah , Loh Khian Aik , Kota Ravi , Henry Zulkipli
Published: November 2020

Managing asset Integrity has been a long inconvenient issue to many ageing assets in Malaysian waters. As the Oil and Gas business grows and matured, so have the assets. Often time direct solutions are not available due to complexity of the problems. As asset operator, it is our responsibility to find life extension solution to keep the hubs full and remains competitive. With the advancement in technology and creative mindset, large system can be subdivided into smaller systems and solved one at a time before reintegrated into the larger system which forms the backbone of finite element analysis method.

This paper will illustrate some of the asset integrity issues faced by shallow and deep-water platforms. The three selected asset integrity examples include a topside beam with cut-out, well casing material loss and stress joint fatigue life extension. A step by step fit for purpose solution along with the challenges faced and mitigation measures taken was documented in this paper. For beam with cut-out, the 2D beam model is compared against the 3D model concentrating on the stress flow pattern and stress concentration factor. For well casing material loss, discussion evolved on how strengthening can be minimized by simply repositioning the bolt location. For stress joint fatigue life extension, the limitation of an axis-symmetry model in capturing bending moment and the conservatisms of applying an equivalent tension load to simulate the bending action was discussed. Simplified solutions are often associated with conservative result which is not necessarily true. Simplified solution in this context is a method to break the complex system into simpler system and solve using minimum resources, time and cost. The aim is to share knowledges with fellow operators on ways to maximize the niche manpower to do less with less.

In conclusion, by simplifying the complex system coupled with 3D advanced analysis tools, the integrity of the asset remained intact, reduces the need of periodic inspection/ parts replacement and opens-up opportunity for life extensions. The same concept can be replicated for other similar projects and be mindful that FEA do not solve all problem, but people do.
A Simplified Method to Predict the Shock Load on Crane Wire to Hang Hammer During Pile Running
Authors: Huang Zhiwei , Kurundwade Santosh , Kibby Landon , Chen Zongrui
Published: November 2020

Pile running, the uncontrolled fall of a pile due to the collapse of a hard soil layer over softer soils, is a major constructability risk during pile driving operations. This is especially the case for the long and large diameter piles driven with heavy hammer. Unexpected pile running may cause loss of the pile, damage to the jacket, damage to the crane due to overload or even hammer loss. This paper discusses about shock load on cranes due to pile running and its estimation using simplified method based on a real project record. The method can help to develop dedicated plans for pile driving if pile running is predicted in pile drivability analysis in future projects. At the same time some remedial measures to reduce shock load on crane wire are included and discussed.
Laser Drilling in Extremely Hard Formation
Authors: Batarseh Sameeh I. , Alharith Abdullah M. , Assiri Wisam , San Roman Alerigi Damian
Published: November 2020

The objective of this work is to demonstrate the success and the ability of high power lasers beam to drill in extremely hard formations. The result showed that the rate of penetration in these formations is much faster than conventional drilling methods. Formations with high compressive strength can prevent or slow drilling and rock penetration. A High power laser program was established to overcome the limitations of conventional drilling methods and provide an innovative non-damaging technology as alternatives to current practices. The technology is not only able to drill in extremely hard formations but also enhances rock properties without compromising wellbore integrity.

For the past two decades, researchers attempted to deploy high power laser technology for several downhole applications, with no success because the power needed to penetrate the rock was insufficient. Laser technology has evolved and advanced recently, creating compact efficient, higher power, and economically feasible systems.

An experimental setup was designed to evaluate the performance of a high power laser in different rock types and with different compressive strengths, ranging from 12,000 to 43,000 psi. These samples were exposed to a high power laser for several applications. The results demonstrated that a high power laser could penetrate extreme rock formation in seconds, for example, at the lab scale, it took 3 seconds to drill 3 inches of basalt (43,000 psi compressive strength). The flow properties were also enhanced regardless of the compressive strength and hardness of the rock.

Laser technology attracted the oil and gas industry due to its unique features, such as the precision in controlling and orienting the energy in any direction. Laser drilling is independent of the reservoir stress orientation and magnitude. The laser generation unit is mounted on the surface and the laser beam delivered downhole via fiber optics cable. The system has a minimal footprint, is an environmentally friendly technology, and can drill and case simultaneously.

High power lasers have the potential to be the next intelligent drilling and completion generation that will change current practice. State-of-the-art high power laser technology provides an innovative and safe non-explosive based technology. Precision, speed, small footprint, and reliability are some of the properties of the technology that make it attractive for downhole applications.
Synchronized Towing of Flexible Riser in Shallow Water and Varying Current
Authors: Shahaya Marshel Anbu , B. Karim Khairul Anuar , A. Latif Nur Atika , Badaruddin M. Fauzi , Ali Napiah M. Nazmi
Published: November 2020

Towing of offshore pipelines can be heard during the mid-nineties, and it has been continuously improved with the advent of 2nd and third generation vessels. The operation poses a great challenge due to the dynamics and the instantaneous tension which the pipelines need to face. There is a high risk of flow line / pipeline getting damaged with potential increase in tension loads. It could also happen that the pipeline can get buckled with unexpected environmental loads. There can be a situation wherein the flow line gets damaged due to difference in tow speeds. In such situations the pipeline most likely touches the seabed for a shallow water depth. If a pipeline is in high tension in which greater than the allowable axial load, then there is likely pipeline can get damaged. If the pipeline is a flexible type, then there is a high chance for the outer sheath to get damaged. It is one of a most delicate operation which requires a focused interaction from different parties, viz. the Tow master, captain of the forward and trailing vessel and the monitoring vessel which have to move in a synchronized speed along with the Tow speed. There are in all three (3) major phases for a typical Towing Operation: a) Initiation and setup for Towing; b) start of Towing operation; and c) Tie-in or relocating the Pipeline / Riser to a new location.

The seabed route selection and the bathymetry features are decided and firmed upfront. It should be as much as possible select the shortest route with minimum changes in the Vessel azimuth and bearing direction. The bathymetry should be free of any elevated obstruction, subsea anchor, mooring buoys and any mooring anchor chain from the nearby floating facility. This paper will be discussing flexible dynamic riser with near seabed tow at shallow water depth and high current. The flexible dynamic riser is an existing production line, which was required to be detached from a floating facility and then to be towed away to a safe distance. The facilities were temporarily shut down and during that time flexible riser was planned to be towed to a safe location and wet stored. The flexible riser was then again towed back to the same field after changes were made in the infrastructure facilities. The additional challenges faced were on manipulating the tensions around the bend stiffener and maintaining allowable Minimum Bend Radius (MBR) near the bend stiffener portion. It discusses about the sequence of operation, the initial planning preparation work, the simulated engineering activity, the offshore marine spread and its associated activities, and the monitoring systems in place.
A New Solution for Well Abandonment: Bismuth and Thermite
Authors: Fulks Jeff M. , Carragher Paul
Published: November 2020

Well abandonment is as much a part of the oil and gas industry as drilling and production yet is seems to receive the least amount of consideration. Operators spend months and even years planning how they will drill and complete a well but often don't think about how they will abandon it until production has ceased. As such, they tend to rely on traditional methods and materials, doing it the same way it has always been done and yielding the same results which are often not desirable. Recently, more operators have chosen to spend more time planning well abandonments than ever before. Perhaps this is because the requirements for well abandonment have increased or because, unlike drilling and production, any money spent on well abandonment comes straight off the bottom line without the opportunity to recuperate during production. Either way, this increase in visibility has led to a search to abanon wells more efficiently and cost effectively.

One of the ways to achieve this is by looking at alternative sealing materials, such as bismuth. Since 2015, bismuth alloy tools have been delployed over 80 times to seal wells at various stages of the well's life with 60% of the tools run for well abandonment. Bismuth alloys are also being considered as possible alternative barriers to cement by multiple regulatory agencies.
Evaluation of Data Driven Versus Multiphase Transient Flow Simulator for Virtual Flow Meter Application
Authors: Ishak Mohd Azmin , Al-qutami Hasan Tareq Aziz , Ellingsen Halvard , Ruden Torgeir , Khaledi Hatef
Published: November 2020

Production Well Testing is one of the major routines in the upstream oil and gas operations. It is an important oil & gas operation as it will be used to track the performance of individual well productivity, production planning, projection for future investment or divestment i.e. drill new wells, shut non-productive wells or execute well intervention. Historically, production well testing is executed using a single-phase meter after the hydrocarbon is separated in a test separator. Alternatively, physical Multiphase Flow Meter (MPFM) could be used either over a test header or at individual well flowline. MPFMs combine several measurement principles such as Gamma ray spectroscopy, capacitance tomography, microwave, and ultrasound to infer phase flow rates. From PETRONAS experience, there are many instances where the MPFM, especially in subsea installation, failed either prematurely or later part of the field life. Virtual Flow Meter (VFM) can be used as a back-up in this case. Traditionally, a virtual flow meter uses a steady state or transient flow simulator that exploit various measurements within the wells and facility such as downhole pressure & temperature gauges, tubing head flowing pressure, differential pressure across the choke, choke position and fluid characteristic to derive the flow rates of oil, water and gas. In this paper, we will compare and evaluate a VFM that uses transient flow simulator against data-driven VFM which uses machine learning technique. Both data-driven and transient flow simulator VFM are evaluated using the same well test data from real producing oil fields. From this work, the team realized there is a potential that both data-driven and transient flow simulator can be combined to provide a complementary benefit as an optimal Virtual Flow Meter and to reduce the overall system uncertainty.
Optimization of Online Pipeline Repair Method Using Welded Sleeve
Authors: Md Zin Ghazali , Badaruddin M. Fauzi , M. Zabidi M. Zazli , Ibrahim Kamal Azam
Published: November 2020

The objective of this paper is to demonstrate the optimization of online pipeline repair method using welded sleeve for onshore pipelines. There are several online repair methods available however the use of sleeve is preferred due to higher strain capacity and ease of installation.

In managing prone leak pipelines due to geographical terrain requires higher strain resistance over stress based design. Inline Inspection (ILI) program using geopig has recorded more than 0.5% strain on various location along the pipelines. From the original WPS, most of the girth welds are able to withstand only 0.2% strain. In order to ensure continuous production, any location that recorded more than 0.2% strain has to be strengthened. A relatively simple and ease of installation repair method is required. Any girth welds experiencing more than 0.2% strain may be cut out and reweld however requires extensive repair welding activities. This method also is not favorable due to loss of production.

The proposed welded sleeve welding procedure qualification (WPS) for online repair has to be qualified as per API 1104 prior to welding. The WPS were tested in accordance to API 1104 Annex B to simulate the in service welding requirement. All the mechanical tests were successfully tested as per the requirements. In addition to mechanical test, the sleeve also is required to pass the Full Scale Bend Test (FSBT) testing. The FSBT is intended to simulate the actual pipe condition with sleeve to withstand strain as per calculation. A 12m pipes with actual pressure of 96 bars were bended vertically downward to measure the maximum strain results. As per Finite Element Analysis (FEA), the maximum calculated strain for the sleeve to withstand is 0.9%. The results were compared with FEA analysis to check the amount of strain allowed on the weld.

This repair method eliminate the cut out repair method that require extensive repair works. The cut out and replace certainly will cost more and time consuming. Using this sleeve online repair method, loss of production is eliminated. The repair works is minimal hence the repair schedule is faster compared to cut out. The estimated cost savings is around RM20M per repair using welded sleeve method.
Improved Recovery Through Optimum Well Design Using Autonomous Inflow Control Device in Complex Brown Field Reservoir
Authors: Mohammad Zin Zulkifli , Khairuddin M. Shahnizam , A. Manaf Maziah , Mohammad Suria Melanie , Yap Bee Ching , Ahmad Mior Yusni , Shafie Shaiful Helmi , Dang Lola Le
Published: November 2020

Challenges associated with horizontal wells production in a barefoot or only standalone screen are well documented in the industry. Inflow control devices have been around for years and have been the answer to mitigate the challenges typically associated with heterogeneity in horizontal wells, as was applied in an offshore brown field in East Malaysia, Field S. However, as the field gets more mature, increasing production challenges posed by the reservoir leads to conventional passive inflow control device solution becoming less effective. Over time, as water production from the reservoir increases due to the rise of aquifer column, new infill wells have to be completed shallower and closer to gas oil contact to maximise recovery leading to risk of high gas production. The risk is further compounded by uncertainty in the fluid contacts in a complex dipping reservoir.

In order to mitigate these challenges, Autonomous Inflow Control Device (AICD) was selected for Field S infill wells to control excessive gas production anticipated due to the wells placement. AICD's ability to choke production based on the fluid properties allows for improved flow control together with influx balancing from segmentation into compartments by swellable packers. In total, seven (7) horizontal wells were completed in an infill drilling campaign in Field S, with the wells placed at around 5 m from prognosed gas oil contact. AICD was installed with premium sand screen and swellable packers in the wells’ lower completion and has managed to control excessive gas production while enabling production at the targeted oil rate.

This paper describes the implementation of AICD in Field S infill drilling campaign with challenges of complex dipping reservoir and fluid contact uncertainty. The workflow to investigate the feasibility of the candidate and the completion design process will be discussed. Well modelling (nodal analysis) using production data was performed to characterise the well performance and to understand the impact of AICD in controlling gas and inflow of producing fluid into the producing horizontal section.
Risk Management and Control for CO2 Waterless Fracturing
Authors: Meng Siwei , Yang Qinghai , Duan Yongwei , Tao Jiaping , Chen Shi
Published: November 2020

The fluid is seen with the high pressure and low temperature during the CO2 waterless fracturing operation, which is prone to accidents such as casualties and environmental pollution. In this paper, a complete operation safety management approach and a contingency plan are developed, with respect to the CO2 waterless fracturing.

For the fracturing equipment and support facility, high-pressure-resistant, low-temperature-tolerant specialized wellhead, valve and surface pipeline are required. The pipe wall thickness should exceed the N80 tubing criterion, and the relief line has to be anchor-fixed. In order to prevent suffocation caused by CO2, all vehicles and personnel must stay windward. All safety valve outputs should be arranged leeward, facing no personnel operation and equipment placement. Crews must appropriately wear protection that prevents suffocation and cold injury. While operating valves, they should stand beside the valve and operate steadily, so as to avoid object strike induced by the dry ice.

The contingency plan corresponding to the operation condition is developed. In the case of CO2 leakage, the operation should be stopped immediately, personnel will be evacuated to the open area on the windward side, and the air blower at the field should be turned on. As for the occurrence of gaseous CO2 in the surface process, one has to identify the gasification position in a timely fashion and adjust the vent valve of the blender and the surface pipeline and the wellhead valve correspondingly. If gaseous CO2 occurs inside the wellbore, the countermeasures of close surveillance, stabilizing pressures by injecting CO2 at a small rate, and pressure relieving after switching off pumps are implemented, depending on the severity of the case. Upon the arrival of the blender pressure at 2.4 MPa, the safety valve is open for venting. Synergistic pressure relief should be executed by opening the sand-input ball valve, gas valve and liquid valve, if the pressure continues to grow.

So far the CO2 waterless fracturing has been successfully operated for over 20 times, in the tight oil reservoir, shale oil reservoir, low-pressure sensitive gas reservoir, etc. No safety accident has been reported, which demonstrates the rationality and operability of the proposed risk management and control approaches for the CO2 waterless fracturing.
Effect of Two–Phase Flow on Gas Permeability in Marine Flexible Pipelines
Authors: Zhao Bingliang , Wang Kai , Li Yi , Yu Xichong , Chen Jinghua
Published: November 2020

The flexible composite pipes are quite suitable for the development of marine oil&gas reservoirs due to the excellent characteristics of design abilities, economics and dynamic behaviors. At present, the theories and methods of the gas permeations in the composite walls have not yet considered the influences of the multiphase flow in the inner pipes. Therefore, the prediction accuracies of the permeation rates are expected to improve for the marine flexible pipelines with significant differences of pressure and temperature drops. In this paper, a comprehensive gas permeation model including gas-liquid two-phase flow is proposed, and the effect of flow patterns on the gas permeation rate and vent period is investigated numerically. The results show that the flow patterns of multi-phase flow have significant impact on the permeation rate of gas due to different pressure drop and temperature drop for the same mass flow rate, and the permeation rate of CO2 is higher than that of CH4 under the same working condition.
Preventing Brittle Fracture of Metallic Materials in Oil and Gas Companies Through Mandatory Control Framework During Design, Engineering and Construction
Authors: Abdul Malik Noor Syamiza , Yusoff Suriani Binti , A Razak M Hasbi
Published: November 2020

The consequences of a catastrophic failure of equipment are very serious, both in terms of financial implications and the risk to human life. Essential requirements in the design and operation of pressure containing equipment such as pressure vessels, piping, and pipelines particularly those made from ferritic steel and operating at low temperatures shall be seriously considered in avoiding the possibility of brittle failure. Thus, preventing Brittle Fracture of Metallic Materials in Oil and Gas Companies through Mandatory Control Framework during Design, Engineering and Construction is implemented throughout PETRONAS facilities.

The specification of material requirements was developed to prevent process safety incident and mitigate the consequences resulting from the unintentional release of energy or hazardous by adopting lessons learned from major process safety incidents that have occurred in PETRONAS and in international hydrocarbon processing industries. Therefore, a governance document i.e. Mandatory Control Framework (MCF) was developed in PETRONAS by verifying the HSE management systems and practices in assuring the technical design integrity and quality during installation.

The establishment of MCF in most major oil and gas companies took place especially after the Texas refinery and Macondo incidents. The main intent of MCF is to ensure that all capital projects, plant modifications and the existing facilities with HIGH and VERY HIGH process HAZARDS complies with PETRONAS Technical Standard (PTS) requirements to safeguard the interest of all relevant parties.