bluuebunny/crossref_metadata_2025_split huggingface dataset:
MS New Dead-Crude Oil Asphaltene Inhibitor Test Method
Authors: Jennings David W. , Cable Robert , Leonard Geoffrey 
Published: June 2014

Abstract
Asphaltene deposition is a serious problem for deepwater subsea production systems. The potential for immense production losses coupled with the difficulties and expense in remediating deposition in subsea systems make it imperative that deepwater fields are evaluated for asphaltene concerns. If concerns exist, effective prevention treatments must be designed and employed. Therefore, having effective asphaltene inhibitors and correspondingly, better methods to evaluate inhibitor performance is extremely valuable for deepwater operators.
This paper discusses a new dead-oil asphaltene stability analysis method which has shown to be effective in comparing asphaltene inhibitor performance. The method can also be used in field monitor programs. Although not a live-fluid deposition test, the method offers advantages over some currently used methods, like ASTM D7601-04. The method uses an analytical centrifuge to evaluate the stability of asphaltenes in crude oils which have been simultaneously subjected to a solvent that destabilizes asphaltenes and centrifugal force. In comparison to ASTM D7601-04, use of the new method provides a better measure of asphaltene inhibitor effectiveness in crude oils due to:the application of centrifugal force andthe ability to perform testing with higher crude oil concentrations / less destabilizing solvent. Note, ASTM D7601–04 uses more than 97 % destabilizing solvent.
Its maximum recommended crude oil concentration is 2.67 %. The new asphaltene stability analysis method has been run at crude oil concentrations from 5 – 40 volume %.
The ability to perform testing with less destabilizing solvent is particularly significant as only a fraction of the total asphaltenes deposit during production. In field conditions, only the more "insoluble" asphaltenes precipitate and deposit. By reducing the destabilized asphaltene fraction to only the more insoluble species, dead-crude oil test method conditions can be moved closer towards field conditions. The amount of asphaltenes destabilized can be altered with the choice of destabilizing solvent and amount of destabilizing solvent used. This is the approach used in the new test method. Also, by using significantly higher crude oil concentrations in the method, more destabilized asphaltenes can be generated during the test despite reducing the fraction of asphaltenes destabilized. By increasing the amount of destabilized asphaltenes, more stringent asphaltene inhibitor conditions are created in the testing since asphaltene agglomeration occurs more easily in higher-concentration environments. Further increasingly stringent conditions are created with the simultaneous application of the centrifugal force. It has been found that these more stringent conditions allow better differentiation in evaluating asphaltene inhibitor performance.
This paper shows results from the new Asphaltene-Analytical Centrifuge Stability Analysis (Asphaltene-ACSA) method with different crude oils, destabilizing solvents, and asphaltene inhibitors.
Saudi Arabia's Manifa Giant Offshore Field Development: The Role of Technology
Authors: Arukhe James , Hanbzazah Shadi , Ahmari Abdulrahman , Al Ghamdi Saleh , Yateem Karam , Aramco Saudi , Bal Moustapha , Ahmed Danish , Baez Fernando 
Published: June 2014

Abstract
Field development costs have risen with oil price. A resulting challenge with Arab heavy oil development remains how to generate competitive advantages through deploying efficient technological innovations and making cost-effective solutions a crucial part of a firm's strategy for rigless interventions. With strict commitments to environmental protection, the need for operational excellence and several process improvements necessary to yield dividends in the form of safe project delivery and to overcome several technical difficulties is vital.
The scope of the paper is to examine coiled tubing (CT) stimulation and logging technologies used in the timely project execution of one of Saudi Arabia's largest field developments to cost effectively enhance matrix stimulation success. Some of these solutions include technologies for CT reach, CT access for dual laterals, acid placement optimization, and treatment effectiveness monitoring. CT extended reach solutions comprised tapered CT strings designed for ultradeep wells, drag reducers, tractors, and vibrators. Technologies for CT access for dual laterals include a flow activated multilateral tool for CT matrix stimulation employing pressure variation telemetry with bottom hole pressure (BHP) and casing collar locator / gamma ray (CCL/GR) for high success lateral identification.
To optimize acid placements, distributed temperature survey and pressure measurements are used to enhance diversion and acid placements. A blend of tools assisted to monitor, analyze, and adjust in real-time the reservoir and stimulation fluids interaction. Viscoelastic diverting acid is designed to viscosify in situ as the fluid spends on the reacted formation for chemical diversion in carbonates. The concentration of the diverter was optimized from 20% HCl to 15% HCl. A unique solution for monitoring treatment effectiveness evolved to include real time production logging using single strings for CT stimulation and real time profiling instead of memory logging. This solution required less equipment mobilization and no wireline unit. Intervention from 99 producers and injectors reveals operational and cost benefits from deploying technological solutions and justifies the degree to which each technology solution fits the overall field development strategy.
The implications of deploying these solutions include reduction of well counts from the original estimates in this field development to offer manageable total field development costs.
A Drill Stem Well Testing Design for Extreme HP/HT Exploration Wells: Strong design along with good operating and contingency procedures are essential to achieve safe and efficient DST operations.
Authors: Milenkovic Frederic , Zarina Nik 
Published: June 2014

Abstract
Design of Extreme/Ultra (E/U) HPHT well testing, from an operator standpoint, is a difficult exercise that involves long and meticulous preparation phases, where a large proportion of the work is devoted to dealing with contingency procedures. The first step consists of the evaluation of the complexity of the project since it drives the level of preparation, level of risks, support /expertise requirements and their financial impacts. The Value Of Information must be accurately justified since HPHT well testing involves tremendous costs. The second step is to understand what it takes to deliver an E/U-HPHT in a safe and efficient manner, meeting well testing objectives. Basis of design and procedures are developed without overlooking the importance of tubing stress analysis, design reviews, quality insurance, and laboratory tests (qualification or verification). The proper well construction and its integrity is of paramount importance in the success of well testing operations since it provides the operating envelope DST tools are relying on. This envelope will be highly stressed during all DST load cases and therefore all DST components installed are designed to accommodate these stresses safely. The uncertainties of actual Pore Pressure, Temperature (down-hole and surface) and reservoir fluids make the exercise even more complicated, therefore, implying a great deal of preparations and contingencies need to be in place. The importance of selecting the right annulus fluid increases the chance of a successful operation and thus under balance versus over balance testing philosophy must be thoroughly evaluated to resolve the dilemma of well control versus DST tools operability. All this steps must be taken after a thorough review of what the current technology can offer along with the understanding of its limitation. Over the last few years, services companies noticeably pushed to develop extreme tools in order to provide viable technical solution to complex Ultra HP-HT well testing. Nevertheless, recovering the DST string is known as being one of the upmost challenge in HPHT well testing, meaning the design of the production string (including a tubing free strategy) must be planned well in advanced. No string back to surface means no down-hole data & samples, therefore missed objectives and waste of money.
This paper describes a design approach and preparation for an EU-HPHT well testing on an exploration well being the first to be implemented by PCSB.
Innovative Solutions Make China's First Marginal Subsea tie Back oil Field into Production
Authors: Jiayou Mao , Jianjun Yang , Qingdong Yuan , Yiyong Liu , Zuan Yue 
Published: June 2014

Abstract
Liuhua4–1 oil field is located 215km to the south east of Hongkong in the South China Sea. The reserve was first discovered in 1987. Due to economical and technical challenges, it was not until 2012 the development of this field become reality. The 300m water depth oil field was successfully tied back to an existing oil field Liuhua11–1 oil field through subsea pipeline, power cable and multiplex control umbilical. The project executions include disconnection, life extension and re-hook up to the existing oil field FPS. It was also China's first tie back subsea development project. In order to develop this marginal oil field, a number of technical challenges were overcome through a series of new technologies successful development and implementation.
Qualification of Flexible Flowlines: Lateral Instability Testing
Authors: Tanaka R.L. , Morini R.G. , Godinho C.A. , Swanek D. , Timms C. 
Published: June 2014

Abstract
The need for oil exploitation in ever increasing depths drives the development of structures suitable to resist very high loads. In this context, the qualification process for flexible flowlines involves physical testing to demonstrate suitable performance for the intended application and to obtain data to improve the applied design tools.
As part of the qualification process, lateral instability under external pressure and cyclic bending, known as lateral buckling (LB), was investigated for a 6-inch ID flexible pipe flowline with wet annulus conditions. This was done by performing reduced-scale prototype testing in a hyperbaric chamber with the application of cyclic bending and external pressure. The external pressure was adjusted to the application depth of the particular flexible pipe, in an attempt to replicate the typical conditions of a Deep Immersion Performance (DIP) Test. The benefit of DIP testing is that it realistically replicates the loading conditions that the flexible pipe will be subjected to during installation or operation. However, DIP tests are very expensive, whereas reduced-scale testing can be performed at much lower costs. A concern of reduced-scale testing is if these tests can duplicate the loading conditions of the DIP tests.
This paper will describe the testing program, results and its relation to the design methodology.
Development of 4,000 m Class CFRP Drilling Riser
Authors: Miyazaki Eigo , Kyo Masanori , Seki Hitoshi , Takasaki Hideto 
Published: June 2014

Japan Agency for Marine-Earth Science and Technology (JAMSTEC) is operating a deep sea scientific drilling vessel " CHIKYU" (Figure 1) to promote research on the earth sciences. 21st Century Mohole is one of the most challenging projects among current science proposals for the next decade. In this project it is proposed to penetrate oceanic crust, drill into the uppermost mantle across the Mohorovicic discontinuity and to obtain samples of mantle directly.In order to accomplish this objective, it is required to drill about 7,000m below deep sea floor which water depth is over 4,000m. One of the elements which have a great influence on the realization of this target is a deep water riser. Generally, the material of a riser is high tensile steel. However, it will be very difficult to apply the steel riser to a drilling operation in the locations of more than 4,000m water depth due to the limitation of the strength. Therefore, JAMSTEC started to study a new material riser. CFRP (Carbon Fiber Reinforced Plastic) was selected as the primary candidate for the new material. It is classified by its raw material to two types, pitch-based carbon fiber (Pitch-CF) and PAN-based carbon fiber (PAN-CF). Pitch-CF has higher modulus of longitudinal elasticity and it will be more favorable for the dynamics of the riser. In this paper, outline on the developments of pitch-based CFRP riser are presented.
Inferred Depositional History of Middle-Late Quaternary Depositional Systems using Seismic Facies Analysis and Age Dating
Authors: Oyedele O.A. , Dupre' W.R. 
Published: June 2014

Abstract
The study area is located within the Mad Dog Development Area in the Gulf of Mexico. Several studies have been carried out in the area including the use of coherence and seismic amplitudes to identify fan sands behind the prominent Sigsbee Escarpment. This paper focuses on integrating seismic attributes and age dates to infer the depositional history of key deposystems landward of the Escarpment. The assessment was achieved by using data sets donated to the University of Houston by BP America, Inc.
The detailed architectural and facies analysis of the deposystems were interpreted using 3D high resolution seismic imaging and seismic attribution. Integration of the seismic facies analysis with biostratigraphic ages was used to infer the prevalent geologic processes and thus the depositional history of the systems. Deposystems identified in this study include a channel-lobe complex, channel/glide-track features, and mass transport complexes (MTCs).
The study revealed that the mapped depositional elements were mainly controlled by the interaction of sea level changes, sedimentation, and salt movement. Analysis of the channel-lobe complex and MTCs reveal successive periods of deposition which suggest periods of high sediment supply. Age dates of bounding markers reveal that these periods coincide with low stand to rising sea level. The influence of salt movement is not discussed in this paper though it was inferred from the study.
Obsolescence Management Through Technology Qualification Processes
Authors: Strouse J. M. , Sutherland J. , Botto A. 
Published: June 2014

Abstract
Technology in the oil and gas industry is continually changing and evolving to support demands on challenging and harsh operational environments. Understanding and working with any technology has inherent risks and benefits. The development of a technology qualification process (TQP) is crucial to ensure that established methodologies for qualification and management are in place.
As technology evolves, a common industry challenge is management of obsolescence on system and subsystems, especially newly designed or emerging technologies in components. Using TQPs to assess the potential challenges of obsolescence and the progression of changes as it develops helps minimize the risks and ensure the availability of equipment. This paper will develop a series of case studies that examine the use of integrity & obsolescence management through TQPs, thus, reducing or even circumventing the high risks involved with aging and developing technologies. The first phase of the paper will compare like industries by looking into the aging and developing sectors of the nuclear industry. It will assess the processes used at aging US nuclear reactors and compare methods used to develop and manage technology in the subsea industry. The second phase will be a case study that delves into TQPs and obsolescence management of hardware in subsea control systems. This section will look at a particular set of failure modes found during operation of subsea control systems and valves, identify how to manage these changes as the product develops, and what TQPs could be used to help eliminate failures going forward. The final element of this paper will look at processes and management tools that can be used as best practices going forward and provide insight into methodologies that will best serve developing technologies for the subsea industry.
Investigation of Next Generation Subsea Power Distribution System Architectures
Authors: Duan Yao , Forrest William , Li Xin , Bjørn Ulvestad Harald 
Published: June 2014

Abstract
Subsea power is the enabling technology for subsea processing to be implemented in more challenging applications. The current point-to-point power distribution systems are not sufficient to meet the increasing demands of future subsea processing developments. The development of a robust and high capacity subsea power grid is the technological first priority to achieve future subsea processing applications.
Four power system architectures, which meet the future needs of field developments, have been modeled and simulated in EMTP-ATP under both normal and fault conditions. The major contribution is that this study identified the system characteristics and the functional requirements of the major subsea and topside power components for the future subsea power grid. Comparing to the present point-to-point connection, additional power and control equipment necessary for the subsea power grid have been proposed. The conclusion is that having a more complicated subsea power system is necessary and feasible but there are a number of technical challenges to overcome, which requires close collaboration of field operators, system integrators, and equipment suppliers.
DFA Connectivity Advisor: A New Workflow to Use Measured and Modeled Fluid Gradients for Analysis of Reservoir Connectivity
Authors: Mishra Vinay K. , Cañas Jesus A. , Betancourt Soraya S. , Dumont Hadrien , Chen Li , De Santo Ilaria , Pfeiffer Thomas , Achourov Vladislav , Hingoo Nivash , Zuo Julian Y. , Mullins Oliver C. 
Published: June 2014

Abstract
In deepwater and other high-cost environments, reservoir compartmentalization has proven to be a vexing, persistent problem that mandates new approaches for reservoir analysis. In particular, methods involving reservoir fluids can often identify compartments; however, it is far more desirable to identify reservoir connectivity. Downhole fluid analysis (DFA) has enabled cost-effective measurement of compositional gradients of reservoir fluids both vertically and laterally. Modeling of dissolved gas-liquid gradients is readily accomplished using a cubic equation of state (EOS). Modeling of dissolved solid (asphaltenes)-liquid gradients can be achieved using the newly developed Flory-Huggins-Zuo equation of state (FHZ EOS) with its reliance on the nanocolloidal description of asphaltenes within the Yen-Mullins model. The combination of new technology (DFA) and new science (FHZ EOS) provides a powerful means to address reservoir connectivity. It has previously been established that the process of equilibration of reservoir fluids generally requires good reservoir connectivity. Consequently, measured and modeled fluid equilibration is an excellent indicator of reservoir connectivity. However, some reservoir fluid processes are faster than equilibration rates of reservoir fluids. The often slow rate of fluid equilibration makes it a suitable indicator of connectivity. Consequently, measurement of disequilibrium can still be consistent with reservoir connectivity. Moreover, the two fluid gradients, dissolved gas-liquid versus dissolved solid-liquid can be separately responsive to different fluid processes, thereby complicating understanding. A workflow is developed, the DFA reservoir connectivity advisor, to enable interpretation of the implications of measured fluid gradients specifically with regard to reservoir connectivity. Reservoir connectivity is difficult to establish in any event; analyses of fluid gradients can be placed in a context of the probability of connectivity, thereby significantly improving risk management.
Middle East India Deepwater Pipeline (MEIDP) crossing of the Indus Fan
Authors: Nash Ian , Burnett Christopher , Smith Russell 
Published: June 2014

Abstract
The Middle East to India Pipeline (MEIDP) will provide an economic and secure source of gas for India, where the demand for energy will continue to increase over the coming decades. The proposed pipeline will be the deepest major infrastructure pipeline laid with water depths exceeding 3000m for significant sections of the 1200km route. In addition to its depth the MEIDP will have to contend with significant potential geohazards, namely the Indian and Omani continental slopes, the Indus Fan, the Owen Fracture zone and the Qalhat Seamount. Since the Mid 90's when the Oman India Pipeline (OIP) was first envisaged the crossing of the Indus Fan has been held up as one of the major technical challenges for such a deep pipeline.
This paper will give details of the 2013 geophysical reconnaissance survey along the MEIDP route, with particular focus on block reconnaissance performed for the area where the route crosses the Indus Fan which is characterized by two topographical main structures: The channel/levee systems of the Indus fan which dominate the central part of the survey area; and the deep sea basins in the easterly and westerly sections. The channel/levee system is characterized by central channels with a series of adjacent terraces and numerous abandoned channel loops, which are partially refilled by the overspill sediments from active canyon areas. The pipeline route crosses five turbidity current channels with side walls up to 200m high, in water depths between 2100m – 3200m. With the exception of Channel 1 the channels follow a meandering flow pattern with general N-S direction. Channel side slopes up to 25° have been detected. Channel 1 on the western edge of the block follows a meandering E-W direction.
The results of the survey will be discussed together with details of the geohazard design process required to identify a feasible route across the Indus Fan and necessary intervention works at this feature to bring this project closer to reality.
Hydrogen Embrittlement Susceptibility of Precipitation Strengthened Ni-base Superalloys
Authors: Kernion Samuel J. , Magee John H. , Werley Thomas N. , Maxwell Paul 
Published: June 2014

AbstractThis paper discusses the results of an on-going investigation to rank the hydrogen embrittlement susceptibility of precipitation strengthened Ni-based superalloys using a rising step load (RSL) technique in four-point bending. Alloys characterized include UNS N07716, UNS N09925, and UNS N07718 heat treated to various strength conditions. Hydrogen was introduced either in-situ via an applied cathodic potential (external hydrogen) or prior to testing by thermally charging in gaseous hydrogen (internal hydrogen).The RSL method measures the stress intensity required to cause propagation of a pre-existing flaw with and without the presence of hydrogen. Another method used to evaluate hydrogen embrittlement is the slow strain rate test, which characterizes material through the relative loss in ductility due to hydrogen exposure. While both methods provide a relevant measure of hydrogen embrittlement susceptibility, fracture mechanics testing such as the RSL method offers more useful information for the design of components.Results indicate hydrogen embrittlement susceptibility is related to both the microstructure and the composition of the alloy. Measured fracture toughness values are also affected by the method of hydrogen exposure, however general trends among the materials are seen. In light of these results, the relative merits of the RSL testing method compared to slow strain rate testing is addressed, with a focus on overall applicability.Failures attributed to hydrogen embrittlement of Ni-based superalloys in off-shore wells have emphasized the need to identify the limitations of these alloys in environments where the potential for hydrogen embrittlement exist.