bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improvement Drilling Efficiency by Using Mud Motor and Agitator Bha in 6 1/8-in. Hole: Gulf of Thailand
Authors: Toasudjai Natsuda , Lordkratok Chanya , Fecho Kelly , Tipdontree Poppoom 
Published: March 2022

Abstract
In the Gulf of Thailand (GOT), deep directional drilling wells are planned with two runs using motor and adjustable-gage-stabilizer (AGS) bottom hole assembly (BHA) in the 6-1/8-in. hole section or the rotary-steerable-system (RSS) BHA. However, the cost of the RSS is not economical for some wells. The paper discusses the challenges of drilling in the high temperature environment and explains the engineering and analysis that resulted in a one run hole section with a motor BHA.
The extreme temperature elastomer (XT) motor was paired with an agitator system to facilitate the transfer of BHA weight for effective weight-on-bit (WOB) while sliding in long tangent or curve for great depths and temperature more than 150 degree Celsius (⁰C) well. Exhaustive BHA analysis, namely hydraulics, drill-string torque-drag and various sensitivity studies were performed for optimal placement of the agitator and shock sub in the BHA for the best friction reduction and least damaging vibration effect on BHA components. The simulation capabilities were enhanced by trail runs, analyzing historical performance and empirical data to implement step change improvements in the next BHA.
The XT motor with agitator-system BHA enabled smooth sliding and fast rate of penetration (ROP) across the entirely true vertical depth (TVD) range of the 6-1/8-in. hole. There was no BHA hanging up when sliding in deep sections of the well, demonstrating stable tool-face control while sliding, which translated to an overall efficient penetration rate. The 6-1/8-in. hole sections drilled with the XT motor and agitator-system BHA demonstrated 30 percent (%) faster ROP than similar TVD sections drilled with a motor without an agitator-system BHA. For example, a 6-1/8-in. hole with 1360-meter (m) drilled in long tangent at 41degree (°) inclination was successfully drilled in one run from shoe to 2584m MD of the well TD in 27 hours, with an average on bottom ROP of 51 meter per hour(m/hr).
Enhancing Oil Recovery in a Brown Oilfield of Offshore South China
Authors: Liu Wubo , Gao Xiaofei , Li Qingquan , Guo Yi , Yu Lei , Wang Chao , Chang Botao , Wang Fei , Li Shuzhong , Shim Yen Han 
Published: March 2022

Abstract
Located in offshore South China, XJ oil field entered the mature development phase after more than 20 years of production, with the water cut of the field increasing to 93%. A new strategy was executed starting in 2018 that targeted the remaining oil column, which was being squeezed by a strong bottomwater. One of the biggest challenges was the high uncertainty of the oil/water contacts in the current reservoir state. After reviewing the technical and geological challenges encountered, we will describe the successful approach taken to optimize the remaining reserves recovery using innovative horizontal well placement strategies.
Using a few case studies, we will illustrate how we executed this innovative well placement strategy. This includes landing the horizontal wells at the upper part of the reservoir with low incident angle, drilling the horizontal sections close to the top of target zones using a reservoir boundary detection tool, and using a continuous packer for the well completion to reduce the water cut. In addition, we will describe how the team evaluated and selected logging technologies in the planning phase for proper well placement.
The two cases discussed in this paper are based on horizontal wells completed using the following new strategy: maintaining a long lateral section in the upper layer of a predefined target, following the undulating structure while mapping the thin sandstone, keeping the trajectory in the target zone, etc. To ensure that each horizontal well could meet the target productivity index planned, real-time data were used in reservoir modeling to determine the required lateral length of each horizonal well. With the purpose of controlling water cut and improving oil recovery in these laterals, a new completion assembly, including a perforated liner with special completion material that prevented water from entering the liners, were installed in selected intervals according the logging data interpretation. Several observations will be highlighted, including:
Real-time logging data can effectively evaluate the reservoir properties and structural changes along the lateral Optimum well placement in the lateral section is critical for draining the remaining oil column An optimized completion design based on real-time reservoir evaluation.
The performance of the wells drilled to date shows that the production increased from 1,000 to 3,000 BOPD with zero to very low water cut. A reversing production trend from a declining trend to a growth trend is recorded. The successful implementation of the new strategy and the application of fit-for-purpose technologies in mature oil fields lead to improved production and increased oil recovery.
Weathering Uncertainties in Oil & Gas: Challenges and Design Optimization of High Contaminant Gas Field
Authors: Mustaffa Norlelawati , M Norpiah Rohaizad , Awang Bakar Dyg Amalina Azzyati , M Nazori Qurratuaini , Agus Muliadi 
Published: March 2022

Abstract
Typically, for a high volume, low condensate-gas ratio offshore gas production field having high content of carbon dioxide (CO2), hydrogen sulphide (H2S), mercury and solid particulates having to meet Liquified Natural Gas (LNG) inlet specification would require an enormous facility exceeding the largest available floatover vessel capacity. Aside from an enormous and complex processing facility, it would also require a large emergency disposal system and sour service pipeline material to cater for start-up and process excursion scenarios. In order to obtain a commercially attractive solution while meeting technical integrity and designing for operational excellence in mind, several innovative design approaches were implemented. The scope of this paper will cover major optimization implemented at gas treatment system, emergency blowdown system, export gas pipeline, and venting system at receiving platform.
Fine Characterisation of Remaining Oil Using Time-Varying Numerical Simulation: Experimental Study, Characterisation in Model, and Application in QHD Oilfield
Authors: He Yifan , Liu Yingxian , Cai Hui , Chen Xiaoming , Chen Jing 
Published: March 2022

Abstract
For water-flooding oilfields, both indoor experiments and mine field practices have confirmed that long-term water flooding can change physical properties, wettability, and fluid parameters. The comprehensive performance of these changes is that the relative permeability curve of oil and water changes dynamically. Usually, numerical simulation does not consider the change of reservoir properties, which will cause the mismatch of history matching. This error is especially obvious in the high water-cut period. It further affected the understanding of remaining oil and the prediction of subsequent production. Therefore, time-varying numerical simulation is required for fine numerical simulation in high water cut period to improve the accuracy and reliability of model prediction.
In order to solve the above problems, a set of fine reservoir numerical simulation process integrating core experiment, logging, dynamic and geological knowledge was established. The specific workflow is as follows:
The data of core particle size analysis, X-ray diffraction and cast thin section were used to study the change law of reservoir physical properties and wettability after water flooding, which confirmed that the reservoir was re-stimulated under long-term water flooding. The relative permeability curves before and after water flooding were compared using natural cores. After water flooding, the relative permeability curves shifted to the right and the residual oil saturation decreased. It is confirmed that the relative permeability curves will change with water flooding. Carried out 500∼2000PV water flooding laboratory experiment, determined the oil displacement efficiency under high multiple flooding, calculated the residual oil saturation changes with the displacement multiple and physical properties. Using pore cross-sectional area flux to continuously characterize the temporal changes of properties during the simulation process. In this way, the accurate conversion of the attribute change law from the laboratory core to the actual model is realized, and the deviation caused by the change of the mesh size is avoided. In the simulation process, the changing laws of the attributes are defined separately according to the partitions, and the iterative modification of the attributes is realized in each time step.
When time-varying numerical simulation is applied to the QHD oilfield, the matching degree of history matching has been improved.
Time-varying simulation is an important means to improve the history matching effect of high water-cut water drive oilfields, and can help oilfields understand the true remaining oil distribution. This method has been extended to Bohai SZ, BZ and other oil fields.
Non-Contact Magnetic Tomography Method MTM Inspection for Re-Instatement of a Decommissioned Buried Pipeline
Authors: Lam Choong Meng , Jasni Nur Akmal Hakim 
Published: March 2022

Abstract
The Magnetic Tomography Method (MTM) has been introduced as a non-intrusive inspection technique capable of inspecting ferromagnetic materials such as carbon steel pipeline without any contact. A buried main pipeline in one of PETRONAS's operating countries that had been out of service for more than 8 years needed to be inspected prior to being re-instated. This paper discusses in detail how this innovative MTM technology was used to successfully inspect a decommissioned buried pipeline and safely re-instated the pipeline operation. The MTM inspection covered 172 kilometres of buried pipeline, including the calibration work which involved direct assessment methods. The danger degrees such as Rank 1, 2 and 3, as well as the safe operating pressures, Psafe along the entire pipeline were determined using the MTM results of Risk Factor F in accordance with MTM technical approach. Direct assessment findings were consistent with the MTM inspection findings, as the technology detected all of the anomalies discovered by the direct assessment methods. MTM inspections of decommissioned buried pipelines are proven since they are reliant on the residual self-magnetic leakage field (SMLF) in the pipeline and do not require any intrusive works. Being a non-intrusive inspection method, this technology was not affected by the low pressure & low flowrate, and no changes to the pipeline operation mode was required during the inspection. Further, this MTM inspection method was not affected by the stalled pigs inside the pipeline, as this inspection method was non-intrusive. The inspection results serve as major input to the Pipeline Integrity Management System (PIMS) to effectively manage the integrity and risk level of the pipeline.
Remediation of A Complex Blockage for Gumusut-Kakap Subsea Flexible Flowline from a System Perspective
Authors: Gwee Yong Chin , Chin Grace , Chan Chee Hou , Chua Lee San , Ling Jason , Wu Yvonne 
Published: March 2022

Abstract
A subsea production flexible flowline in Gumusut-Kakap field was found blocked in March 2021 during a routine production well-flowline switching/alignment operation. Further evaluation showed that the blockage was caused by the formation of hydrate and gel over the 1.3km length of the flexible flowline, as the live crude and water were left stagnant and untreated in the flowline over a prolonged period. This paper covers the remediation strategy and the associated challenges from a System perspective, which successfully unblocked the flowline within a relatively short period of time.
The condition of the blockage in the flexible flowline was simulated using a commercial multiphase dynamic software to ascertain the phase distribution and hence allowed the estimation of the location and length of hydrate, gel, and emulsion in the flowline which has a downward inclination of circa 50 meters height. Heating (from production well), methanol (MeOH) soaking and flowline depressurization were planned and executed. In addition to the technical methodology, the System-wide aspects were also considered for the effective and optimum execution of the remediation activities which include attempting to fulfill the production commitment, abide by the subsea hardware and flexible flowline integrity envelope, and consider the impact of the remediation operation on other operations at the Gumusut-Kakap installation.
The MeOH soaking, flowline depressurization and pressurization successfully remediated the blockage over the period of weeks. Positive results were observed at the start of the remediation when the targeted location for MeOH contact and depressurization were identified via field trial. One of the key challenges is the time factor in which to ascertain the "appropriate" waiting time for the flowline depressurization, as the remediation involved partial shut-in of the prolific production wells.
A holistic System engineering approach is critical to the successful remediation of the blockage, integrating the key technical requirements as well as the soft and non-technical aspects to deliver optimum and net positive value for the asset.
Fish Anchor Testing in the Swan River
Authors: Hossain Muhammad Shazzad , Kim Youngho 
Published: March 2022

Abstract
OTC-28901-MS proposed the novel dynamically installed "fish" anchor in 2018, adopting a geometry taken from nature, for potential economic and safer tethering of floating facilities in deep water. Every cross section of the fish anchor shaft is elliptical, leading to very low drag resistance during free fall through the water column, and also low resistance in penetrating the seabed sediments. The padeye is fitted on the widest part of the shaft to mobilise the maximum resistance area under operational loading. The fish anchor embedment depth during dynamic installation, and capacity under both monotonic and cyclic operational loading in calcareous silt were assessed through centrifuge model tests and large deformation finite element analyses. During dynamic installation, the normalised tip embedment depth of the fish anchor was typically three times that for the torpedo anchors and 50% greater than that for the OMNI-Max anchors. Under operational loading, the fish anchor dove deeper, reaching penetrations 20 to 60% greater than achieved during installation. By contrast the torpedo anchors (for all mooring mudline inclinations) and the OMNI-Max anchors (apart from a single test with mooring mudline inclination of 0°) pulled out directly without diving, reflecting insufficient free-fall penetration in calcareous soil.
This paper provides a follow up reporting the performance of the fish anchor through field tests in the Swan River, Perth. A 1/15th scale model fish anchor was fabricated with dry weight being 0.304 kN. The anchor was tested at five different locations. At two shallow water locations (water depths 1.1 and 1.9 m, respectively), the tests were performed from the Burswood and Maylands jetty. At relatively deeper water depths of 2.91∼4.73 m, the tests were performed from a barge. The riverbed soils consisted of clay, silty clay, silt and sandy silt. The impact velocities were 5.9∼11.7 m/s. The normalised tip embedment depths were even greater compared to those achieved from centrifuge tests in calcareous silt. Under operational monotonic loadings, the fish anchor dove, as opposed to pull out of the riverbed, for mooring angles ≤ 37∼47°. Interestingly, in contrast to non-diving torpedo and suction caisson anchors, the diving fish anchor resulted non-elliptical failure envelopes, which have been expressed mathematically. The ultimate capacity was 3.5∼15 times the weight of the anchor submerged in water for taught and catenary moorings.
Standardization and Carbon Footprint Reduction of Subsea Manifolds – Is Ready and Now!
Authors: Ali Mohammed Hasan , Galli Caterina , Freire Machado Jose Felipe , Martinelli Giordano 
Published: March 2022

Abstract
There has never been a more challenging time for the energy industry. In the subsea sector, the search for optimised costs, minimized carbon emissions, and maximized performance is set to intensify as oil prices continue their unpredictable trajectory.
At the same time, the risks to equipment, to people, to the local terrain and seascape will remain. What the industry needs in the face of all this is cost certainty and reduced CO2 output, derived not just from technical certainty but also execution certainty.
With these concerns front of mind, it is no surprise that research into the performance of subsea equipment and service suppliers published by [1] Kimberlite LLC in May 2020 showed some concern about the capability of suppliers" offerings to meet those future requirements.
45% of those surveyed said that more advances were needed in subsea trees, citing reliability, cost, lead times, and size as areas for improvement. In addition, subsea manifolds were separately cited by another 12%, as a technology area that could be advanced.
As part of the goal to achieve carbon net zero status, every single aspect of subsea operations is an opportunity to drive improvement. Through the work undertaken as described in this paper to drive standardization across the industry around the world, it can be shown that even equipment like manifolds – that come with some entrenched design and operational philosophies behind them – can deliver substantial improvements to the areas that matter most such as reduction of carbon footprint.
Effect of Silicon Carbide on the Surface Tension and Adsorption of SDS on the Sandstone Formation
Authors: Pandey Anurag Pandey , Roy Vishnu , Kesarwani Himanshu , Mittal Govind , Sharma Shivanjali , Saxena Amit 
Published: March 2022

Abstract
Oil recovery in modern fields is challenging due to the reservoir complexity and heterogeneity. The need is to improve the efficacy of additives used in oil mobilization under higher pressure, temperature, and salinity conditions. The nanoparticles provide improved and sustainable solutions for improving oil recovery. Silicon carbide nanoparticle exhibits negligible agglomeration and impart higher thermal stability to the displacing fluid for oil mobilization at higher salinity. The SIC nanoparticles are being used in EOR Applications for the first time owing to their adsorption reduction potential and thermal stability at elevated temperatures. The study estimates this nanoparticle's enhanced oil recovery potential using electrical conductivity, surface tension reduction, and crude oil mobilization. The concentration of SDS was varied from zero-4000 ppm and that of SIC from 100 ppm to 300 ppm. The solution's surface tension and critical micelle concentration (CMC) conductivity were measured at elevated temperatures (30°C, 50°C, and 70°C) with and without nanoparticles. The adsorption studies were performed for 72 hours with 10 wt% of sand added to the solution. The loss of surfactant onto the sand was calculated by studying the variation electrical conductivity before and after adsorption. Surface tension reduces from 70.15 to 28.5 mN/m with increasing SDS and nanoparticles concentrations in the solution. The CMC values of the SDS+SIC solution were lower than that of the independent surfactant system, even at higher temperatures of 70°C. SDS adsorption increased from 0.80 to 6.27 mg/g as the surfactant concentration increased up to 4000 ppm. It was reduced by about 10% and 20% for 100 ppm and 200 ppm of the nanoparticles. However, at 300 ppm, the agglomeration of nanoparticles renders them ineffective in controlling adsorption.
Sand Erosion Mitigation for Offshore Pipeline and Riser – Erosion Prediction by Computational Fluid Dynamic CFD Analysis and Experimental Testing
Authors: Putra I Wayan Eka , Chien Tan Chin , Badaruddin M Fauzi , Isa M Hilmi , Hou Cheong Xiang , Dongjie Liu , Dalin Sun 
Published: March 2022

Abstract
Late life production of oil & gas facilities are faced with significant challenge especially when sand is produced along with the production fluid. It can cause premature failure of the equipment, for example piping and pipeline. Mitigation by adding sand removal facility is limited by space, available load, and handling at satellite wellhead platform. It also introduced additional pressure drop which limit the production that already in low pressure. One of the measures to mitigate sand erosion issue for the offshore pipeline and riser is by flow assurance, to reduce the flow velocity so that the sand velocity will be less than the erosional velocity. This mitigation comes with drawback where reducing velocity will require bigger size pipeline, higher cost, and introduce higher liquid dropout along the pipeline which will create severe slugging issue in the pipeline. Next mitigation can be done by increasing bend radius along the pipeline, to reduce impact angle of the sand to the internal surface of the pipeline. Last mitigation will be increasing resistance of the material to the sand erosion. Combination of those methodology is required to achieve the most optimum solution to mitigate sand erosion. This paper present sand erosion mitigation on one of the existing pipeline replacement projects in PETRONAS by application of unbonded flexible pipe. Modeling of the of the erosion due to sand particle solution in the pipeline was done using computational fluid dynamic finite element analysis simulation. Experimental test with samples positioned at various orientation of the riser bend location were also investigated. Concerning the exceptional balance between results efficiency and simulation time, a grid sensitivity test has also been included. Various parameters were used to verify the sensitivity of the simulation including materials properties for various fluid composition data obtained from production forecast and fluid velocity as modeled in the pipeline steady state hydraulic analysis and transient flow assurance analysis. As result, the thickness of internal carcass is found sufficient to withstand the erosion threat generated by sand particles for the entire design life of the pipeline. The results obtained from finite element analysis and erosion experimental test were then correlated, and the comparison were illustrated in graph of velocity against erosion rate for each of sand concentration. The result of the modeling and experimental testing may improve prediction model of the sand erosion in the offshore pipeline especially for flexible pipeline and riser application.