bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unlock Tight Gas Reserves in South China Sea by a Revolutionary Formation Tester
Authors: Hongjun Yang , Shusheng Guo , Jun Cai , ChengGang Xian , Jichao Chen 
Published: February 2015

As interest grows in formations with permeability ranging from tight (&lt;1.0 md) to ultralow &lt;0.1 md), formation testing and conducting drill stem tests (DSTs) become increasingly challenging and more costly. Formation testing using conventional probes has low success rates for pressure surveys and sample collection, long pumping times, and poor data quality that cause difficulty in fluid identification because of incomplete cleanup of filtrate. DSTs are often unsuccessful without sufficient inputs of permeability and fluid properties for optimization of testing plan. This paper presents case studies of a revolutionary new 3D radial probe that makes effective evaluation possible for unlocking tight gas reservoirs in the South China Sea.
The tight gas formations have poor borehole condition for conventional probe sealing and testing. A total of 25 attempts by two different conventional probes fail to seal. However, three stations for the 3D radial probe took less than 4 hours per station to successfully collect PVT-quality samples. Fast cleanup to flow pure formation fluids enabled better accuracy in real-time fluid identification, sampling assurance, and compositional analysis including CO2. Transient analysis indicated that all stations have &lt;0.1-md/cp effective mobilities, with the lowest at 0.03 md/cp. Production prediction was conducted to assess the natural productivity. Comparison with DST results from neighboring wells show that this prediction has acceptable accuracy and is sufficient for crucial decision making. This enables the operator to avoid unnecessary DST stations and ensure optimal completion and well testing designs.
Performance was compared against conventional modules. The advantages of the 3D radial probe over elliptical probes and dual-packer module in this kind of tight gas reservoirs are obvious and significant, with better efficiency, quality and operability such as applicable differential pressure, sealing capability, minimum storage, no exposure to borehole mud, and less sticking and plugging probabilities. Numerical modeling of an immiscible water-gas system with representative borehole conditions and reservoir properties of tight gas formations was conducted to investigate flow and pressure transient behaviors for operation optimization. Initial results of the simulations will be briefly discussed in this paper.
Applications and Performance of Trenching Technologies in Asia-Pacific
Authors: Brunning P. , Machin J. 
Published: February 2015

Description ofproposed paper:
Burial ofsubmarine pipelines and cables is standard practice in offshore oil and gas regionswhere potentially damaging threats such as interaction with fishing gear anddragged anchors are high. The requirement to bury pipelines in Asia-Pacific hasnot had the same imperative as the North Sea for example but this region is nowseeing a growing demand for pipeline burial to increase mechanical protectionand stability. Performance benchmarks for most trenching systems are based onthe seabed soils typically found in the North Sea and consequently do notinclude the unusual carbonate rich seabed sediments that are prevalent in theAsia-Pacific region which are often cemented and pose a significant challenge to trenching.

Application:
Trenching isconsidered an activity with significant risk so it is particularly important toselect the correct tool for the field conditions and to establish realisticperformance criteria based on regional experience in the prevailing seabedsoils, including carbonate rich sediments. This paper addressesthe primary differences that exist in seabed sediments and trenching conditionsbetween Asia-Pacific and other regions and show how these dissimilaritiesimpact on the choice of burial equipmentand tool performance. Results, Observations, and Conclusions:A state of theart review of trenching methods and technologies is presented. Trenching casestudies from Australia and Asia are presented which highlight the challenges ofdesigning an appropriate protection and burial strategy for this region and providesindications of actual performance that can be expected across the range ofseabed conditions typically found in the Asia-Pacific region. This includesdata for trenching in harder cemented soils to help fill the gaps associatedwith performance predictions in carbonate sediments. Significance of

Subject Matter:
The significanceof this proposal paper can be summarised as follows:It provide a reference point onwhich to plan trenching work in Asia-Pacific region,It addresses the knowledge gapsassociated with the relative inexperience of trenching in Asia-Pacific regionPerformance benchmarking is extendedto include the carbonate rich and cemented sediments.
Optimized Platform Placement to Cover All Geological Targets in Baronia Field
Authors: Sofian M. Anas , Leuranguer Christophe , Bt Musiran Noor Farahana , Saifuddin Afiqah Fathiah Ahmad , Wong Thomas , Kardani Ilen 
Published: February 2015

Platform placement and sizing are critical steps for enabling subsequent operations such as well construction, logistics, and facilities installation to be performed efficiently and safely. This paper introduces the most economical yet efficient solution for a PETRONAS enhanced oil recovery (EOR) project in which 25 wells were to be drilled in Baronia field, offshore of Sarawak, Malaysia. Collaborative teamwork from drilling, reservoir, facility, geology, and production groups was required to develop the best solutions to minimize construction work, simplify well trajectories, and utilize all available resources to help minimize the overall budget.
In addition, this paper evaluates the drillability of each well based on available drilling technologies and rig capabilities in the market.
During the initial design stage, all 25 wells were planned to be drilled from two new wellhead platforms (WHP) to intercept all geological targets. Major well collision problems were encountered against adjacent wells in the congested Baronia field; however, after several iterations of surface nudging and slots designation, all wells were drillable, with a total footage of 227,527.1 ft drilled.
The first iteration was performed by placing one new single WHP at an optimized location and using spare slots and sidetracking from an existing platform. This optimized design reduced/saved 39,868.61 ft compared to the initial stage and eliminated the requirement for another new platform. The second iteration was performed by shifting the new WHP 300 ft closer to the production platform to enable bridge linking and help reduce construction work on the pipelines. The total footage to be drilled from this location was reduced again by 3,622.63 ft. Finally, the setup was further optimized by equipping the new platform with splitter wells, which reduced the number of conductor pipes required without decreasing the number of wells to be drilled.
Overall, the platform placement and sizing optimizations saved millions of dollars in the planning stage by eliminating one platform, decreasing drilling footage, minimizing construction work, and helping reduce health, safety, and environment risks.
Improved Zonal Isolation in High-Temperature Offshore Wells with an Advanced Lightweight Cement Design - Gulf of Thailand Case Histories
Authors: Brandl Andreas , Valentino Vincentius , Fauchille Guillaume , Syed Haidher , Dean Greg , Stanley Rick , Rivera Nemboy Nemesio 
Published: February 2015

The Gulf of Thailand is characterized by shallow-water wells that are hot and deviated, with low fracture gradients and bottomhole static temperatures of 450°F (and some wells approaching 520°F). Drilling depths average 12,000 ft measured depth (9,000 ft vertical) and fast drilling practices are used for slimhole monobore completions, resulting in daily cementing jobs from each of the offshore rigs. Many jobs are executed in batch mode and are performed offline on the production deck under the rig floor. As a consequence these fast-paced, streamlined, and simultaneous offshore activities require a high degree of rig integration as well as logistically and operationally simple high-performance cementing systems to avoid expensive rig delays. The performance demands on the cement slurries include low density, uncomplicated on-the-fly mixing, low fluid loss, gas invasion control, and stability under the very hot wellbore conditions.
This paper will present an advanced lightweight seawater-based cementing concept using a single cement blend with only 3 to 4 primary liquid additives (including a multifunctional polymer) to adjust all primary cement jobs for the entire wellbore. A sophisticated lab testing program (such as analyzing slurry gas invasion) was conducted for the innovative cementing concept according to the required demands on cement slurry design and the given harsh wellbore conditions in the Gulf of Thailand. Tests revealed that the developed cementing systems meet all operator and well requirements despite their relative low densities of 13.3 to 14.0 ppg with high water content.
The advanced lightweight cementing design was successfully pumped in 311 Thailand offshore wells during 2012, and its performance was directly compared to previous cementing systems used in more than 1,000 wells in the same fields from 2009 to 2012. Lab test results, pre-job planning, cement job execution and cement bond logs are evaluated and discussed. The case histories conclude that the advanced lightweight cement design significantly improved the quality of zonal isolation in wellbores. Valuable design-effect relationship elements found in this study (such as the impact of the multi-functional polymer on slurry stability and gas control) will be discussed for applications on other upcoming and challenging drilling projects in Asia.
Importance of Thermal/Stress Loading Analysis for Tubulars in HPHT Wells
Authors: Shahreyar Noman , Finley Douglas 
Published: February 2015

The upstream oil and gas industry is experiencing increased interest in exploration and production from the more complex, hostile, and deeper geologic horizons that are classified as high-pressure, high-temperature (HPHT) reservoirs. Well completion planning and design is becoming increasingly more critical and challenging because of the uncertainty that typically is experienced from the high pressure and temperature changes that can occur in operational scenarios during the well's lifecycle.
The cost of a typical tubing completion equipment usually represents 15 to 25% of overall well cost. High operating temperatures and pressures cause significant pipe movement and high axial loads at the packer and tubing during the well operation. For wells where design margins can be slim, a detailed and robust stress-loading analysis and the aid of modern thermal-and-stress- analysis software can balance tubular equipment design versus risk. This approach provides savings on tubular cost by optimizing the tubing design so that it meets the company's integrity standards without being overdesigned.
This paper discusses an engineering design methodology that can be followed for tubular equipment sizing and selection for complex wells. A typical list of reservoir and well parameters that are required to set up the well model for the thermal and stress loading analysis is presented. Importance of estimated thermal simulation is highlighted for tubular selection and design. A full integrity analysis for well casing and tubing design integrity will be performed for a complex, deep-water, high-rate, HPHT example well. The analysis will cover various anticipated operating loads during the life of the well and will include the effects of stimulation, production, and EOR flooding. Results are presented showing changes in temperature and pressures during well operating scenarios and impact of temperature changes on tubulars stress loading. Sensitivity analysis is then performed with applied landing forces on the completion for further discussion on limitations on well operating conditions during well life cycle.
Utilising Aerogel in Effective Oil Spill Cleanup and Recovery
Authors: Singh Apoorv 
Published: February 2015

Oil spill is currently a burning issue. The damage to the environment caused by an oil spill of any size demands immediate cleanup. The issue of Arctic drilling is of global concern and the industry must be equipped to tackle the problem of oil spill, if any. Current oil spill cleanup methods include booms, skimmers, and centrifuges. However, these containment methods have not been successful as nearly 60,000 barrels of oil are released into the water each day, and their efficiency to collect the leaked oil is too low. The paper presents an approach to solve this problem by use of porous material that not only absorb oil effectively but also provide a way to recover the spilled oil.
Aerogel is such a synthetic porous material derived from a gel, in which the liquid component of the gel has been replaced with a gas. The product formed is a solid with very low density. A form of this Aerogel is made by mixing clay with a polymer and water in a blender. The mixture is then freeze-dried, air fills the gaps left by the loss of water, and the resulting material is ultra- lightweight sponge, comprising of about 96% air. The Aerogels are synthesized by a NH4OH catalyzed reaction and are found to be hydrophobic. Treating oil and salt-water mixtures with the aerogel at an oil to aerogel ratio of 3.5 showed that all CF3-aerogels efficiently separated oil from water, absorbing oil as much as 237 times of their weight. The present hurdle with the industrial application of Aerogel is its economical feasibility which can surely be overcome in upcoming years with the recent advancements in technologies. Future oil spills can be very effectively tackled by the use of Aerogels or other porous materials as Oil Spill Cleanup agents.
Infield Transportation of High Content CO2 Fluids
Authors: Condat C Taravel , Denniel S 
Published: February 2015

There is a strong demand in the subsea oil and gas industry for cost effective solutions for transportation of highly corrosive fluids. In particular, high concentrations of CO2 are prevalent in both injection fluids (up to 90%) to enhance the oil recovery process and in some production fluids (up to 75%). This paper will present the work carried out to qualify reeled rigid and flexible pipes for transportation of fluids containing very high pressure of CO2.
For flexible pipes, this work concentrated on qualification of several thermoplastic materials used for pressure sheathes and stainless steel materials used for inner carcasses, and it covers application as high as 90°C/600bar/100%CO2. Qualification of stainless steels carcasses for production applications containing high level of CO2 and chlorides has also been conducted.
For rigid pipe applications, Corrosion Resistant Alloy (CRA) can be used either as the linepipe material or as a metallurgicaly bonded liner to the inside of a carbon steel or stainless steel linepipe. Mechanically Lined Pipe (MLP) is a cost effective alternative to metallurgical bonding which has been qualified for installation by reel lay method at atmospheric pressure for static flowline and dynamic riser application. The qualification process complied with DNV "Qualification of New Technologies".
Measured Wave Spectra Offshore Sabah & Sarawak, Malaysia
Authors: Amurol Jamal Sharizal , Ewans Kevin , Sheikh Rizwan 
Published: February 2015

The use of wave spectra in offshore engineering is a key ingredient of the design process. Empirical formulations of wave spectra are used extensively in offshore engineering. These spectra describe a smooth spectral density that represents the wave energy density for a given wave frequency and direction. Two of the most commonly used spectral formulations are forms of the Pierson Moskowitz (PM) and JONSWAP formulations, which describe fully develop and fetch-limited seas, respectively. An interesting result of the JONSWAP study is that a wave spectrum continues to evolve with increasing fetch or duration without actually becoming fully developed.
The JONSWAP spectrum, which was derived from fetch-limited measurements made in the North Sea, has a mean shape represented with a peak enhancement factor, [[Unsupported Character - Symbol Font &#61543;]], equal to 3.3, which in engineering applications is often adopted on the assumption that this spectral shape is valid for all locations. This is primarily because historically there has been insufficient measured raw wave data to enable the characterization of basin specific wave spectra. In reality, the wind field is rarely sufficiently steady or spatially homogeneous for sea states to be fetch-limited, and as a result the mean JONSWAP formulation may not be suitable to describe wave energy densities for design purposes.
This paper presents the results of a study of measured wave spectra offshore Sabah and Sarawak, Malaysia. The study is the first systematic analysis of raw wave data to determine the shape of the wave spectrum offshore NW Borneo. The characteristics of these measured spectra are discussed here together with a comparison to the JONSWAP formulation.
Condition-Based Pigging for Pipeline Network
Authors: Zainal Abidin S. , Norman A. , Khairil Hing A. , Juzaimi N. , Ismail M. , Alias M. 
Published: February 2015

Pigging operation is primarily conducted for flow assurance and integrity of the pipeline. It will ensure maximum throughput and minimize internal pipeline wall corrosion by removing debris, asphaltene, sulfate reducing bacteria (SRB) and other impurities from the pipeline. Currently at PMO, pigging operation is conducted per time-based as required by pipeline's Corrosion Management Plan (CMP). The pigging frequency will be revised should there are changes to the amount of water holdup inside the pipeline. Since there is no reliable way to predict how much water holdup and heavies will deposit, pigging frequency can be optimized only by learning system behavior. Once the system behavior is better understood, the condition-based pigging frequency can be optimized.
Mathematical study utilizing numerical method analysis was performed by doing mass balance analysis of the recorded pipeline discharge and landing flowrate. Daily flowrate discrepancies between inlet and outlet flow were plotted. Cumulative flowrate discrepancies were calculated via a numerical method analysis technique. Data delay was also considered based on pig traveling time and/or fluid velocity in pipeline. Pipeline simulation model was developed using iCON with OLGAS 3Phase flow correlation to validate liquid hold up findings from numerical analysis. Other relevant parameters and profiles of the pipelines are also calculated such as pressure, temperature, velocity and flow regime. iCON is a steady state and dynamic simulation software widely used in PETRONAS with a variety of applications for upstream and downstream businesses.
The study has realized accurate approach to quantify the amount of liquid hold-up volume as well as other operating parameters such as velocity, pressure profile, flow regime and temperature to identify the pigging requirements for the pipelines for Tapis-P to TCOT pipeline. PMO pipeline engineer optimized pigging activities by switching from time-based to condition-based pigging. Several case studies were demonstrated in this paper to show that the modeling techniques applied matched liquid holdup accumulated at receiving terminal.
Successful Development and Application of Sand Transport Correlation for Upstream Oil & Gas Application
Authors: Zamberi M.S.A. , Shaffee S. , Moh C.K. , Jadid M. , Johar Z. , Wong C.Y. 
Published: February 2015

Sand production related problems are common in E&P operation. Understanding and predicting sand transport is one of the key elements to develop an effective sand management strategy.
From a review conducted, it was found that majority of the sand transport prediction correlations available in the literature were developed through experimental conditions that were closer towards the mineral and mining industries. This paper discusses the development of an enhanced critical sand transport velocity correlation through experimental campaign focusing on improving the correlation for upstream oil and gas application especially on the effect of sand concentration, fluid viscosity and flow inclination angle. Comparison with several third party experimental data is provided, showing the improved accuracy of the developed correlation in conditions closer to upstream oil and gas operation.
The experimental campaign consist of flow loop experiments at selected sand (concentration &lt;&lt;1%vol-vol, size up to 200 micron, angular shape) and fluid conditions (viscosity between 1 to 10cP), and at different inclination angles. Using the experimental results, a sand transport correlation was enhanced which showed much improved accuracy compared to existing sand transport correlations (average deviations of the enhanced and existing correlations are ±7% and 40% respectively). The enhanced correlation was also able to predict accurately (less than 10% deviation) of third party experimental data. The correlation is also able to qualitatively match sand monitoring data from several operating wells.
Finally, application of the correlation in developing an effective sand management strategy for high-sand-producing wells in Malaysia, through integration with a sand erosion prediction tool is discussed whereby the current field practice in surface sand management was reassessed resulting to incremental hydrocarbon production.
How to Increase Recovery of Hydrocarbons Utilizing Subsea Processing Technology
Authors: Marjohan Rudisham 
Published: February 2015

Abstract
As demand for oil escalates and resources from the relatively simple onshore and shallow water fields become relentlessly depleted, oil companies are compelled to focus on more remote, complicated and deeper water reserves. At the same time, emerging technologies to increase recovery and extend the life of brownfield developments often requires moving this equipment to the seabed due to topside space, capacity and integrity constraints.
These technological challenges are now being met head-on with subsea processing and the need to provide an increased recovery factor to justify the large investment made. Not only does subsea processing become an enabler for producing from these challenging environments, it also frees up space on the topsides while allowing expansions to be implemented on the seabed, with the additional benefit of offering significant cost saving possibilities. Notably, subsea boosting has demonstrated added value for increased hydrocarbon recovery through several commercial installations since 1995.
This technical presentation will focus on increasing recovery of oil and gas by implementation of subsea processing techniques and in particular, subsea boosting. An overview of the different applications of subsea boosting systems will be given. This will cover options that include subsea single-phase and multiphase hydrocarbon boosting, subsea seawater injection, and finally, subsea compression with a world's first, true multiphase compressor.
A number of case studies where significant increase in production has been seen as a result of implementing subsea boosting at the seabed will be presented. These cases will demonstrate the key production enabling techniques that allow enhanced recovery from deeper waters, as well as production of heavier and more viscous fluids, including high water cut production.