bluuebunny/crossref_metadata_2025_split huggingface dataset:
Process Stability of Multi-Compander Refrigeration Trains for Floating LNG Application
Authors: Hashim Hasnor Hassaruddin , Muhd Ali Fadzrul Izwan , Rusman Andriny 
Published: February 2015

Conventional land based LNG plants utilizes hydrocarbon-based refrigerant systems driven by large compressors. For floating LNG plants, gaseous N2 refrigeration system is preferred due to the compactness of the refrigeration equipment and the less hazardous nature of gaseous N2 when compared with liquid hydrocarbon refrigeration system. Due to the low heat capacity of N2, companders (expander-compressor) are required to maximize the cooling duty instead of JT valves. Multiple compander units are required to handle the pre-cooling, liquefaction and sub-cooling of the natural gas. To provide process flexibility and equipment maintenance window, parallel N2 refrigeration trains are required for floating LNG plant. PETRONAS Floating LNG 1 facility will be the first floating plant in the world, utilizing only gaseous N2 as the refrigerant to produce LNG.
The controllability of the N2 liquefaction is the main concern due to the large number of rotating equipment as well as load balancing the parallel N2 refrigeration trains. Specific analyses need to be conducted on the liquefaction system due to the complexity and highly interactive nature of the process, leading to possible process instability. An integrated dynamic model using PETRONAS's iCON dynamic process simulation software was developed and utilized to conduct several operability studies, focusing on normal start-up and shut-down, refrigeration load switching from single to parallel N2 refrigeration trains, increase and decrease in LNG production, feed disturbance from production wells and equipment malfunction.
Result shows that there is a highly interactive dynamic response between the companders and the heat exchangers due to the tight process integration. Disturbance to one compander may cause cascading effect through the other companders, which can cause compander overspeed or surge condition. This necessitates prudent analysis of the operating scenarios to ensure operability and carefully planned controller design for stable operation. Additionally, being the first such refrigeration configuration in the world, correction of perception that operation will be similar to the conventional hydrocarbon-based refrigeration LNG facilities is an issue to address.
Water Source and Flow Direction Detection in a Heterogeneous Fracture Carbonate Reservoir: Challenge and Solutions_A Case Study in Indonesia
Authors: Sanjaya Sanggum , Quintero Luis , Iyer M.S. , Diametrica Septian , Praveen Florence , Soendaroe Achmad , Harkomoyo Harkomoyo 
Published: February 2015

Detecting the source of water production remains a major challenge during evaluation of fractured carbonate reservoirs. In heterogeneous formations, when the horizontal section passes through a fracture or set of fractures, improper drawdown can allow formation water to flow through these conduits, increasing water cut and blocking hydrocarbon production.
On the contrary, in cases of horizontal wells with three phases of fluid flow, the presence of inflow control devices (ICDs), sliding slide doors (SSDs), slotted liners, and swell packers can add to the complexity of the logging environment and exasperate the ability to accurately quantify production using a production logging tool (PLT).
Using horizontal production logging alone can help identify the point of water entry; yet, in cases of slotted liners, it can be difficult to pinpoint the source of water and the direction of flow. The use of oxygen activation can help identify water movement inside or behind liners and confirm the direction of flow. The integration of both techniques helps minimize uncertainty and enhance interpretation.
This paper discusses a case study from Pertamina Hulu Energi-West Madura Offshore (PHE-WMO). The difficulties associated with identifying water sources in horizontal wells drilled in complex carbonate reservoirs completed with ICDs, SSDs, and swell packers are discussed. It documents a well with high water cut, making water point identification more challenging. Also, it discusses the advantages of using a spectral flow log with a horizontal PLT, versus using the latter only.
Floating LNG Development - Challenges and Achievements
Authors: Ahmad Hamzah , Abdul Wahab Iskandariah Roslan , Suaib Mohd Hany 
Published: February 2015

The PETRONAS Floating LNG concept was envisaged to monetize stranded gas resources as part of the effort to turn Malaysia's 2% hydrocarbon depletion rate into 3% growth. The two floaters for offshore Sarawak and Sabah will increase the country's LNG production capacity by 8% (2.5 MTPA). The fast track nature of the project present a challenge to both the Gas and upstream Business in meeting the target date. Extensive technology selection exercises we conducted in finalizing the turret and mooring,, gas treating, liquefaction, LNG cargo containment and LNG offloading systems. Designers and licensors have done rigorous design optimization and marinization studies on impact of floater motion and evaluated against an extensive criteria:Proven and established onshore and offshore track records as well as experience or involvement in the delivery of LNG plantsDesign robustness and efficiencyOperating envelop and flexibilityInherent safe design
Main challenge includes optimizing the flexibility of the process to accept the widest range of known and anticipated feed gas quality. Technology and equipment selection for the topside processes required extensive investigation into vendors' readiness to design and supply natural gas receiving, treating, liquefying and LNG storage and offloading equipment for first time utilization in the open sea environment. Processes and equipment design have taken into consideration the design motion envelope, calculated blast loads, acceleration and sloshing effects while keeping within the topsides weight, footprint, environment and regulatory constraints. The nitrogen cycle liquefaction process presented a unique challenge in commissioning attributed to logistics requirement and the extreme complexity of the process and machinery controls.
Success in managing the complexity of the facilities design and construction within the extreme constraints of technology and constructability will be the ultimate triumph for the PETRONAS Floating LNG Project to become a benchmark and model for similar scale Floating LNG projects.
Detection and Removal of Naphthenate Deposit in Oil Well
Authors: Mohamed A.S. , Goyal A. , Mohd Ismail M.D. , Munainni G. , Amar Singh J.K. , Ismail M.Z. , Anwar M. 
Published: February 2015

Oil wells which produce high acidic crude especially asphalt-base crudes tend to yield naphthenate (cycloparaffin) as deposits. This is a major flow assurance issue as it reduces the oil production in the wells and also causes napthenate induced emulsion. The objective of this work is to focus on diagnosis of oil producing well which have the tendency on forming napthenate deposits along with inorganic scale/corrosion product. In this paper, two wells from an oilfield offshore of East Malaysia were used as a case study to detect the presence of naphthenate. Analytical testing was conducted to detect napthenes deposit in these wells. Tests such as total acid number (TAN) analysis, cationic and anionic analysis on water, pH of crude and also x-ray diffraction (XRD) on deposit were conducted to understand the occurrence of the napthenate solid. A speciality micro-emulsion formulation was designed to improve the productivity of the well by injecting into the tubing/around wellbore to dissolve/disperse these napthenate deposits embedded with inorganics. One of the well of the case study, Well A is diagnosed to be impaired by napthenate deposition. Well A was observed to have production drop from 1200 bpd to 300 bpd in 7 years. During this period, skin increased from 30 to 65. Formation blockage was identified as the root cause based on the Productivity Index (PI) trending established from several pressure build up surveys (PBU) and flowing gradient surveys. After the treatment, the liquid rate increased to 700 bpd with significant reduction in watercut.
The application of this study is to provide a guideline towards early detection of naphthenate and possible chemical remedial to revive the well productivity. Thus, promotes preventive measures and mitigation plan which can be devised and replicated.
3-D Mapping for Fire and Gas Detection
Authors: Kek Chua Kien , Yang Tan Ping 
Published: February 2015

An increasingly competitive environment has put intense pressure on Oil & Gas operators to design and operate facilities in a more cost efficient manner without compromising safety. Fire and gas detection systems play an important role as a safety barrier in process safety management and the adequacy of detection coverage is crucial. PETRONAS has developed 3-D visualization software to accurately quantify detector coverage for correct detector placement.
This software provides a quantitative means of evaluating flame and gas detector coverage which is not available via conventional engineering methods. It also improves accuracy over conventional 2-D methods, evaluating coverage around irregular-shaped equipment at different elevations. PETRONAS' Fire and Gas Mapping software can be used to evaluate detection of various hazards by different detection technologies such as combustible gas (point, open path and ultrasonic), flame (UV, UV/IR, IR3 and CCTV) and toxic gas (point and open path). It has been successfully deployed to 27 downstream and upstream sites and counting, covering both green field and brown field facilities.
With a greater emphasis on safety and economics in Oil & Gas facility design and operations, fire and gas mapping is an invaluable technical solution and will become the benchmark in determining detector placement for the industry.
Solution to Cement Integrity Evaluation in Long Extended Reach Wells: New Record in South China Sea
Authors: Cai Jun , Gao Yongde , Zhang Mingjie , Cui Lei , Guo Hongzhi 
Published: February 2015

The development wells in South China Sea today are mostly extended reach wells with a measured depth of about 4000m and a high deviated or horizontal displacement of over 3000m. The accurate assessment of cement bond is given even more attention because of the cementing challenges in such environment: the uncertainty of cement distribution in highly deviated intervals due to uneven mud removal, the difficulty in evaluating two-stage cement job with both light and heavy slurries pumped in one section. Furthermore, rising cost concern of offshore operations requires an efficient manner to acquire comprehensive integrity evaluation data without extending rig time.
The combination of ultrasonic and flexural attenuation measurements was adopted in this project for cement integrity evaluation, conveyed with a wireline tractor. Analysis from the combined measurements discriminates the materials behind casing circumferentially regardless of cement density, and identifies liquid or gas filled channeling in cement sheath. The flexural wave imager reveals the "Third-Interface" information that illustrates annulus shape and casing centralization, from which a three-dimensional cement sheath image can be generated. We conducted the operation rigless by tractoring the tool-string down for over 3300 meters to the target depth, to acquire good quality data in a single run.
In this paper field examples are presented to explain the workflow of getting a more definitive cement integrity answer. We will also discuss how the new method aids to understand why the integrity losses occur in certain sections by analyzing the Third-Interface information uniquely provided by flexural waves, hence to suggest improvement actions in future cementing jobs.
This method gained more explicit cement integrity evaluation result with detailed graphical annulus information comparing with limited outputs from conventional acoustic measurements. Furthermore, this solution was launched for the first time in South China Sea and great efficiency was demonstrated with a new tractoring distance record in China offshore operation, which saved 2 days rig time in comparison with previous jobs conveyed by drill pipe.
Selecting a Safe and Reliable Drilling System for New Deepwater Challenges
Authors: Brandt Havard 
Published: February 2015

The Oil & Gas industry continues to explore and develop ever more challenging and difficult hydrocarbon prospects. Also Asia is experiencing a push into deeper water, exploring reservoirs with higher pressure and more difficult and complicated formations, i.e. fractured carbonates. These operating conditions results in an increased interest for more novel drilling systems, i.e. offshore managed pressure drilling. But how safe and reliable are these new systems?
A general perception is that new technology introduces more risks, and there are a number of examples of new technology not meeting expectations with respect to reliability and performance. What would be the consequence of a failure in these new drilling systems? To further complicate the situation, the recent Macondo and Montara blowout has put a increased pressure on the drilling industry to demonstrate safe and reliable drilling operations; there is no tolerance for failure.
One of the challenges with this risk adverse perception on new technology is that conventional systems are typically only evaluated on the basis of their past track record, with little or no considerations to the more complicated and challenging operating environments. Consequently, the drilling contractors experience more drilling problems when operating in these new environments, i.e. stuck pipe and lost circulation. These issues result in high operating costs due to loss of drilling mud and non-productive time (NPT), but they also represent a potential safety risk as these drilling events may trigger a well control incidents.
To provide a more realistic risk picture and have a better basis to compare alternative drilling systems, DNV has together with the industry developed a methodology to assess and quantify the risk of blowouts related to a specific well operation. This risk based assessment is based on a systematic assessment of the drilling rig, drilling equipment, operating conditions, sub-surface conditions and drilling and casing program. In this paper the methodology is outlined, and a case example related to a specific drilling operation in a fractured carbonate reservoir of the Eastern coast of Sulawesi, Indonesia, is used to demonstrate the methodology.
Influence of CO2 Nucleation Rate Towards Cryogenic Separation Technologies in Bulk CO2 Separation from Natural Gas
Authors: Md Jalil A.A. , Rostani K. , Ahmad Samawe R. , Othman N.A. , Esa M.A. 
Published: February 2015

Marginal gas fields containing large concentrations of CO2 is a technical challenge to develop due to the low CO2 concentration requirement in the sales gas. One of the CO2 - Natural Gas separation methods being studied to develop the field is to use phase separation method in separating CO2 with natural gas. The principle of these gas separations units lies in the cryogenic sciences in the separation unit, causing condensation (and crystallization) of CO2 out of the mixture. Therefore, it is important to understand the concept of nucleation of CO2 to properly design the gas separation units.
An adiabatic expansion experiments is performed in pulse expansion wave tube (PEWT) (1, 2 &3). In this experimental set-up, CO2 nucleation is induced in a high-pressure expansion wave tube, where rapid controlled pressure and temperature decrease is induced. The nucleation is measured by means of laser scattering and extinction signals. Moreover, the onset of crystallization can be measured if the expansion is sufficiently deep for the liquid droplets to evoke liquid-solid transition. Similarly, a new parallel experimental set-up was commissioned to allow for more experimental runs per day. Gas mixture in Expansion Chamber (PEC) is brought into nucleation by subjecting it to a sudden change in temperature and pressure. When temperature continues to decrease, the solid-liquid saturation curve in the phase diagram is passed, and crystallization occurs. In this way the experimental setup open the possibility to determine Wilson points, crystallization points, and nucleation rates for multi-component gas mixtures. The onset of nucleation, crystallization, and the measurement of droplet growth is measured by means of laser light transmission and scattering.
In both set-ups temperatures below -100°C is reached. Experiments in both setups for CO2 in NG mixture confirmed theoretical temperature predictions. The results are comparable to the nucleation theory which predicts the onset of nucleation and nucleation delay. These parameters are then used to design CO2 - Natural Gas Separation devices.
Frac Pack: Reviving and Maximising Production Potential in Cambay Offshore Field
Authors: Patil Bhushan , Ivanov Maxim , Shado Horatio-Da-C osta 
Published: February 2015

As energy demand continues to grow, it is amazing that more than half of world oil production comes from fields as old as 30 years. The Cambay offshore fields off the coast of Gujarat, India started producing gas in 2002 and oil 2005. The production of Oil was possible through geophysical studies that led to incremental recoverable volumes. The oil wells with cased hole perforated completions however have a sanding problem after a few years of production leading to rapid oil production decline in the field as well as associated sand production issues.
This paper presents the result from implementing the simultaneous gravel packing and hydraulic fracturing of a well commonly known as "FracPacks" in the industry on a sanding well in the field and a comparison to 2 other wells with different completion techniques. The paper outlines the challenges faced with data collection, the design methodology, an overview of operations and execution. The outcome of the FracPack treatment was a textbook tip screen out placement leading to a 76% increase in oil production with zero water cut and sand. The results demonstrate the benefits of contacting the reservoir beyond the critical matrix even in a 2.4 Darcy formation and highlights that FracPacks can be less sensitive to the procedures used for wellbore preparations..
The lessons learned from the Cambay experience add to the growing number of case histories which show that FracPacks are effective techniques for sand management in high permeability formations. FrackPack performance is compared to other techniques such as standalone screens and gravel packs, both in terms of production as well as production longevity. This study will highlight the importance of selecting the completion technique based on the reservoir challenges and the importance of considering constraints such as nearby water, logistics and other operational concerns.
Stuck Pipe Nonproductive Time Reduction by Application of Intelligent Technologies to Replace Conventional Drillstring Separation Methods
Authors: Hunter Gordon , Ollerenshaw Andrew 
Published: February 2015

The Sticking of a Drilling BHA and subsequent loss of tools, hole footage and hence potentially jeopardizing well objectives; is THE most costly unplanned drilling event that can occur to an Operator. It tops the table of costly NPT events ahead of items such as Well Control incidents, " waiting on weather", lost circulation, equipment failures and rig associated problems. The cost to the industry is estimated at several billions $USD per year. This is probably conservative and in the Gulf of Mexico alone in 2007, it was predicted to be 3% of the total spend on upstream oilfield equipment and services or $7.8 Billion (Dodson et al)1. This can significantly affect drilling budgets where technical and operational risk must be balanced with potential return on Investment (ROI). The technological advance into extreme hostile territory, deepwater and HPHT, makes the investment and risk higher to the extent that some wells are left undeveloped. Deepwater wells are often incurring spread dayrates for services including the rig of $1M USD per day.
Stuck pipe is a reality and the success of a recovery plan depends on a number of issues of which the most important is the efficient separation of the drillstring at the most beneficial point. Current separation technology is the same as it has been since the start of this industry albeit more advanced in its efficiency. Explosives or chemical cutting are still the only methods to separate the drillstring usually requiring mobilization of specialist equipment and personnel.
This paper discusses the application and development of an integral circulation and disconnect tool. Additional to receiving downlinks to adjust a multi position circulating valve, it processes sensory information to establish the status, " stuck" or " free" and ultimately receives a command to disconnect from the BHA or wherever it is positioned in the string. The disconnect is effected by electro / mechanical means and represents a step change in application of technology for this purpose; removing any form of surface intervention or the requirement for 3rd party specialist equipment or personnel, leaving the Operator in control of the event.
Assessment of Coatings in High pCO2 Environment for Pipeline Internal Coating Application
Authors: Zakaria Muzdalifah , Sauri Ahmad Shalabi , Abas Ahmad Zaki , Mat Saadan , Suhor M Firdaus , M Nor Azmi , Kamarudin Rozilah 
Published: February 2015

Offshore pipeline transportation of non-treated, high CO2-containing gas stream imposes significant challenges due to the anticipated high corrosion rate that could disqualify the economic use of the carbon steel material. Alternative solutions are required in order to find the most cost effective system in transporting CO2 over long distances particularly for offshore application. Several solutions exist which include application of corrosion resistance alloy (CRA), cladded or CRA- or non-metallic-lined pipes and internal coatings.
This paper is focused on the assessment of the physical properties of internal coating for pipeline transporting high CO2 gas in the dense phase under the steady state operational condition. The performance of commercially available epoxy-based coatings exposed to high pCO2 has been studied as per NACE TM0185. Three coatings from different manufacturers were tested in an autoclave at temperature of 25°C and 80°C and partial pressure of CO2 (pCO2) 80 bar and 150 bar respectively for 28 days. The coatings were evaluated for the presence of blistering, adhesion to metal and between coats, hardness and resistance to undercutting and creep. The results have shown that all the 3 coating systems did not show significant physical degradation under the test conditions. However, one of the coatings showed a reduction in the pull off adhesion at high temperature which indicates some degradation of the coating under the imposed test conditions.
The results from the lab testing have shown that commercially available coatings are able to perform well in dense CO2 phase within the defined test parameters. However, in order to reliably predict the service life of the coatings material, their performance when subjected to the variation in operation, e.g., decompression, as well the analytical methods that can give representative performance measures between laboratory test and service life, are critical and the subject of this review.