bluuebunny/crossref_metadata_2025 huggingface dataset:
Influence of PET Fibers on Compressive Strength Water Absorption Percentage and Density of Adobe
Authors: Ordoñez Denys , Noa Melisa , Carmen Carrera Cabrera Elsa
Published: March 2022

Adobe is a building material that has been used since ancient times, but is not as widely used as clay bricks or concrete for housing construction. In addition, it uses a construction technique that has been passed down and improved from generation to generation. In view of this, the present work aims to improve the properties of adobe by using PET bottle fibers in its composition. A mechanical test and two physical tests were carried out for adobe with 0% (standard adobe), 2%, 4% and 6% PET fibers, where it was observed that the adobe with 6% PET fibers obtained the best results, since it increased the compressive strength of the adobe by 19%, reduced the absorption percentage by 12% and finally reduced the density by 16.4%. Therefore, the addition of PET fibers in adobe is recommended, as it contributes to improve its mechanical and physical properties. Additionally, it reduces pollution in streets, rivers, parks, etc. because it promotes the recycling of PET bottles.
Numerical Characterization of the Mechanics of Bézier-Based Lattice-Beams
Authors: Álvarez-Trejo Alberto , Cuan-Urquizo Enrique , Roman Armando , Farfan-Cabrera Leonardo I. , Trápaga-Martínez L.G. , Alvarado-Orozco Juan M.
Published: March 2022

Metamaterials are controlled arrangements of material structures in which their mechanical properties can be tailored by tuning their geometrical parameters. A parametrization based on cubic Bézier curves is employed here to generate cantilever lattice-beams by changing the position of a free control point. The apparent stiffness of these lattice-beams is numerically analyzed by means of tensile, bending, and free vibration simulations. Results expose the influence of shear deformation in the mechanical behavior of beams made from a cellular material; different degrees of variation depending on the loading conditions and lattice topology are observed and discussed.
Challenges on Building Representative 3D Static Models under Subsurface Uncertainties for a Giant Carbonate Field in Central Luconia, Offshore Sarawak
Authors: Chongrueanglap Pongsit , Siriwattanakajorn Warintaphat , Hamdan Mohamad Kamal bin , Poret Kelly La Grange , Soontornnateepat Thanutpong , Mahamat Sirichai , Wongpaet Khuananong , Cheong Yaw Peng
Published: March 2022

This paper focuses on the challenges in building representative 3D static models under all subsurface uncertainties for a green field. The case study is based on a giant carbonate gas field, appraised with a few partially penetrated wells in Central Luconia province, offshore Sarawak, Malaysia. With very limited hard data for reservoir characterization, knowledge from Central Luconia literature and nearby field analogues had to be used together with the 3D seismic data. Standard geostatistical methodology was used to integrate the subsurface interpretations and to capture the identified subsurface uncertainties, i.e., structural framework, fluid contacts, facies distribution, petrophysical interpretations, saturation function, permeability prediction etc.

Some of the key challenges, findings and results are listed below;

How to quantify a long list of subsurface uncertainties with a manageable number of 3D static models? Full factorial design was used together with expert knowledge to limit the total number of uncertainties. How to quantify the structural uncertainty and the challenge in building geocellular grid for carbonate platform and pinnacle buildup? Even with very limited core data, the lithofacies interpretation was completed and incorporate 3D seismic data as representative 3D trend for distributing the expected carbonate facies. It is a massive challenge in characterizing the petrophysical properties for carbonate reservoirs, as heterogeneity (both primary and secondary processes) can be difficult to predict. Similar porosity seen in seismic inversion might have different flow behavior in permeability. Sub-seismic geological features like flooding surfaces might be acting as vertical baffles, which must be modelled as an important element of the geostatistical models. Reservoir characterization and uncertainty quantification will allow an improved understanding of the reservoir, and the results will guide the data acquisition program in subsequent appraisal campaign.

This case study will enrich the knowledge within the Central Luconia carbonate province, and a discovery in a mature basin is still a massive challenge for reservoir characterization under uncertainties.
Performance Evaluation of W Shape Dynamic Inter-Array Cable Configuration for Floating Offshore Wind Turbine
Authors: Shi Luhao , Yang Wanqiu , Chen Kai , Yu Guojun , Jin Canwei , Ni Lingxiao , Jing Biao , Hu Zhendi
Published: March 2022

Floating wind farms has been a global trend in utilizing offshore wind resources. With the development of floating offshore wind turbine (FOWT), dynamic inter-array cable would be required to connect between floating structures. W shape is a kind of dynamic cable configuration that shape the cable floating in midwater and connect between floating platforms. This paper tends to look into W shape dynamic cable configuration performance in extreme environmental conditions. The sensitivity of buoyancy and cable length is evaluated, which provides information for future development of such kind of configuration.
Comparing Oilwell Cement Static Gel Strength Development by Ultrasonic, Intermittent and Continuous Rotation Measurement Methods
Authors: Ashraf Shameed , Muhamad Husin Rahmad Haidzar , Rizalman Awang , Bogaerts Martijn
Published: March 2022

Cement sheath integrity to prevent interzonal communication is closely related to the static gel strength. The API Standard 65-2 puts importance on the critical gel strength period (CGSP) measurement, which begins when the critical static gel strength (CSGS) is developed and ends when 500 lbf/100 ft2 is attained. The recommended duration for this period should be 45 min or less to be effective in isolating flow potentials. The API 10B-6 covers the three methods to measure the static gel strength development accepted in the industry, which are continuous and intermittent rotation followed by ultrasonic. A laboratory-based study is presented in this paper that compares these measurement methods.

The slurry frameworks chosen for the comparison ranged between 11.5 to 18 lbm/gal and the temperature extended from 27 to 121°C. The formulation of the fluid system consisted of Class G cement, silica flour, weighting agent, or light weight extender for the blended phase. Liquid phase additives such as antifoam, fluid loss, dispersant, and retarder were used. The formulations were adjusted to simulate two placement times, i.e., one between 3 to 4 hr. and the second between 7 to 8 hr.

The testing performed on the selected cement systems provided significant knowledge of the four different types of static gel strength development equipment used during the testing. There are two equipment's from different manufacturers operating using the continuous rotation method followed by one each for the intermittent rotation and the acoustic type.

The overall average transit time for each slurry and the respective standard deviation were arranged for ease of comparison. It was found that there are less deviations in certain fluid systems compared with some other systems. As indicated by the API 10B-6, each equipment may well result in generating different static gel profiles due to cement sample size, apparatus configuration, and formulation. Slurry formulations can be modified to improve their transition time depending on conditions as needed.
Intelligent Decision Making and Optimization of Artificial Lifting Based on MR Multi-Phase Flow Detection
Authors: Deng Feng , Chen Shiwen , Chen Guanhong , Wang Mengying
Published: March 2022

Quantitative information regarding multi-phase flow of oil, gas and water in wells or pipelines are very important in guiding the artificial lifting parameters optimization and tool selection. At present, there is no reliable technology available which can accurately measure split flow of multi-phase fluids without separating oil, gas and water. So far, the multi-phase flow measurement technique commonly adopted globally is to carry out by phase separation after produced fluid entering the gathering station through the pipelines, where the content of each component is measured separately. The indirect measurement methods are usually with low-efficiency, high-cost and delay-delivery, and hard to reflect the real instantaneous fluid producing properties at wellheads or pipelines. Therefore, it is urgent to seek for accurate and reliable multi-phase flow detection devices and methods that can meet the monitoring demands for oil and gas resources.

This paper proposed a nuclear magnetic resonance (NMR) device and analytical methods for detecting multi-phase fluid. At the same time, it puts forward the intelligent decision-making and optimization technology based on measurement, cloud computing and automatic control. As a green, efficient and accurate method for oil and gas detection, the NMR can realize online measurement for each component of multi-phase flow. Then based on the internet and large data analysis technology to achieve artificial lifting parameters optimization, while based on automatic control technology to achieve artificial lifting equipment negative feedback control.

This progress helps to apply the NMR technique in petroleum industry to achieve green, efficient, real-time and low-cost multi-phase flow measurement. Combined with large data, Internet of Things (IOT) and automatic control technology to achieve intelligent artificial lifting technology and system.
A Subsea Wellhead Annulus Seal Ready to Meet Challenging and Critical Endurance and Performance Needs
Authors: Potter Philip , Bornia Guaraci , NG Nicholas , Robbins David , Attaway Daryl , Amini Shakib , Zhu Baozhi , Wafai Ayman , Croucher Eric
Published: March 2022

This paper discusses the design, development and testing of an optimized subsea wellhead annulus seal. Historically annulus seal qualification and validation testing requirements are defined in API 6A and API 17D requiring a PR2F temperature and pressure cyclic test program, and x3 lockdown load cycles. Throughout the operational life of a production subsea wellhead, the annulus seal can be subjected to many start-up and shut-down cycles, leading to substantially more lockdown load cycles on the annulus seal than initially validated (OTC-30784-MS). Traditionally, it has been left up to operators to define their own requirements over and above API.

Operating conditions experienced by the annulus sealing system and the subsea wellhead equipment can be exceptionally challenging. Prior to landing and locking the annulus sealing system in place, the sealing surfaces of both the wellhead system and the annulus seal are subjected to a multitude of operational and environmental conditions such as cuttings/ debris from circulating well fluids, possible damage from lowering the annulus seal through several thousand feet of subsea riser and a BOP stack and misalignment of the seal during installation.

The annulus sealing system of the subsea wellhead equipment is a critical secondary well barrier for well control. Either in exploration or production mode, with the casing cemented in place, the annulus sealing system locks the subsea casing hanger into position, providing a metal-to-metal seal across the annulus of the intermediate casing. The purpose of the annulus sealing system is to ensure it does not unseat and lose integrity in the event there is any pressure from below the seal due to a leak, reduced hydrostatic pressure from above or from thermal expansion during the production life of the well.
Striving Towards Zero Gas Emission
Authors: Ariffin Mohd Hafizi , Guillory Ryan , Low Bee Chan , Salleh Fairus Azwardy
Published: March 2022

Greenhouse gas emission (GHG) is the main contributor to global warming, so the industry players need to take a huge step to reduce GHG. Furthermore, the implementation of carbon tax has eroded oil project values and drives teams to think about ways to reduce the carbon tax.

This paper highlights the subsurface studies, gas balancing method, and surface modification effort to reduce the gas emission in Field B while reaping the benefits not just of reduced carbon tax but increased oil production and revenue.

Gas injection is not just increasing reservoir pressure but also reduces emission. Several reservoirs in the field have been depleted by 66% to 500 psi. The team converted the existing oil wells to gas injection wells instead of spending high CAPEX to drill new gas injection well. This way the team can confirm the benefit of gas injection with a low-risk cash injection.

The field has a high amount of unproduced Non-Associated Gas (NAG), but this NAG cannot be produced without a gas evacuation plan. Producing the NAG will cause the field to vent higher with existing facilities installations. So, the team came out with a plan to monetize the gas by installing a new gas pipeline and new gas processing platform. Furthermore, the Associated Gas (AG) which was vented previously can be channeled to the new compression system to further reduce the emission.

Currently, the gas from the surge tank is lined up straight to the vent stack. A Vapour Recovery Unit (VRU) was proposed to install upstream of the surge vessels. The VRU will pump the gas back to an AG gas compressor and straight to the gas sales line.

The gas injection project has increased the reservoir pressure from 500 psi to 700 psi. As a result, one idle well reactivated to produce oil, two wells were drilled from the same reservoir, and gas venting was reduced by up to 7 MMscf/d. Because of this success, several other wells were identified for gas injection candidates in other reservoirs.

NAG gas project is expected to provide 100 MMscf/d revenue. In addition to that, the NAG project also helps to reduce AG venting because of AG compressor limitations. The additional AG volumes are around 5 MMscf/d.

VRU installation is still undergoing doability and commerciality study because the gas from the surge vessel is minimal. However, the team's dream towards zero gas emission is a step closer if VRU installation is brought forward.

Because the field is not well equipped with a gas meter for each piece of equipment. An accurate and understanding of gas balance estimation is important to drive zero gas emission.
Surface Casing Collapse Load Design Optimization Challenges for Highly Depleted Reservoir
Authors: Yap Yun Thiam , Wahi Wahidullah , Campbell Scott
Published: March 2022

In the current climate, cost reduction has been a major enabler for project sanction. With significant drilling activity planned in relatively benign environments offshore Malaysia, there were potential casing design optimisations, and hence cost reduction opportunities, in analyzing the relevant well planning data of such projects, with a view to further optimising the standardised 13-3/8" surface casing specifications that have historically been used in similar areas. Additionally, the feasibility of using 13-3/8" casing as slim conductor on platform development wells was investigated.

Well planning data for a variety of projects planned for between 2022 and 2024, which planned to use the same 13-3/8" surface casing specification, were collated and boundary conditions were established for all of the key parameters. This standardised casing string was first assessed for suitability, and areas for potential optimisation were identified. Simplified casing load analyses optimisation were performed on this optimised 13-3/8" casing specification for typical collapse loads as laid out in the company's casing design standards, to assess its suitability. Generalized fatigue life analyses were also performed on the slim 13-3/8" conductor to try to prove viability of the concept.

It was shown that collapse design is the controlling factor for the cost reduction initiatives through 13-3/8" casing specification optimization, especially in an environment of severely depleted reservoir (down to 3 ppg) in the reservoir section underneath the surface casing. This is exaggerated with conservative load assumptions that is used in the industry/company standards i.e., running mud weight, 50% to 100% evacuation, extreme low pore pressure assumption as low case prognosis etc. Combination of conservative collapse prohibited the casing specification to be optimized lower.

This paper addresses the 13-3/8" casing optimization through fit for purpose collapse design approach. It was shown that the reduction of the casing specification for 13-3/8" surface casing in the majority of the projects studied was justified and acceptable based on the minimum design requirements for collapse loads. Additionally, cost savings of up to approximately 7% were observed for this reduction in 13-3/8" surface casing specification depending on connection qualification and casing manufacturer.
Building a Sustainable Life Cycle Cost Efficiency Model
Authors: Kusumawardhani Mayang , Arnhus Magnus Soon , Markeset Tore
Published: March 2022

Life cycle cost (LCC) evaluation has been a powerful decision-making support tool for assessing different alternatives throughout an asset's life cycle. After having been ushered in by the global awakening of a sustainability conscience, there is a need to upgrade the LCC calculation to include these sustainability factors. This train of thought has also been acknowledged by the oil and gas industry, through the recent update of the ISO 15663:2021 (International Organization for Standardization), which addressed sustainability, in conjunction with other ISO standards, guides and the IOGP (International Association of Oil & Gas Producers) report.

Following this trend, the paper aims to present a sustainable LCC efficiency model for oil and gas facilities, particularly in the selection of the optimum equipment or package. To achieve this, the paper drilled down possible cost factors related to these concerns and offers a model that is required to remain relevant in the current conditions.

The LCC model presented was developed through a systematic research method, including trials, feedback loops and validation processes. Potential production risks were also factored in, so that the LCC would deliver the best possible value to the business. Finally, a step-by-step process in developing the LCC structure will be illustrated and explained in the paper.
The Role of Mooring Line Monitoring in an Effective Asset Integrity Management of Floating Wind Farm
Authors: Sha Yong , Feng Wei , Zhang Hui , Lim Frank , Natarajan Shreenaath
Published: March 2022

As offshore wind farm developments move into water depth above 60m, one of the greatest challenges is in designing cost-effective mooring systems capable of overcoming the added risks of more severe environments, complicated floating structure response, and turbine forces. The failure of a primary mooring component could lead to unacceptable consequences, including destruction or complete loss of assets, loss of continuous electricity generation, possible retrieval of destructed structure, and possible injury or loss of human life during maintenance. It is essential to ensure that mooring systems operate without failure.

Operators have recognized the importance of installing instrumentation such as GPS to monitor floating wind structure location. However, motion monitoring instruments have seldom been deployed on mooring lines of floating wind farm structures to capture dynamic response, which will govern the integrity of the mooring system and subsequently the whole floating wind structure. Measured data from these instruments on mooring lines allow an operator to determine when the limits of acceptable response, predicted by design analysis or scale model tests, could be exceeded in terms of strength and fatigue.

This paper describes the role of mooring line monitoring in an effective asset integrity management of floating wind farm and provide a typical procedure for the development of a fit-for-purpose mooring line monitoring program. Furthermore, this paper presents an advanced monitoring method to capture the dynamic response of the mooring line by a cost-effective and maintainable solution.
Casing and Cement Evaluation on Drillpipe: New Tool Acquires Well Integrity Data in Parallel with Existing Drillpipe Deplyed Operations from Drilling to Plug and Abandonment
Authors: Hawthorn Andrew , Steinsiek Roger , Rahman Shaela
Published: March 2022

Casing and cement evaluation logging has long been essential for the success and safety of well operations from spud all the way through to abandonment. Indeed, as the casing and subsequent cement play such a critical role in the separation of fluids and the provision of downhole pressure barriers it is essential and sometimes also a regulatory requirement to obtain such data. For example, understanding the condition of the casing, whether it is worn or corroded, and the material in the annulus behind the casing, such as cement, fluid, formation or even gas directly plays into the success or otherwise and also the safety of multiple well operations. Historically this information has only been available from wireline conveyed tools. As a consequence of this other rig operations then have to stop to allow the wireline logging. It is also true to say that over the last few decades wells have become significantly more complex, more deviated and deeper. In addition, the pressure regimes have required tighter margins increasing the risk of operations and necessitating a greater need to understand the integrity of casing and cement barriers. As the wells have become deeper, more complex and more highly deviated it is also more difficult to run wireline conveyed tools, often significantly increasing the amount of time required to run and obtain this data. In fact, it can be clearly seen that increasingly, operators have often declined to get this critical data due to the time and effort required in certain circumstances to log on wireline. This has had a significant impact in terms of non productive time associated with not understanding the condition of casing and cement in well operations such as side tracking or cut and pull operations.

For those associated with drilling then there has been a huge advancement in the technology, reliability and utilization of logging while drilling technology, although this has traditionally been employed in the openhole sections and deployed only while drilling. This paper will introduce a drillpipe conveyed casing and cement evaluation tool that can be deployed in parallel with other runs in the well to improve the efficiency of operations whilst also increasing the frequency of times that this data can be acquired. Through case history we will demonstrate how operators improved efficiency, reduced rigtime and personnel on board, improved the safety of operations and reduced the risk of non-productive time by the application of this new drillpipe conveyed technology.
First Experience Matters: Evaluation of Acid Treatment Recipe for Fines Migration Control in S Field Sandstone Reservoirs
Authors: Bakar Hasmizah , Ravichandran Narindran , Abu Bakar Mohamad , Idris Khairul Nizam , Masoudi Rahim
Published: March 2022

Restoring formation damage by acid matrix treatment in sandstone formations faces multiple challenges due to variable petrophysical and compositional properties. The S field team had carried out a formation damage study to determine the damage mechanism, evaluate the best acid treatment recipe to treat the formation damage mechanism identified and study the effect on petrophysical properties before and after the treatment. Most of the S field oil producers experienced rapid decline in production, and this is suspected to be due to fines migration and plugging.

The formation damage study is divided into three sections: the field background review, the potential formation damage identification, and the evaluation of the best acid treatment recipe for S field formations. Core samples from a wide range of mineralogy, permeability, pore distributions and porosity were evaluated using laboratory testing to describe the elemental and morphological presence of each mineral. Then, four of the core samples were high graded for evaluating the permeability by flooding with brine and oil to examine the fines migration and dispersion potential of clays and siderite. The next phase of this study was continued with the core sample acidization using organic acid and HCl to identify a suitable acid treatment cocktail. This will be discussed in detail in this paper.

Fines migration was observed to be resulted from movement of both siderite and aluminosilicate clays under representative conditions. The evidence from the geological analyses and core flooding shows that in brine, there is a tendency for siderite to migrate, potentially even at low flow rates. The effect is expected to be more severe in brine than in oil and possibly in both phases. HCl acid and strong organic acid treatments with and without the presence of an iron control to remove iron carbonates in siderites and iron-silicate gel formation will be outlined in this paper. The result of the HCl treatment was that it was able to remove carbonate material from the core, but it was still not able to substantially improve wellbore permeability. An additional short phase of testing examining a HF-HCl package was demonstrated more effective and is discussed extensively in this paper.

This laboratory work is not unusual to the sandstone stimulation however the discussion of the core flood testing findings and acid recipe comparative study provides more comprehensive understanding on the effect of fines migration to the success of the stimulation treatment and its effect on petrophysical properties. The outcome of this work will lead to a reliable design of sandstone matrix acid treatments and, increase the acid stimulation treatment success rate which subsequently optimizes well productivity.
Field X, Central Luconia, Offshore Sarawak, Malaysia, Early Appraisal Stage Reservoir Characterization
Authors: Poret Kelly , Saller Art , Henglai Puntira , Laitrakull Kasira , Chongrueanglap Pongsit , Siriwattanakajorn Warintaphat , Chris Platt
Published: March 2022

Miocene carbonates have been producing gas in Central Luconia for more than 30 years (Warrlich et al., 2019). Approximately 65 TCF of recoverable gas have been discovered to date in these build-ups (Scherer, 1980; Mahmud and Saleh, 1999; Khazali et al., 2013; Kosa et al., 2015; Warrlich et al., 2019). One of the most recent carbonate discoveries in this region, Field X, is in its early-stage of reservoir characterization. Depositional and facies models have been created with newly acquired data from LL-C appraisal well.

Tectonics, accommodation, and sea level contributed to the overall shape and deposition of the carbonate buildup. One appraisal well, LL-C was drilled and penetrated a thick carbonate section on the structure. With the available data, facies and conceptual depositional models were created using well logs, sidewall cores, conventional cores, cuttings, seismic, and an extensive literature review. At the time of this study, core laboratory analyses were not yet completed. The reservoir is separated into five zones based on well log, core, and seismic data. A precursory facies model was completed using only photographs from the sidewall cores acquired in all five zones of the structure and photographs from conventional core acquired in the upper reservoir interval. Five facies were identified: Coral, Packstone, Wackestone, Mudstone, and Cemented Margin. The data acquired in LL-C illustrates the complexity of carbonate reservoirs and the need to acquire core early in the appraisal of carbonate reservoirs.
Carbon Footprint Assessment for Decarbonisation Strategy Development
Authors: Jamal Hisne Fairul Izmal , Hughes Kayleigh Dawn , Su Li Yuen
Published: March 2022

As reported by the United Nations Framework Convention on Climate Change (UNFCCC), the quantity of atmospheric Greenhouse Gas (GHG) concentrations in the atmosphere has elevated by an average of 1.6% annually over the last three decades, primarily contributed by carbon dioxide gas (CO2), and is currently considered to be one of the top three issues facing the world today. Climate change, as a result of increased GHG concentrations are threatening adverse impacts to the natural environment, as well as human livelihood and survival. In response, international actions, such as the Kyoto Protocol 2005 and the Paris Agreement 2015, gathered nations worldwide to set targets with the intention of mitigating climate change and reducing its impacts. One such action is the movement towards ‘net zero’ CO2 emissions to be achieved by 2050. A commitment considered necessary by the Intergovernmental Panel on Climate Change (IPCC) for realising the goal of global temperature stabilisation to 1.5 °C above pre-industrial levels.

Increasing environmental, consumer and regulatory pressures, have driven the need for transitions in business focus towards sustainability by reducing overall GHG emission and carbon footprint. The integration of sustainability in business strategies is vital to avoid the occurrence of potential risks by demonstrating a clear link between the commitment to the sustainability agenda and continual business development. Undertaking a carbon footprint assessment of current and future assets is critical, to understand the nature of emission sources, and the contribution levels of each source to enable organizations to plan and make decisions which provide the most benefit in executing emission reduction strategies. The use of supporting tools developed in compliance with GHG Protocol principles, can provide clarity on carbon footprint drivers and enables informed, clear, traceable, carbon conscious, rapid decision making for business operations.

This paper will discuss how the application of digital tools allows for the development of baseline understanding of an organization’s carbon footprint. Further, the subsequent steps required in utilizing the baseline information to determine feasible carbon reduction strategies in a traceable, verifiable, and systematic manner, will also be explored.
Design of Mechanically Lined Pipe MLP for Lateral Buckle Zones – MLP Qualification and Calibrated Wrinkling Criteria Using FEA
Authors: Govindan Nampoothiri Sajith Kumar , Pawar Dipak , Mak Kok Wah
Published: March 2022

Mechanically Lined Pipe (MLP) is a pipe with a layer of corrosion resistant alloy (CRA) mechanically bonded to carbon steel pipe. MLP is mostly used in offshore pipelines for HPHT (high pressure and high temperature) conditions with corrosive contents. These type of pipe joints are largely used for HPHT offshore pipelines conveying corrosive fluids, but mostly limited to ‘non-buckle’ zones due to the concerns of liner wrinkling, fatigue damage and triple point failure resulting from high strain and stress ranges in the lateral buckle zones.

Recently, MLP's have been used for the entire length, including in the buckle zones of a dual HPHT multi-phase infield flowlines. Planned buckles have been designed at specific intervals to ensure controlled lateral buckling. Extensive qualification procedures are required to be undertaken to validate the use of these types of pipe at the buckle zones with high strains and stress ranges during repeated shut down cycles. The qualification procedure for MLP at the buckle zone are discussed in this paper. The paper also presents an optimized formula, calibrated based on the qualification procedure and Finite Element (FE) analysis for determining the optimized onset strain for liner wrinkling.

Initially, a thorough review of the concerns in the industry for employing MLP at the lateral buckle zone was undertaken and include the requirements for qualification/testing currently specified in the industry, such as bend test/liner wrinkling, and and full-scale fatigue tests.

Liner wrinkling is caused by excessive compressive strain that occurs during de-pressurisation of the flowline. To assess the risks of wrinkling, the compressive strain for the onset of liner wrinkling is evaluated using analytical calculations. This is followed by a comprehensive discussion on the qualification steps adopted for addressing the fatigue, triple point failure and wrinkle that enabled to use MLP at buckling and fatigue sensitive zones.

The qualification procedure undertaken has demonstrated better fatigue performance and wrinkling onset strains considerably higher than those evaluated analytically. The findings from the qualification and material tests are used to calibrate the ABAQUS FE analysis simulations to obtain optimised wrinkling onset criteria. An optimized wrinkling onset criteria for a range of D/t ratios defined based on Finite Element (FE) analysis results. In summary, this paper provides reliable guidance for the qualification of MLP at the lateral buckle zones. The paper also presents the methodology and results for determining an optimized strain for the onset of liner wrinkling based on ABAQUS FE analysis.
Defining the Optimum Well Completion for Marginal Field Development – An Approach
Authors: Syed Abd Rahim Syarifah Puteh Mariah , Azman Mohd Fairuz , Awang@Mohamed Zaidi , Ahmad Mior Yusni
Published: March 2022

Marginal field development commonly face setback when it comes to an investment decision, which makes it technically and commercially very challenging to be developed. Technologies that usually applied in big fields may not be economically relevant to the marginal fields, despite require the same assurance and functionality. Well completion cost itself can take up to 50% of the total well cost, especially for fields that potentially must deal with sand production, high CO2 and/or H2S content, artificial lift, and multilayer zonal completion and isolation. This paper demonstrates an integrated approach to identify and define the optimum well completion strategy for such conditions in a Malaysian oilfield.

The first step is to list all the operational issues and challenges of producing from the neighboring fault block and other analogue fields experience. Leveraging on the available data and types of completion that have been installed, a set of scoring is given to different completion type, considering the sand production control effectiveness, good well performance, and long well life span. The shortlisted completion types were further evaluated based on the following criteria:

Production flexibility Early monetization Operation complexity (drilling and completion) Sand production management Sand control failure probability Associated Risks Stand-alone economic

As a result, eight (8) completion strategies were investigated namely Monobore, Monobore wih resin, Cased & Perf, Cased & Perf with resin, Open Hole Stand Alone Screen (OHSAS), Cased-Hole Stand Alone Screen (CHSAS), Cased-Hole Gravel Pack (CHGP); using circulating method or frac pack. Different completion has its own advantages and disadvantages. Structured scoring system was again applied to guide the decision-making process. The key elements in the decision thought process are the associated cost of each option, the skin factor that affect the production and reserve estimation, and ultimately the Net Present Value (NPV) indicator.

In conclusion, identifying the optimum well completion will never give a single solution answer. However, the most important thing is to consider all the decisive factors and properly evaluate all options. In our own real example, the option that gives the best NPV coupled with tolerable risk (HSE risk i.e. less issue at surface) was selected as the optimum well completion strategy to be used in the development plan.
Cementing the First Australian Offshore Carbon Capture and Storage Appraisal Well
Authors: Lyons Ariel , Sheikh Veisi Mahdi , Salehpour Amir , Azwar Cinto , Ashraf Shameed , Duthie Lynden , Marshall Steven
Published: March 2022

Analysis has consistently shown that carbon capture and storage (CCS) has an important role in meeting emission-reduction targets (IPCC, 2018). CCS wells require special design considerations to ensure long-term zonal isolation when exposed to carbon dioxide (CO2) because a complex set of chemical reactions leads to carbonation and dissolution of conventional cement sheaths.

Several studies conducted into the long-term stability of different cement systems when exposed to wet supercritical CO2 and CO2-saturated water showed that the novel CO2- resistant cement system provides enduring zonal isolation. Properties investigated included permeability, porosity, mass evolution, CO2 degradation front, and compressive strength. Given its superior mechanical properties, the novel CO2-resistant cement system was selected for use in the first Australian offshore CCS Gular-1 appraisal well.

To ensure that the blend characteristics of the novel CO2-resistant cement system remained optimal, a stringent quality-control procedure was developed. The blend management process, supported by rigorous laboratory testing, covered the complete lifecycle of the blend. This lifecycle extended from sourcing chemical components, to blending the components in a bulk plant, to transporting the blend across land and sea, and ultimately, preparing the slurry mixing.

By adhering to the project management process, all primary cement jobs were successfully performed without incident using conventional cementing equipment and practices. The novel approach of blending the product locally at a fit-for-purpose facility reduced costs compared with previous methods of importing a preblended product prepared at a special centralized facility. Blend homogeneity was maintained during transfer from a sea vessel to the jackup rig, with minimal change in density between samples received from the bulk plant and samples received from the rig. This blending, which verified the initial blend flow capability and the robustness tests performed at a regional laboratory using specialized equipment, concluded the blend is suitable for offshore operations.

Selection of a suitable cement system to ensure long-term zonal isolation will prove essential to the continuing expansion of the CO2 injection market. Through this offshore CCS appraisal project, valuable best practices and lessons learned in design and execution have been captured. This paper presents the decision process used for selecting a suitable CO2-resistant cement system for Australia's first offshore CCS appraisal well, drilled by AGR as part of the CarbonNet Project in late 2019, as well as the project management processes implemented to ensure successful job execution. The experiences detailed in this paper will benefit other operators confronted by challenges associated with wells subjected to CO2 injection.
World'S First Successful Dual String Installation of A Digital Intelligent Artificial Lift DIAL – Interventionless Gas Lift Production Optimization System, Offshore Malaysia
Authors: Rozlan M Rizwan , M Ghazali M Haziq , Bakar M Farris , Ishak M Faizatulizuddin , Samuel Orient Balbir , Misron Mohd Al Perdaus , Ismall Mohamad Sazwan , Salleh Nurfarah Izwana , Rizwan Badroel , Amara Abdel Ben , Faux Stephen , Ahmad Azhari Ahmad Hafiz , Anak Muara Azis
Published: March 2022

PETRONAS completed well H-X on B field in Malaysia with a Digital Intelligent Artificial Lift (DIAL) gas lift production optimization system. This DIAL installation represents the first ever successful installation of the technology in an Offshore well for Dual String production. This paper provides complete details of the installation planning and operational process undertaken to achieve this milestone.

DIAL is a unique technology that enhances the efficiency of gas lift production via downhole monitoring of production parameters informs remote surface-controlled adjustment of gas lift valves. This enables automation of production optimization removing the need for well intervention.

This paper focusses on a well completed in November 2020, the fourth well to be installed with the DIAL technology across PETRONAS Assets. The authors will provide details of the well and the installation phases: system design, pre-job preparations, improvements implementation, run in hole and surface hook-up. For each phase, challenges encountered, and lessons learned will be listed together with observed benefits.

The DIAL system introduces a paradigm shift in design, installation and operation of gas lifted wells. This paper will briefly highlight the justifications of this digital technology in comparison with conventional gas lift techniques. It will consider the value added from the design stage, through installation operations, to production optimization.

This successful installation confirms the ability to implement the DIAL technology in a challenging dual string completion design to enable deeper injection while avoiding interventions on a well with a greater than 60-degree deviation. With remotely operated, non-pressure dependent multi-valve in-well gas lift units, the technology removes the challenges normally associated with gas-injected production operation in a dual completion well – gas robbing and multi-pointing.

Despite the additional operational & planning complications due to COVID-19 restrictions, the well was completed with zero NPT and LTI. Once brought online, this DIAL-assisted production well will be remotely monitored and controlled ensuring continuous production optimization, part of PETRONAS' upstream digitization strategic vision.
The Future of Zero Continuous Flare Operation at Greater Bongkot North Field
Authors: Nunthaworrarat Rattachai , Srivaranon Suchart
Published: March 2022

The Greater Bongkot North (GBN)'s condensate stabilization system initially utilizes multi-stage flashing concept through the multi-stage separators. Most of the flashing gas at the last stage separator could not be recovered as being operated at very low pressure (0.05 barg) resulting in the continuous flaring through Low Pressure (LP) Flare Header at the Production Platform of the GBN since 1st operation day. Recovery of the unrecoverable low-pressure gas has been unsolved since then.

Regarding lower gas nomination forecasted and exported condensate rate in low condensate production mode, LP flare rate is being simulated at 1-3 MMSCFD whilst the existing condensate and gas recovery system shows the available capacity left over even the field potential is maintained. This information energized the opportunity of Recovery Scheme by boosting the pressure of LP Flare Gas and feeding the recovered gas to the existing FGRU compressor within the minimal modification scope. Entire feasible recovery options had been technically examined including essential requirements of modification to evaluate the Pros and Cons on each development scenarios.

Key engineering challenge on recovery of the low-pressure heavy flare gas is the closed recirculation of recovered hydrocarbon which wastefully occupies the system capacity. Selection on the returning point of the recovered gas is crucial to minimize the recirculation while increasing production yield. The selected option provides less modification works whereas the entire recovered gas feeding back to the existing FGRU compressor is feasible while the existing facilities at its maximum capacity are utilized and new equipment installation requires only one (Wet Screw) compressor and one liquid recovery (Vertical in-line centrifugal) pump. Each equipment was technically selected through evaluated technical specifications and limitation of installation spaces. Furthermore, the installation scenarios on the aging production platform are key challenge as deck extension, which new equipment are installed, is heavy-lifted, and installed on the existing lower deck of Production Platform using the available margin of platform load on the existing piles. Cost estimation is conducted together with economic evaluation for investment decision. The project is budgetary approved providing an attractive positive NPV. The economic evaluation results in positive NPV mainly due to the condensate gain from the flare gas recovery insisting that greenhouse gas reduction project could be performed in the techno-economical way.

The implementation of GBN New LP Flare Recovery scheme will soonest be getting started by FEED and Construction phases accordingly to shape up essential details of required engineering aspects to make the start-up of this project meets the timeline supporting Sustainable Development framework (Green-house gas reduction) as PTTEP strategic directions.
Perforating Docking System for Efficient High-Volume Operation
Authors: Jumaat Mohd Shafie , Wattanapornmongkol Sawit , Wattanachai Sorawit , Konglumthan Kontron
Published: March 2022

The Gulf of Thailand is developed with a high volume of slim monobore wells, producing from multiple thin reservoirs. The high volume of wells enables sufficient production output, but their costs must be well managed for overall field economics. An important cost component comes from the perforating operation that involves several runs of guns on electric wireline, and on each run consists of several guns that are activated sequentially using switches. This process of perforating multiple zones in a well, if not managed, will lead to extended operational time or worse, leading to serious problems like off-depth perforation. Additionally, the temperature of the wells averaging at 370 degF poses an additional challenge to the operations.

The efficiency of operation is paramount in achieving better well economics. Hence, several operational and technology optimizations were performed over the years to achieve several incremental in efficiency. Incremental improvement is always valuable in such a high-volume operation involving thousands of perforating runs annually. However, the gain is even more pronounced when a step change in efficiency is achieved, and this has been observed in the new gun docking system engineered for the high-volume market in Thailand. It enables quicker connection of multiple guns on the surface with better safety and reliability.

This paper discusses the background of the high-volume perforating in Thailand and the need for efficiency, which led to the development of this new gun docking system tailored for this market. This docking system technology is presented together with the statistics of its deployment in over 300 perforating runs to date and compared to the statistics of the previous system. The efficiency achieved comes from its quicker connection and arming system, combined with its better safety and reliability that lead to a lower misfire rate.

The success of its deployment and more importantly, its step change in efficiency may pave ways for more marginal fields to be developed globally. Additionally, as thousands of perforating runs are performed globally, its efficiency will also play a vital role in shortening operational times and contribute to lower global carbon emission.