bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Estimation and Management of Hydrate Plugging Risk During Deep-Water Gas Well Testing
Authors: Zhang Jianbo , Wang Zhiyuan , Duan Wenguang , Fu Weiqi , Tong Shikun , Sun Baojiang 
Published: November 2019

Abstract
Hydrate formation and deposition usually exist during deep-water gas well testing, which easily cause plugging accident in the testing tubing if it was not found and handled in time. A method to estimate and manage hydrate plugging risk in real-time during deep-water gas well testing is developed in this work. This method mainly includes the following steps: predicting hydrate stability region, calculating hydrate behaviors, analyzing the effect of hydrate behaviors on the variation of wellhead pressure, monitoring the variation of wellhead pressure and estimating hydrate plugging risk in real-time, and managing hydrate plugging risk in real-time. As hydrates continue to form and deposit, the effective inner diameter of the tubing decreases, and the wellhead pressure also decreases accordingly. The risk of hydrate plugging can be estimated by monitoring the variation of wellhead pressure. When the wellhead pressure decreases to the critical value for safety at a given gas production rate, it is indicated that hydrate plugging is likely to occur. Under this condition, hydrate inhibitor is needed to inject into the tubing to reduce the severity of hydrate plugging, and real-time monitoring of wellhead pressure variation is also needed to guarantee the risk of hydrate plugging in the testing tube is within safe range. By using this method, the real-time estimation and management of hydrate plugging during the testing process can be achieved, which can provide basis for the safe and efficient testing of deep-water gas wells.
Drilling in the Digital Age: An Aproach to Optimizing ROP Using Machine Learning
Authors: Batruny Peter , Yahya Hanif , Kadir Norazan , Omar Amir , Zakaria Zahid , Batamale Saravanan , Jayah Noreffendy 
Published: November 2019

Abstract
Low rates of penetration (ROP) were experienced in an area with well-known lithology. The vast drilling experience and similarity of drilling conditions in the area, provided the operator with enough data to improve the well schedule and cost performance through the use of machine learning.
Machine learning, specifically artificial neural networks (ANN), is a statistical tool to find relations between multiple inputs. Details that would have been missed or considered outliers by a mathematical model can be accounted for and explained in the ANN model. The ANN was trained on thousands of real time data points recorded from selected wells in a specific depth interval. Typical drilling parameters such as weight on bit, rotary speed, bit hydraulics, lithological properties, and dogleg severity were the input parameters chosen in the model to generate ROP. Once the model was calibrated to historical data, it was used to find the best parameters to maximize ROP.
R squared factors were 0.729 and 0.675 for 12.25 in. and 17.5 in. sections repectively. This was achieved with an ANN structure of 2 hidden layers consisting of 5 nodes each. Sensitivity analysis identified bit hydraulics, weight on bit, and rotary speed as the major parameters impacting ROP. The ROP model was used to conduct a "virtual drill-off test" to identify drilling parameters that maximize ROP. ROP dependency on weight on bit and lithological analysis suggests bit design can be further improved. Bit hydraulics showed that higher flow rate was needed in sections with higher overbalance. Optimum drilling parameters were tested on four wells and resulted in more than 50% higher ROP compared to original field data.
In an industry increasingly dominated by big data, separating the clean data from the "noise" will be a vital topic. This paper aims to provide a blueprint for the use machine learning to optimize ROP in a manner that is simple and easily replicated.
Optimal Surface Cooling Solutions for Thermal EOR Projects
Authors: Sulaimani Husam , Sellappan Ganesamoorthy , Hamm Mark 
Published: November 2019

Abstract
Thermal Enhanced Oil Recovery (EOR), is considered the most applied EOR method, which contributes to around 66% of the global EOR. Steam Injection is normally employed on the reservoir to reduce the viscosity of heavy oil and enhancing its mobility, at high temperatures. One of the common issues arising with continuous steam injection, is reservoir heating, causing produced fluid temperature to increase, exceeding the temperature limitations of the downstream facilities. The objective of this study is to develop and provide an optimum surface cooling facility to minimize the impact of production and avoid the need for major modifications to the facility.
The methodology used involve; surface process simulation using UNISIM simulator, subsurface dynamic heat modelling using CMG Stars software, materials selection, economical and costing studies. The parameters used were; existing and future well counts, individual wells gross production rates, and maximum expected produced fluid temperatures. Different solutions have been considered such as water dilution, super grade materials, Mechanical Refrigeration, Wet Surface Air Coolers, Draft Air Coolers and Heat Recovery Exchangers. The selected options have been evaluated based on technical, economical, environmental and operability criterions.
Dilution with water and super graded material options were discarded, due to lack of external water supply, and significant life cycle cost respectively. All the Heat Exchanger options were also discarded due to the inability to meet cooling mediums specification, as well as the presence of economical and operational difficulties. The optimum selected technology is to provide Air Coolers at the individual Wellheads, although this solution is theoretically and economically convincing, there are some operational and maintenance challenges to overcome considering the remote locations of the steam injection wells. However, some parameters such as cost, simplified technology, maintainability, availability, will play a key role in demining the optimum technology.
Unlike most published studies, the outcome of this study has been validated with existing field data (operational learnings), as well as being the first of its kind to implement, benchmarking with other major oil and gas producers, also saving significant capital costs by 69%.
Applying a Foamed Cement Operation for Surface Casing in a Deepwater Well: Case Study, French Guiana
Authors: Ribeiro Danilo , Souza Leonardo , Paredes Jose Luis , Michon Patrick , Szakolczai Cyril 
Published: November 2019

Abstract
Lightweight or, alternatively, foamed cement slurries for surface casing operations are often necessary during special situations (i.e., low fracture gradients) for the required zone to be isolated. The foamed cement technique reduces the heat of hydration (HoH) of the slurries, reducing potential risk of shallow hydrate flow and losses because of its reduced hydrostatic pressure. This alternative for lightweight slurries has been used globally with successful results.
The foamed cement operation was designed and executed considering specific aspects and details, including a combination of factors, such as expected low fracture gradient, mechanical property requirements, logistic constraints in terms of the difficulty managing two types of cement (large tonnage of Blend and G cement vs. rig capacity and safety volume requirements), long sections to be cemented, and the uncertainty of the cement volume excess necessary to achieve return in the seabed. Because this was the first cement operation for the operator at this remote deepwater field, the planning phase required extensive discussions. Rig silo capacities and deck space on the rig were limited, which constrained the possibility of considering backup for all bulks, chemicals, and equipment.
Execution of the cement operation was as per the approved program without deviation. The cement volume returned at seabed indicated an openhole diameter with ±100% washout. A tracer additive (fluorescent dye) mixed with the spacer was successfully used to indicate fluid return at seabed (2120-m water depth). As part of the best practices to execute this operation, a liquid additive system was used to provide pump volume flexibility. Foamed cement laboratory tests were performed, considering field samples and the foaming agent (surfactant) were injected straight at the suction of the pump. As expected, the foamed cement operation is an extremely efficient and effective technique to achieve zonal isolation in a surface casing string of a deepwater well. Currently, this procedure is frequently used in fields globally. A case study of the first foamed cement application for surface casing in French Guiana is discussed.
A 40 Years Brown Field Rejuvenation
Authors: Hassan Siti Normaizan , Bt Latif Nurlizawati , Ashqar Ayham , Ishak Ahmad Zamzamie , Mustafa Azfar Hafizin , Roy Amit 
Published: November 2019

Abstract
This paper discusses a comprehensive study to address the uncertainties and troublesome major field development. The west Malaysia field has 7 platforms, and 110 wells. Production started in 1979. The highly complex, elongated anticline structure, possess over 330+ interpreted normal, reverse and wrench faults. It is deposited in Lower Coastal Plain within transgressive system tract.
Despite the strong and consistent reservoirs production, recovery Factor (RF) remained at 19% indicating potential remaining value.
The new look requirement were imposed as a result of disappointing drilling results mainly due to Key uncertainties in hydrocarbon redistribution, sand continuity and its quality, oil production across adjacent fault blocks.
Multicomponent seismic was acquired, to establish an updated reservoirs framework and assist in mapping hydrocarbon, water as well as lithology identification (sand/shale/coal).
Several wells were suspended based on the indicative study result. 85 new opportunities were identified, and tiered based on technical confidence and risk appetite. A roadmap consists of detailed development strategies spanning over 5 years and beyond associated with ~100MMstb reserves value that will bring the RF to 31% were proposed.
Main study outcomes resulted of reducing sand distribution uncertainty, reservoir extension was clarified and confirmed with the new seismic interpretation result. By passed oil were mapped.
Co-Development Aspects of Super Giant Reservoirs With Condensate-Rich Gas Cap
Authors: Ziablitckaia Yulia , Sharif Ahmed , Abdou Medhat 
Published: November 2019

Abstract
Conventional strategy for developing of giant oil reservoirs with a gas cap involves an optimal production from the oil column before the gas cap is blown down. This paper investigates technical aspects of co-development strategies where demand for the gas may entail earlier exploitation of the gas cap along with the existing oil column development.
Co-development of giant reservoirs with condensate-rich gas cap are particularly challenging due to the presence of significant condensate volumes. The basic strategy of the co-development plan involves producing from a gas cap first under full gas recycling so as to accelerate condensate recovery. This is followed by sales gas production by means of partial gas recycling in conjunction with water injection at gas-oil contact for pressure maintenance purposes. The injection of water at gas-oil contact is intended to provide a water barrier or fence that separates and / or minimize gas cap expansion toward oil. The degree at which sales gas is produced is under pressure maintenance scheme is thus linked to the level of the partial gas recycling and the efficiency of the barrier or fence water injection.
To explore the feasibility of this process, reservoir simulations of mechanistic models were first used to study the reservoir physics of water injection at gas-oil contact for the purpose creating water barrier and /or fence. This was followed by implementation of the co-development scheme using sector models that represent two giant carbonate gas cap reservoirs. The feasibility and merits of the co-development strategy were measured by performance metrics that include condensate recovery, sales gas production, minimum oil loss and fluid migration at gas-oil contact and overall water demand.
The results show that partial recycling along with barrier water injection may provide a mechanism for concurrent gas cap and oil column exploitation. A key factor that underlies the success of the co-development plan is the ability of the water injection at gas-oil contact to recover potential pressure drop in time as gas recycling ratio is reduced by forming effective barrier. This, in turn depends mainly on the reservoir geology and water injection volume and scheme. Moreover, reservoir characteristics that are favorable to the process are lower formation dip angle, smaller surface area at fluid contact and good injectivity of the reservoir rock.
The Automation of Steady-State Fractional Flow Upscaling in Stratified and Random Rock Type Structures
Authors: Ramsay Travis 
Published: November 2019

Abstract
In discrete upscaling methods, the saturation history of corefloods is often lost, while automated upscaling methods retain the saturation history of corefloods. A reservoir simulator is used to upscale imbibition relative permeability using discrete and automated methods. Both discrete and automated upscaling methods can be categorized according to a Peclet number ratio, which describes relative permeability upscaled in the capillary limit for stratified and random rock type assemblages. The upscaled results are then compared to both the rock type curves and to results from different cores to validate whether the effects of rock type volume fraction and distribution are preserved. The term random here refers to a carbonate sample relative to its stratified counterparts. In the cores with stratified geometry, a Peclet number ratio is used to ensure multiphase capillary limit flow and preserve adequate scaling. The ratio is determined from the Peclet number in adjoining rock types; a Peclet number ratio is computed from a pair of rock types (or pseudo-rock types if more than two rock types are present), since the geometric and associative relationships of rock types are ill-defined. The discrete method follows an isolated dual-rate injection, while the automated procedure is performed by sequential dual-rate injection.
The effects of rock type volume fraction and distribution are preserved while upscaling in the capillary limit for core assemblages possessing stratified and random configurations; this is true for both discrete and automated methods. Behavior in the stratified cores at the saturation endpoints is then used to further classify the behavior of the random assemblage. The primary conclusion is that automated relative permeability upscaling in a commercial reservoir simulator is a viable alternative to discrete upscaling methods, as it is both functionally efficient and maintains a saturation distribution and profile analogous to the standard coreflooding process. Secondarily, upscaled relative permeability is rock type dependent on the distribution and volume fraction of the differing rock types in the capillary limit. An analysis of curves generated in stratified geometries and randomly assembled rock types, such as carbonates, shows discernable differences and suggests care must be taken during upscaling from pore to core to ensure rock type volume fraction and distribution effects are not lost.
Integrated Engineered Solution for Realtime Through-Tubing Remedial Sand Control
Authors: Ramah Moorthy Kuhaneswaren , Mohd Zainudin Nik Mohd , Nor Nazri , Arief Tham Nabilla , Huang Pin Y , Ishak Eliza , Ismail Abdul Malek , Wijoseno Danny Aryo , Sorman Ignatius , Yong Nigel , Liu Hai , Nwafor Chidi , Ling Kong Teng , Wibisono Rahmat 
Published: November 2019

Abstract
Coiled tubing (CT) sand cleanout has been a normal practice for offshore wells, and repeated cleanout runs will have to be done over the years to sustain production. It has been observed that the production period of these offshore wells has shortened significantly after each cleanout due to sand particles loading up in the production tubing at a faster rate. This production trend is typical for wells with no downhole sand control in the original completion. Various aspects in terms of well design and reservoir conditions have significantly increased the complexity of sand cleanout. This, for example, includes the large 9 5/8-in. casing section with small dual upper completions of 2 7/8-in. production tubing, a high angle with a long horizontal section, and severely drawn-down reservoirs. There were also previous findings on the well where cement pebbles were found on the production choke at surface contributing to higher risk during intervention.
An integrated engineered solution was brought forward to successfully execute the CT sand cleanout job by capitalizing on both engineering and operational efficiencies. In terms of technical and engineering design, real-time fiber-optic downhole telemetry system, nitrified cleanout with a shear-thinning gel fluid that has superior suspension ability, and a milling tool for cement pebble cleanout were utilized. Operationally, an electrical submersible pumping (ESP) system capable of providing continuous supply of seawater and custom-built skidding beams for sand screen deployment purposes were also introduced for the first time for CT operations in southeast Asia that successfully improved operational efficiency and job safety.
A remedial sand control solution was also used to improve production longevity after sand cleanout, without doing any major pull-tubing workover or sidetrack drilling. Either through-tubing sand screens or a sand agglomeration treatment technique was carefully chosen and deployed to address the sand load-up issue in these wells. This paper discusses the operations, challenges, and the key success factors that have contributed to a well-engineered CT cleanout and deployment of sand screen and sand agglomeration treatment.
Acid Stimulation Evolution and Optimization for HPHT Deep Gas Formations
Authors: Moid Farrukh , Rodoplu Rasim Serdar , Nutaifi AbdulRahman 
Published: November 2019

Abstract
Acid stimulation and fracturing in multiple layers formation requires an integrated approach to design and execute an effective stimulation treatment. An extensive campaign of acid stimulation on carbonate formation to increase productivity index in a deep High Pressure High Temperature (HPHT) gas bearing carbonate formation is discussed here. A high degree variation in permeability across long interval, stress barriers between target zones, and completion limitations were main challenges to design an effective stimulation treatment.
The target was to achieve effective acid stimulation for multi-layers carbonate formation with different formation properties and stress barriers. Although all layers had similar initial pressures and gas compositions; but different properties. Comingled flow was planned from the formation, therefore effective stimulation for each layer was recommended to drain effectively and improve recovery.
To assess the best stimulation strategy in early stage of development, complete set of diagnostics conducted across all formations before and after the acid treatment coupled with geomechanical studies on actual core samples. Various stimulation techniques were implemented from Small Matrix Treatments (SMT) with Coiled Tubing, Matrix Acidizing Treatments (MAT), High Rate Matrix Acidizing (HRMA), and Acid Fracturing Treatment (AFT). Thorough study of results as part of learning process was conducted to optimize the important parameters that affect the stimulation efficiency such as perforation strategy, completion design, diverter selection, fracturing design and implementation. The importance of modeling in optimization process, comparison between different treatment types and fluid systems is discussed supported by actual data such as temperature logs, post-treatment flowback analysis, pressure transient analysis and production logging results.
Predicting LNG Loading Arms Structural Bearings Condition
Authors: Nistor Marius 
Published: November 2019

Abstract
The scope of this technical paper is to present existing methodology of predicting structural bearings condition of LNG Loading Arms in ADNOC LNG through a systematic monitoring system (LNG Loading Arms Verticality Check) included into maintenance periodic routines in order to maintain operational reliability, optimize plant availability.
Few years back, ADNOC LNG experienced abnormal structural bearings noise along with leaning issue of two LNG Loading Arms, culminating with one Loading Arm becoming immovable. Despite the fact that the structural bearings are designed for entire life span of Loading Arm, it was recommended by OEM to replace all three structural bearings (slew, luff and apex), activity which was performed with significant resources and cost impact.
A systematic monitoring approach to monitor the verticality of mobile arms was adopted into the ADNOC LNG Preventive Maintenance Program associated with LNG Loading Arms. The technical paper is presenting the methodology and best practices to trend and benchmark wear-and-tear process experienced in the LNG Loading Arms structural bearings. LNG Loading Arms - Verticality Check utilized a combination of GPS, conventional surveying and electronic techniques for the rapid acquisition coordination data required for the monitoring approach.
Several detailed verticality check surveys were conducted for four LNG Loading Arms by determining coordinates (plan and height) from a network of GPS observations connecting newly constructed reference control points as the basis of a 3D network. The monitoring procedure was designed to trend the existing targets coordinates (installed on the LNG Loading Arms - "bull-eyes") and compared with the As-New structural bearing condition and LNG Loading Arms operating behavior, keeping in account the verticality deviation causes attributed to several factors (Loading Arms positioning errors, structural bearing clearance, other mechanical structural distortion, etc.). Each of the Loading Arms were found to be out of verticality along the virtual critical axis, but still within the calculated acceptable limits.
Current maintenance practice on monitoring the Loading Arms verticality check is a powerful systematic tool for better assessment of structural bearings condition in ADNOC LNG - Das Island plant, methodology which can be implemented within other facilities using transfer arms.