bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study of Managing Surplus Surfactant-Foam Generated from Foam Assisted-Water Alternating Gas
Authors: Borhan Noorazlenawati , Saadon Shazleen , Hassan Almila 
Published: March 2022

ABSTRACT
A comprehensive series of experiments on foaming of two (2) types of crude oil and four (4) types of synthesized Gemini silicone- amine base defoamer in simulated produced water system containing foam surfactant Foam Assisted-Water Alternating Gas (FAWAG) package were investigated under the influence of column temperature at 30 – 60 °C, applied pressure of 1 – 4 bar, and fixed fluid flowrate of 0.5 L/min. In this study, the presence of high saturates composition in the crude oil which at 45 – 75.8 % influence the foam stability of the fluids. This reflects the waxy types of crude oils with higher density properties of 0.8768 – 0.858 Kg/L and increase concentration of foam surfactant from 30% to 90% in the produced water system influences the foaming stability. The microscopic observation shows that bigger bubble size about the average of 400 – 500 µm would slows down the liquid drainage, resulting in foam stability behavior. Defoamers with various structures ranged from amine short-chain, amine long-chain, amine branched-chain and amide-chain were analysed to determine the effect of molecular structure at various concentration from 5 – 40ppm. The defoaming ability was determined by foam height and collapse time. The amide short-chain and amine branched –chain had excellent foam breaking performance which was observed from the mean bubble size reduction to 50 – 100 µm resulting from formation of unstable bridge across lamellae causing the foam to rupture, allowing faster liquid drainage, thus improving suppression performance.
U-IMAGe: An Optimised, Efficient and Cost Effective Approach to the Inspection and Maintenance of Upstream Facilities
Authors: W Shafie W Hariz Fadli , Khan Riaz , Mahmood M Rashdan , Mohd Ali Mazri , Zubir Hafiz Azzad , Kamal Girish Chander 
Published: March 2022

Abstract

Objective
The key objective of this paper is to present the methodology of the Upstream Inspection, Maintenance and Assurance Guideline (U-IMAGe) and its implementation across a fleet of ageing assets. The U-IMAGe has been developed within PETRONAS’, Upstream Operational Excellence (OE), Center of Excellence (CoE). The U-IMAGe provides a flexible, efficient, cost effective new way of inspecting and maintaining current assets and equipment, without compromising the inherent safety and health of the asset. The U-IMAGe is applicable to Upstream assets, facilities and equipment including disciplines such as wells, pipelines, structural (offshore, fixed and floating and onshore), electrical, instrumentation, telecommunications, process, storage tanks, mechanical static, rotating equipment, subsea, single point moorings and piping systems.
Autonomous Robot in the Field of Inaccessible Piping System Inspection
Authors: Al-Hannabi Abdoulelah Naji , Rehman Aziz U. , Al-Munif Yousef A. , Al-Musabbeh Kazem Hussain 
Published: March 2022

Abstract
Autonomous inspection robots have emerged as a theme in the digital transformation era, under the umbrella of industrial smart plants for their claimed superiority, safe operation, and cost-effectiveness. Autonomous inspection robots play an essential role in inspecting inaccessible pipelines and process piping, due to their great maneuverability to traverse various bends and geometries, e.g., elbows and T-joints. Saudi Aramco Inspection Department, in collaboration with Shaybah Producing Department, conducted a field trial of an autonomous robot to apply multiple inspection methods simultaneously, in an inaccessible 30" gas pipeline. The robotic system is equipped with motored magnetic wheels to enable movement inside the pipe and can hold the inspection system at certain pre-defined coordinates. The pilot study concluded that the autonomous robot provides accurate corrosion mapping and performs different inspection simultaneously. In addition, the robot has demonstrated great maneuverability inside the pipe in all orientations, i.e. axial, circumferential, and in between. The system has shown a strong potential to inspect inaccessible piping system while minimizing extremely expensive practices, e.g. scaffold erections, excavations, in a timely manner, with ease on logistics and labor.
The use of autonomous robotic scanner provides the operating facility with an option, which is cost-effective and requires a single deployment to complete multiple inspection tasks. The system is capable of replacing the current practice of deploying multiple technologies for a complete inspection inside the pipeline. The system is a self-contained inspection robot that conduct various inspection functions simultaneously, including: Optical Video System, Ultrasonic Guided Waves, Ultrasonic Shear Wave and Ultrasonic Corrosion Mapping with dry-point contact transducers. The system will detect flaws, identify their type and measure the parameters of the pipeline's base metal, welding defects, and provided detailed information and data on the condition of the examined assets, while internally scanning the pipeline. The robot requires, minimum clean-up, and has great maneuverability to go through various bends and geometries, i.e. elbows, T-joints, etc. The autonomous robot can be inserted through the available manhole hatches. The robot is wireless capable and can reach up to 1,000 — 1,500 meters inside the pipe, while being controlled and inspection data is received continuously in outside control room.
Extending the Life Cycle of Old Wells: Fracturing and Replenishing Formation Energy at the Same Time
Authors: Chunpeng Wang , Weiyao Zhu , Weixiang Cui , Min Zhang , Xueqin Huang , Shuzhe Shi , Zhen Nie 
Published: March 2022

Abstract
In order to extend the life cycle of the developed oilfield and ensure the stable production of the oilfield, the exploration and practice of supplementary energy refracturing has been carried out in a small block in eastern China which is on the verge of shutdown since 2017. All of the well in this block are vertical wells. This technology breaks the injection production relationship of the original well pattern. The injection wells and production wells are fractured at the same time. Fracturing fluid is not only used for fracturing, but also for supplementing formation energy. In order to produce more new fractures and make them more complex, low viscosity slippery water is used in hydraulic fracturing. It ensures that the material cost is reduced while the amount of fracturing fluid is increased. In addition, the multi-stage proppant combination is used to support all levels of fractures, which improves the conductivity of all levels of fractures. During the implementation of refracturing, the amount of fluid used in single layer is gradually increased, from 2300 to 3500 cubic meters, the maximum amount of fracturing fluid injected in single layer is 10000 cubic meters, and the proportion of slippery water is increased from 80% to 95%. The proppant is composed of 100/140 mesh and 40/70 mesh ceramic proppant, with an average sand content of 97.7 cubic meters per layer. From the perspective of construction data, after increasing the amount of fracturing fluid used in single well, the average pump stopping pressure of the later batch of construction wells is increased by 3.5 Mpa and the construction pressure is increased by 4.5MPa. After adding temporary plugging agent, the average construction pressure increased by 1.8 MPa, and the opening characteristics of new joints were obvious. After refracturing, all test wells are produced by automatic injection production, the total number of automatic injection production days is 5.2 times of the initial fracturing, and the cumulative oil production is 1.5 times of the initial fracturing. Through practice, the original injection production relationship is broken. Increasing the amount of fracturing fluid can not only supplement the formation energy, but also improve the complexity of fractures. The multi-stage proppant slug can significantly improve the conductivity of fractures at all levels, prolong the life cycle of old wells, and provide technical support for multi thin layer reconstruction.
Robust ASP Flooding Optimization Under Chemical Properties Uncertainty Using Markov Chain Monte Carlo Optimizer
Authors: Wa Wee Wei , Oscar Vazquez 
Published: March 2022

Abstract
The paper presents Alkaline, Surfactant and Polymer (ASP) flooding optimization work under the uncertainties in chemical components’ properties in order to assess the risk in simulated incremental oil recovery value associated to uncertainties in chemical components’ properties.
Uncertain chemical properties for ASP were identified from published coreflood works and were defined in range instead of as discrete value in the simulation model. 100 chemical properties realizations were generated in the study based on the range of these key uncertain chemical properties and nine representative chemical properties realizations were selected based on the total oil recovery. Robust optimization work was performed using Markov Chain Monte Carlo (MCMC) algorithm to determine the optimum ASP flooding design parameters, namely time to start ASP injection, main ASP slug size, post-flush polymer slug size and ASP concentration that gave highest Net Present Value (NPV) for all the nine selected chemical realizations. Optimized ASP design parameters was eventually run on 100 initially generated chemical properties realizations to generate NPV cumulative probability plot. Nominal optimization workflow that based on single chemical properties realization was used to generate another set of optimized ASP design parameters and the NPV cumulative probability plot generation was followed on the same 100 chemical properties realizations for comparison purpose.
The sensitivity of identified uncertain chemical properties on incremental oil recovery is demonstrated in the paper. Both nominal & robust optimization workflows improve the project NPV value compared to base case ASP design, with robust optimization showing further improvement over nominal optimization in all chemical realizations as expected. The spread in NPV clearly illustrated the risk of ASP flooding design related to uncertainties in ASP chemical properties. In this project, the exclusion of chemical properties uncertainties in optimization work led to the underestimation of ASP oil recovery performance.
The study is novel as while there were uncertainties in ASP chemical properties reported from laboratory core flood tests or core flood history matching simulations and presence of dynamic chemical adsorption behaviour under different chemical concentration combination, most of the published ASP optimization simulation studies has considered single chemical properties realization in their simulation models. The impact of uncertainties in chemical properties on simulated ASP oil recovery profile is demonstrated in this paper.
Integrated Hub Roadmap Adds 18 Years to Operational Life: Case Study from Gas Hub in Sarawak
Authors: Adnan Nur Izzati Izureen , Shazlina Intan , Sinha Ankaj Kumar , Faisal Ahmad Hisyam , M Sobri A Nasir 
Published: March 2022

Abstract
One of the key objectives for late field life management is aimed at unlocking production volumes below pipeline turndown rate (TDR). This can be achieved through new subsurface opportunities to keep total hub production above TDR and through operational management strategy to unlock below TDR volumes. This paper presents a reflection of technical studies conducted to extend hub production life and value creation for all stakeholders through technical due diligence, cost compression and operational excellence strategies.
Hub-A caters to production from two carbonate gas fields in Sarawak region and needs to maintain total production &gt;120 MMscf/d to meet pipeline TDR. The hub was expected to go below TDR in Year-2022 and to sustain the hub production beyond 2022, attic gas volumes in one of the feeder fields were identified for future development to potentially add incremental gas production to the hub and extend operational life by 2.5 years. However, based on techno-commercial assessment, the project wasn't considered viable for development.
Additionally, recent production performance indicated sharp increase in water-gas ratio from existing fields with the outlook indicating an early timeline for hub production to go below TDR. This necessitated several surface studies to be commissioned for hub protection with the primary objective of assessing technical feasibility to continue production below TDR limit. These studies focused on flow assurance studies for main trunkline & satellite pipelines, corrosion study for pipeline remnant life assessment, operating philosophy for production management and capacity assessment for onshore facilities.
For long-term roadmap, future gas feeders were also identified for hub sustenance beyond cessation of production from existing fields.
With the implementation of short-term and long-term production strategy as part of operation & management philosophy, ~26 MMboe of below TDR volumes from existing fields are expected to be unlocked and the hub producing life is expected to be extended by &gt;6 years with significant reduction in operational expenditure. Additionally, exploration roadmap has been strategized in synergy with hub outlook to provide long-term gas supply until 2040.
This is expected to generate significant value through continued revenue generation and keeping the hub in operable conditions for future tie-ins from new feeders and nearby gas field developments.
This paper presents novel operational strategy to unlock below pipeline TDR volumes for late field life management and integrated roadmap development for long-term value creation with synergy across exploration and development portfolio in the region.
Contact Determination in Cased Hole Wells by High Frequency Pressure Gradient Survey
Authors: Eriksen Klaus , Bakar Nasrul Hisham B. 
Published: March 2022

Abstract
Understanding the current oil-water, gas-water and gas-oil contacts (‘OWC’, ‘GWC’ and ‘GOC’) in a mature reservoir for planning well interventions, re-completions, or drilling infill wells is an essential part of the subsurface investment decision. Traditionally this is done by running conventional cased hole logging tools in existing wells when information from open hole logging in recently drilled wells is not available. However, in some reservoirs, the cased hole logging may yield ambiguous or erroneous results when determining the fluid contact. For example, when a well has a poor borehole condition or the target reservoir was laminated and/or of poor quality.
When a well is shut in, the fluids in the wellbore gradually equilibrate and a set of localized OWC and GOC will develop within the wellbore itself. These fluid contacts are generally not representative of the contacts in the reservoir; however, across the perforated intervals, the fluid redistribution will behave differently and the fluid column across the perforations will gradually equilibrate with the fluids in reservoir. As an example, if the well is perforated only across the oil column, then fluid across the perforation interval after equilibration will also be oil and the pressure gradients and capacitance log response within the well across this perforation interval will be representative of the oil gradient within the reservoir. Equally, if the free water level (FWL) and/or the GOC is situated within the range of perforated interval on a well that is shut in, then these contacts will also be present within the wellbore at the same depth as they occur in the reservoir, after the fluids within the well and in the reservoir have equilibrated. It is therefore possible to measure the FWL and the GOC across the perforation interval within the wellbore that are representative of the current fluid contacts within the reservoir, provided there is direct lateral hydraulic communication between the reservoir and the gauge as well as vertical communication within the reservoir across the perforated interval. As with any other cased hole logging methods it is also a requirement that the well does not exhibit active cross flow from other zones which would disturb the fluid equilibrium around the wellbore.
This paper presents a new method using a high-resolution static gradient survey (HRSGS) across the perforated intervals to acquire fluid contacts with a high level of precision, irrespective of the reservoir and well bore factors that influence the accuracy of conventional cased hole logging tools. The method has been implemented in the Seligi Field operated by EnQuest in Malaysia and has proven itself as a reliable new way of determining the current GOC and the current FWL. Results from this method are currently being used to determine where there is sufficient oil column in the field for the drilling of horizontal wells and for assessing investment opportunities with existing wells.
Delivering a One Phase Well Under Two Days with a One Inch Cutter PDC Drill Bit: A Record Breaking Performance in Mature Field, Drilling Optimization Case History
Authors: Sayogyo Bramarandhito , Hermawan Aditia , Andoni Bastian 
Published: March 2022

Abstract
Mahakam Block is a huge oil and gas concession managed by PT. Pertamina Hulu Mahakam (PHM) and located in deltaic and offshore environment in East Kalimantan, Indonesia. Until today, the field has produced oil and gas for more than 50 years and categorized as "brown field" due to its declining production and marginal reserve potential. This condition has led to numerous effort to boost efficiency in well delivery from drilling perspective such that the reserve could be produced more economically.
One of the effort that has been done to create a well to be more economical is by increasing the Rate of Penetration (ROP). An increase in ROP would directly impact on well duration that could be finished faster in such that it would also impact on much lower well cost. There are several key factors that influence ROP, yet the most crucial part is coming from drilling bit design that is used to drill the formation. Incompatibility between bit design with formation and directional drive type would often result in slow drilling progress and thus would make a well less profitable. To support this idea, the operator has launched a campaign called MAXIDRILL with aim to have a persistent excellent drilling performance from ROP perspective. Selective approach to different bit designs and bit suppliers has brought the operator to conduct the first trial in Indonesia utilizing a one inch PDC cutter drill bit.
Besides the effort to increase well economics by increasing ROP using various bit designs through MAXIDRILL Campaign, PHM also tries to implement new set of well architecture dedicated specifically for developing the shallow hydrocarbon zone in Mahakam in general, and in Tunu Field in particular. With this new type of architecture, it allows drilling with 9-1/2″ hole to be done straight from 20″ Conductor Pipe down to well final target depth in single phase, where next 3-1/2″ production tubing will be run and cemented in place. The new design of architecture is called "One Phase Well". This novel innovation was initiated in 2019, where to date, the operator has drilled more than 30 wells without any incident.
With the learning curve that has turned into industrialization steps. More and more shorter well duration is born with these two initiatives, MAXIDRILL and One Phase Well. Ultimately, with the spirit of these two initiatives for bringing down well duration in gain for much better well economics has successfully set a two record breaking performance in Mahakam: 1) Being the fastest On Bottom ROP and 2) Being the fastest well ever delivered in Mahakam and Indonesia which is under two days.
Practical Approach to Address Pitfalls of High-Resolution Numerical Simulation Modeling in Advanced Completion Design Optimization Today
Authors: Yew Zhen Xuan , Tan Chee Seong , Wa Wee Wei , Goh Gordon 
Published: March 2022

Abstract
Application of downhole flow control device (DFCV) has proven to be a successful strategy to mitigate early water or gas breakthrough in many fields in Asia. A conventional numerical modeling workflow is often applied in such studies. However, the full potential from the downhole installation is often not explored due to several numerical oversights in failure to adapt to the unique operation requirements and DCFV hardware design representation. This paper presents a practical approach to address pitfalls involved in high-resolution numerical simulation DFCV design optimization.
In this paper, a multi-stage procedure is highlighted involving a numerical simulation model prepared for DFCV design and optimization. The first step is to investigate the grid resolution from the 3D model. This is to ensure the effect of grid-to-well resolutions from coarse scale to finer scales to capture the device behavior along the open hole (OH) length of horizontal wells and to capture the gas and water influx from contact. The second step is to design and optimize the packer placement based on permeability contrast as primary reference using a practical approach by setting the number of packers as a sensitivity variable with uniform DFCV setting design. It is then followed by an unbiased design workflow is to optimize benefits of all kinds of DFCV such as nozzle-based and viscosity dependent inflow control devices of zonally varying setting or optimal configuration designs.
The practical approach is demonstrated on a synthetic simulation model with a horizontal well to address the oversights in modelling prior to DFCV design and optimization process. Based on this work, vertical grid resolution to oil thickness ratio exceeding 1:32 amplified the differences in results due to numerical dispersion problem. For packer location optimization, several sensitivities of different packer placements and number of packers were performed to compare the oil cumulative incremental. The optimum number of packers with uniform DFCV design is 19 packers, however the oil gain will be decreased once the number of packers is reduced. Finally, the practicality of applying a global optimization algorithm to such studies during real-time operations was investigated.
A unique practical approach is presented to address pitfalls involved in the needs of high-resolution numerical simulation in DFCV optimization. This approach captures the complex physics and resolution involved while ensuring the design loop efficient enough to perform fine-tuning during run-in-hole or on-the fly design onsite. In addition, this design optimization workflow is possible due to the availability of a new standard advanced reservoir simulator, that is cloud-compliant and has efficient multi-core parallel processing which otherwise would take days if not weeks conventionally to complete the task, deemed unsuitable for near real-time design or fine-tuning needs.