bluuebunny/crossref_metadata_2025 huggingface dataset:
Unconventional Forecasting Method for Brown Field on Primary Depletion - An Example of a Naturally Fractured Reservoir
Authors: Maricic N. , Zuluaga E. , Somasundaran S. , Manzoor A. , Bungo E. , Saeedi A.
Published: April 2015

A novel in-house technique has been developed for infill well production forecasting for brown fields on primary depletion as an alternative method to forecast production when reservoir simulation models are not available. The paper demonstrates the use of an unconventional approach to forecast infill well performance for a complex carbonate reservoir with fractures and vuggy porosity on primary depletion.

The flow equation was used to determine the initial rates of new development wells and to address expected pressure depletion while a new methodology was developed to take into account well interference. The interference equation takes into account five factors classified as main contributors to well production interference: distance to nearby producers, years on production of existing wells and respective initial rates, presence of faults and density of natural fractures. A correlation between these factors and lost oil volume was established based on historical production data and used to predict the interference of new development wells taking into account their locations. The statistical analysis factored all combinations of potential outcomes for new wells based on historical data and built probabilistic cumulative distribution curve to predict performance of new wells, generating a P10/P50/P90 range of production forecast. Also, a methodology was developed to account for gas and water production, which is also described in the paper.
Understanding Gas Hydrate Growth in Partially Dispersed and Water Continuous Systems from Flowloop Tests
Authors: Vijayamohan P. , Majid A. , Chaudhari P. , Sum A. K. , Koh C.A. , Dellacase E. , Volk M.
Published: April 2015

Gas hydrates are crystalline solids that can plug subsea oil and gas flowlines and are considered a major flow assurance problem. The risk of hydrate plug formation is significantly increased when free water is present in the flowline. Transportability of hydrates has a strong dependence on the total amount of liquids (the carrier phase) present, along with the mixture velocity of the fluids. It is also shown that partially dispersed systems (water dispersed in oil and free water) tend to fail at lower hydrate fraction, compared to completely dispersed systems (no free water) for the same set of conditions. This paper presents the results and analyses of flowloop experiments on partially dispersed systems as a function of water volume fraction, velocity, liquid loading, and oil properties.

A mechanistic model for hydrate plugging of flowlines in partially dispersed system is developed based on flowloop data obtained at the University of Tulsa. Once the hydrates form at the water-oil interface, they soak up large amounts of water thereby depleting the system of a carrier phase which makes transportability very difficult. The plugging mechanism for these systems is a combination of various phenomena (wall growth, agglomeration, bedding/settling, etc.). Experimental data indicates that liquid loading and water cut play a very important role when it comes to transportability of hydrates. The data from the tests performed provide the basis for a mechanistic model for hydrate formation and plugging in partially dispersed systems. A correlation is being developed/modified to predict the onset of plugging in terms of easily measurable variables like the oil viscosity, mixture velocity, etc. Preliminary analysis of the results of experiments using different viscosity oils show that viscosity of oil is an important parameter that determines transportability, and higher viscosity oils tend to facilitate better hydrate transportability.

The work resulting from our experiments should be incorporated into flow assurance models and will ultimately help to advance operating company production strategies to reduce hydrate plugging risks in complex multiphase systems.
A Model for Surface Diffusion of Adsorbed Gas in Nanopores of Shale Gas Reservoirs
Authors: Wu Keliu , Li Xiangfang , Wang Chenchen , Yu Wei , Chen Zhangxin
Published: April 2015

Surface diffusion plays a key role in gas mass transfer due to the majority of adsorbed gas with abundant nanopores of organic matter in shale gas reservoirs. Surface diffusion simulation is very complex as a result of high reservoir pressure, surface heterogeneity and non-isothermal desorption in shale gas reservoirs. In this paper, a new model of surface diffusion for adsorbed gas in shale gas reservoirs is established, which is based on a Hwang model derived under low pressure condition and considers the effect of adsorbed gas coverage under high pressure. Additionally, this new model considers the effects of surface heterogeneity, isosteric sorption heat and non-isothermal gas desorption. Results show that: (1) the surface diffusion coefficient increases with pressure and temperature, while it decreases with activation energy and gas molecular weight; (2) contributions of viscous flow, Knudsen diffusion and surface diffusion to the total gas mass transfer are varying during the development of shale gas reservoirs, which are mainly controlled by nanopore-scale and pressure; (3) in micropores (pore radius < 2nm), the contribution of surface diffusion to the gas mass transfer is dominant, up to 92.95%; in macropores (pore radius > 50nm), the contribution is less than 4.39%, which is negligible; in mesopores (2nm < pore radius < 50nm), the contribution is between micropores and macropores.
The Implementation of a Game Changing Imperium Inspection Technology into the Subsea Domain
Authors: Lasser B , Rich D. , Rhodes J , Gair G , Krugel C
Published: April 2015

Imperium and Subsea 7 have been developing the subsea implementation of the proven Imperium acoustic camera for material defect detection and corrosion mapping. The Imperium tool is well established with terrestrial industries and is the primary defect detection tool within the aerospace and petrochemical industries, beginning with advanced composite materials and more recently extending to pipeline and storage tank inspection. The applications of this technology will considerably enhance the ability of subsea asset owners to detect problems, baseline predictive modelling, optimize up time and extend asset life.

The system generates real time two-dimensional images of subsurface anomalies. Internal corrosion and cracks can be simply and quickly imaged without extensive training or setup. A simple calibration procedure allows internal defects to be visualized immediately and provide thickness data. The technique is based on optical practices, using a large area source of ultrasound, a beamsplitter, an acoustic lens set, and a two-dimensional imaging array. The output of the patented approach is high resolution, real time C-scan imagery. These images can be stitched together as the probe is moved over the target under study to map out larger areas if desired.

There are inherent problems in delivering this technology to the subsea environment. These have been addressed resulting in the first phase diver hand held device ultrasound imaging systems, which replace a number of existing tools required for a variety of NDT tasks. These can now all be undertaken with the one device.

This paper describes the technical functionality and output of the acoustic camera, with an outline of the development program. The application, results obtained and considerable benefits will then be detailed.
Optimizations and Tubular Practice from Integrated Packer Stress Analyses during High-Rate, Multiple Acid Jobs in Low-Permeability, HPHT Reservoirs, China
Authors: Fuxiang Zhang , Liangliang Ding , Xiangtong Yang , Rosland Habil Akram
Published: April 2015

This paper presents various case studies that were performed on an HPHT gas well located in the Tarim Basin, China, with a primary focus on well completion, string design, and technique in response to packer-seal failure resulting from the interconnection of production casing pressure when conducting staged acid jobs with a straddle-packer string. After tripping out, it was discovered that the upper packer mandrel was broken. This paper discusses the factors that led to the broken mandrel and packer-seal failure and provides a unique solution to these challenges during staged acid jobs.

Based on a detailed investigation conducted at the scene and further post-mortem studies using an advanced wellbore temperature simulator that integrates with tubing and packer-stress analyses, it is believed that acid jobs using a heavy-duty pump under high pump pressures have resulted in a rapid temperature drop inside the wellbore, causing possible liquid contraction within the enclosed space between the straddle packers and, subsequently, decreasing the pressure. High differential pressure between the upper and lower packer, as well as inside and outside of the enclosed space, can lead to a broken mandrel and packer-seal failure.

This paper discusses the failures that were analyzed using a comprehensive model that integrates with tubing and packer-stress analyses by implementing multiple iterations and conditions with variations in pressure that were established between the packers during acid jobs. In addition, the string mechanical-analysis method was used for the staged acid jobs. Based on case studies on the different methods for mitigating string challenges, a method was selected as the primary measure for improving string safety during staged acid jobs for high-pressure wells, which has been successfully applied in staged acid-job operations for two wells in this field.

Various models for tubing and packer mechanical analysis for staged acid jobs were established, providing a better understanding of pressure with change in temperature within the enclosed space between packers. The results were able to explain the causes of packer failure from the string mechanical point of view, which identifies the effect of various parameters on pressures within the enclosed space and the effect of pressure change to the packer and tubing stresses. The results were supported by a detailed investigation conducted at the wellsite.

The thesis of this paper introduces various methods for improving the safety of packers and strings, including increasing the temperature of injected fluid, tapping on the string between packers, and optimizing string design. Based on analysis and field study, tapping on the string between packers has been the best measure for improving string safety during staged acid jobs for high-pressure wells in this field.
Well Testing Technique for HPHT Sour Gas Wells in China
Authors: Wei Pang , Juan Du , Tongyi Zhang , Zhiguo Qiao , Gang Lu
Published: April 2015

Yuanba Gas Field is one of the most difficult fields categorized as Super-deep and high-pressure high-temperature (HPHT) reservoirs to develop not only in China but also in the world. It's buried in vertical depth (TVD) of nearlly 7000 m, and with pressure as high as 70 MPa while temperature from 149.5°C to 157.4°C, meanwhile, the average concentration of hydrogen sulfide (H2S) and carbon dioxide (CO2) are 5.14% and 7.5%. In order to successfully exploit this gas field, many problems must be solved in well testing tecniques.

In this paper, we review the most common failures of HPHT sour gas well testing tools and tubular and generalized three major failure types based on analysis of more than 80 wells*times, meanwhile, the potential reasons related to each kind of failures are analyzed. Improvements on tools and operation techniques are conducted. The mandrel of the testing packer is optimized on the basis of axial force simulation and tensile strength is increased from 383 to 618 kN. Three kinds of well testing string assembly are formed to accommodate different well types, different combination operations (i.e., combination of perforation and well testing, combination of perforation-acid stimulating-testing). Well killing and pluging techniques are improve to guarantee the succesful ratio of well testing operations.

The research reviewd field experience and proposes development techniques for well testing of HPHT sour gas field. It can also be taken as a reference for economic and safety development of other reservoirs in extremely harsh environment.
A Value of Information Demonstration for Geohazard and Georisk Assessments
Authors: Trainor-Guitton Whitney
Published: April 2015

Value of information (VOI) is a metric that can be used to determine if a particular data type should be purchased. The VOI analysis is based on how the information or data (used interchangeably here) could influence a decision taken, and consequently, improve the outcome. VOI has been used extensively for engineering applications related to product design and safety. VOI has also been used for geoscience applications related to groundwater remediation and oil exploration. The distinction of recent VOI work as applied to geoscience applications has been to include the spatial aspect of both pieces of the VOI framework: the decision and the data. Spatial uncertainty has not been previously included in many VOI calculations. This paper provides an example that demonstrates how VOI could be applied to deep-water geohazard investigations. Future work could be to extend the recent advances of spatial VOI to the deepwater application.
Measurement of Wellhead Fatigue
Authors: Howells Hugh , Baker Richard , Rimmer Alex
Published: April 2015

Fatigue loading on subsea wellheads has been increasing in recent years through the use of larger and heavier BOP stacks and the longer drilling durations needed for deeper wells and to extend production lives. This challenge has prompted the widespread implementation of monitoring systems to confirm predictions of wellhead fatigue and ensure well operations are conducted safely. Monitoring system design requirements, data processing and evaluation of field measurements from a number of wells are described.

Monitoring systems for measurement of wellhead fatigue require careful planning. Considerations include what to measure, instrument accuracy, power, data transmission, methods of attachment, data processing and data storage. The evaluation will determine the suitability of off-the-shelf equipment or the need for application specific devices. An example assessment of the requirements of measurement devices from which wellhead fatigue can be derived is given that demonstrates the importance of integrated consideration of instruments, resolution and data processing methods in the selection and design of the system. The assessment presented here has widespread application across subsea wellhead systems worldwide.

A variety of different approaches to monitoring wellhead system fatigue have been attempted. These include motion measurement, using devices located in varying positions along the wellhead and BOP, to strain measurement of the conductor pipe. Examples of real systems used in different geographical locations and the wellhead system fatigue damage derived from the data are presented. The improved understanding of wellhead behaviour and modelling improvements that can be made from the use of the data obtained are demonstrated. Finally, comparisons of response measurements from different devices demonstrate the importance of instrument positioning. This finding provides a driver for the design of future instrumentation systems and an important pointer for verification of wellhead fatigue damage derived from previous monitoring programs.

The work presented here provides a systematic basis for design and implementation of wellhead fatigue monitoring systems. Furthermore, the field measurements obtained demonstrate some potential pitfalls to be avoided and how to get maximum value from the data obtained.
The Risk of Cryogenic Liquid Release Could Have Been a Show Stopper for the FLNG Market: How Did the Industry Respond?
Authors: Wade R
Published: April 2015

Liquid natural gas (LNG) at atmospheric pressure, remains as a liquid at -162°C. As the temperature increases, gas is evolved which is flammable and under certain mixtures with air is explosive when in the presence of an ignition source.

As designers have looked more at the risks posed by accidental release of Cryogenic Liquids onboard FLNG assets, it has become more apparent that the steel structures used for these facilities could be prone to brittle fracture. This could potentially lead to structural failure. If fire ensues soon after this cryogenic release then further escalation may occur, particularly if the passive fire protection does not function as expected.

The need for effective, tried and tested solutions to mitigate the risks posed by cryogenic liquid gas exposure was identified nearly 20 years ago. In the last 10 years, as the FLNG industry has accelerated, development has intensified for cryogenic spill protection (CSP) systems. Indeed construction of a leading FLNG asset was nearly stopped due to the lack of an effective solution. In response, owners have initiated studies into the most effective CSP materials to ensure progression of these projects.

Since then, the industry has developed a better understanding of the risks posed by these LNG liquefaction assets and the consequences of not addressing these risks appropriately. Working closely with owners and design engineers to address these project specific risks and to develop robust solutions, has therefore become of paramount importance in developing this appropriate response.

This paper covers the initial requirements of protection against cryogenic spill. It considers the solutions developed to meet all the industry expectations (and where appropriate conformance to standards) and describes those finally adopted by the first FLNGs under construction.
More Improvements to Deepwater Subsea Measurement - Overview
Authors: Letton W. , Pappas J.M. , Shen J.
Published: April 2015

Since the beginning of the last decade efforts have been underway to develop new measurement technologies for ultra-deepwater oil and gas production. Though initial R&D activities were carried out by individual companies, after a few years interested parties began to pool their efforts.

The first such endeavor was a project sponsored by the DeepStar consortium, Improved Multiphase Metering for Subsea Tiebacks, performed in 2006 and 2007. Beginning at the end of 2008 a larger effort – Improvements to Deepwater Subsea Measurement – was initiated by the U.S. Department of Energy's National Energy Technology Laboratory under the Research Partnership to Secure Energy for America (RPSEA). RPSEA was a product of the U.S. Energy Policy Act of 2005, and was aimed at encouraging technology development in oilfield exploration and production, of which ultra-deepwater was a major element. Key to the project's success was the active support of a JIP sponsored by seven deepwater operating companies: BHP, BP, Chevron, ConocoPhillips, Shell, Statoil, and Total. After the first project was completed in 2011, RPSEA approved a Phase 2 effort to extend the results that had been achieved in the first project.

The new project – More Improvements to Deepwater Subsea Measurement – has addressed those gaps that were viewed as the most pressing for multiphase flow measurement by the new JIP (Chevron, ConocoPhillips, GE, Statoil, and Total): Deepwater Fluid SamplingDeepwater Meter Verification TechnologyEarly Kick DetectionDownhole Differential Pressure Sensor DevelopmentVirtual Flow Meter EvaluationDetection of Meter Fouling

These technology developments are significant due to the increasing global importance of subsea production. Improved recovery from deepwater reservoirs could yield millions of barrels of additional reserves, but to achieve this goal requires better, more reliable measurement at the sea floor. Equally important is insuring that royalty assessment and production allocation are precise and equitable.

However, a noteworthy application for these new measurement technologies is in the areas of drilling operations. Better, more extensive measurement can be pivotal in preventing the loss of well control. Certain aspects of this new measurement project aim at this goal, as will be explained in the companion papers and presentations to this one.

This paper and presentation will provide an overview of these areas of development, with details of the achievements in each of the target areas described in the six papers/presentations that follow.
Suction Pile Allowable Suction Pressure Envelopes Based on Soil Failure and Structural Buckling
Authors: Yuan-Hung Kuo , Bo-Siou Wei
Published: April 2015

This study develops the allowable suction pressure envelopes using applicable industrial codes for different suction pile sizes at various penetration depths. In addition to the industrial codes, 3D nonlinear finite element analysis (FEA) utilizing plate buckling techniques is carried out for comparisons. Traditionally, the suction pile design has considered very comprehensive soil failure mechanisms in general practice. However, the structural plate buckling criteria for suction pile with large D/t ratios are not well defined to reflect the current industrial codes and standards. This paper performs extensive study to investigate the buckling strength of suction piles with various D/t ratios using different industrial codes and standards. This study also proposes the 3D nonlinear FEA including the geometric and material nonlinearity and using the plate buckling technique in order to predict the buckling strength for piles with various D/t ratios. The above approaches can provide thorough comparisons among different code requirements and FEA results. After suction pile's self-penetration, the initial suction pressure required to mobilize the force penetration can be critical for pile shell buckling, especially for the large D/t and long pile. This required suction pressure due to moderate soil setup and static friction is briefly discussed in this paper. Based on this study, different codes and standards suggest different buckling strengths to the same pile. In general, for piles with D/t ratio less than 120 and with small L/D ratio, the suction pressure to fail the pile structure is much higher than that for the soil plug failure in regular clay soil; nevertheless, this may not be applicable for piles with D/t ratio greater than 120 and with large L/D ratio. The industrial codes and standards using thin wall theories shall be adopted to design suction piles w in order to take into account various structural buckling modes. For the 3D nonlinear FEA, the post buckling analyses predict the suction pile buckling pressures and show the reduction in pressure after buckling rather than traditionally selected buckling pressure at an arbitrary displacement regardless pile geometries. The proposed approaches to generate the allowable suction pressure envelopes can lead to an economical suction pile design and provide the installation contractor with a visualize tool to ensure a safe and successful suction pile installation.
Managing Total Fluid Loss is Critical for Well Integrity Management
Authors: Savari Sharath , Whitfill Donald L.
Published: April 2015

Well integrity management (WIM) is predominantly viewed from a perspective in which technical, mechanical, and operational solutions are applied to help reduce the risk of uncontrolled release of wellbore fluids at unwanted times throughout the life of a well. Wellhead integrity, completion integrity, and zonal isolation are a few of the key performance indicator (KPI) parameters considered. This paper discusses WIM from a drilling fluid management perspective. Drilling fluid loss (lost circulation), if not properly addressed at the correct time, can lead to significant well control issues. Particulate lost circulation materials (LCMs) have been in use to manage lost circulation for many years. This paper discusses preventive (proactive) and remedial (reactive) operational strategies to deal with such issues.

Preventive strategies are employed to help reduce the potential for lost circulation. This strategy involves the initial consideration of lost circulation management from the wellbore planning/design phase. Improved drilling practices can be emphasized and planned by examining drilling fluid hydraulics and all other fluid engineering aspects. Finally, effective preventive engineered solutions can be considered and made available to manage losses well before they are encountered. Conversely, a prudent engineer will have remedial strategies in place if the preventive plan does not work. This strategy also includes loss contingency plans to be in place if unexpected loss events occur. Examples are discussed with respect to how previous knowledge and lessons learned can play a critical role in developing contingency plans to effectively manage losses when they occur.

In summary, this paper discusses WIM from a drilling fluids perspective and, more specifically, through managing drilling fluid losses. The preventive and remedial operational strategies presented can be critical in managing drilling fluid losses and helping prevent wellbore stability or well control situations.
Coastal Trapped Waves Offshore Angola
Authors: Cooper Cortis
Published: April 2015

This paper analyzes several years of observations from eight sites off northern Angola and finds strong coastal trapped waves (CTW) that are energetic and narrow-banded on the continental shelf. Seaward of the shelf break, the CTW spectral peak becomes less pronounced and more broadly banded. By 1000 m they are almost undiscernible. On the shelf, the CTWs are characterized by phase speeds of about 0.5 m/s, periods of roughly 11 days and peak unfiltered velocities of 100 cm/s; far exceeding the energy from other processes except in the upper few meters of the water column. CTW velocity profiles are sometimes barotropic (nearly constant with depth) and at other times display low-mode baroclinic characteristics. Analysis of winds in the equatorial Atlantic show substantial energy in the biweekly period range suggesting a simple source for the CTWs but a coherence analysis reveals low correlation at all frequencies. Previous work by Guiavarc'h et al. (2005) identified CTWs in this region and using a model, they traced their origin to equatorial waves driven by fluctuations in the equatorial winds. This paper also compares the global HYCOM and WANE models to the observations and finds that HYCOM shows spectral peaks in the CTW period range but they are several days longer than in the observations and too weak on the shelf. WANE underestimates the energy in the CTW frequency range on the shelf by an order of magnitude and shows no CTW frequency peak on the slope.
Assessing Uncertainties in Wellhead System Fatigue Life Prediction
Authors: Pedro Ramón I. San , Hamilton Mark E. , Bhalla Kenneth
Published: April 2015

This paper examines sources of uncertainty in present analysis methodologies used for the prediction of wellhead system fatigue lives. For this study, the sources of uncertainty are classified as those parameters that affect the prediction of loads and stresses (the demand) and those parameters that affect the calculation of fatigue damage (the capacity). The combined effects of demand and capacity uncertainties are then considered to qualitatively examine the resulting uncertainty in fatigue life predictions and how uncertainty in the results can drive design and operational decisions in order to achieve the desired reliability.

Calculations, test results, and experience show that any number of factors on the demand and capacity aspects of wellhead design can result in considerable uncertainty in the prediction of fatigue performance. This makes the task of determining rational and justified safety factors, design requirements, and operational limits extremely difficult. Reduction of uncertainty is required in order to maintain or improve the reliability (i.e., reduce probability of failure) of the wellhead system while allowing design and operational flexibility without having to resort to impractical safety factors. Progress towards this goal can be achieved, in part, by: (a) developing technically sound and consistent analysis methods, (b) refining analysis inputs through complementary advanced analyses and sub- and full-scale testing of systems and components, (c) qualifying welds and components to existing design S-N curves or developing appropriate design S-N curves from material and full-scale fatigue testing in applicable environments, and (d) developing benchmarks for analytical model validation through wellhead fatigue monitoring in real time.
Brazilian Pre-Salt: An Impressive Journey from Plans and Challenges to Concrete Results
Authors: da Costa Fraga Carlos Tadeu , Capeleiro Pinto Antonio Carlos , Branco Celso Cesar Moreira , de Sant´Anna Pizarro Jorge Oscar , da Silva Paulo Cezar Augusto
Published: April 2015

In the early 2000s the context of the pre-salt formations was conceptual geological models of possible oil bearing reservoirs underneath a thick salt layer, many technical challenges, uncertainties and risks. Past only eight years from first discovery (2006), there are nine production systems, FPSOs, in operation, reaching an average oil rate of more than 700 thousand barrels per day and a cumulative production greater than 400 million barrels of oil, through 34 production wells. To optimize recovery, the first desulfated sea water and gas injectors were started. But these impressive numbers cannot be taken from granted: although nature has revealed prolific reservoirs, much experience, talent, planning and perseverance were necessary.

The first articles addressing the pre-salt fields had a focus on the technical challenges faced on first years: the heterogeneous nature of the microbial carbonate reservoir, the 2,000 m salt layer and drilling concerns associated, the variable CO2 content and compositional grading in the reservoir fluids, flow assurance issues and special demands concerning subsea engineering, well construction and processing plant. The main drivers and development strategies were also established: staged development, based on extended well tests (EWTs), multi well production pilots and definitive systems prioritizing the standardization of well projects and production systems. Now, challenges and plans are rewarding the efforts, as depicted by the concrete production numbers achieved to date.

In this text, a historical perspective of the pre-salt exploration and development is presented, emphasizing the previous unknowns and uncertainties and how they were treated in order to attain the results. As we still have a lot to learn, since we are just on the beginning of the development of this extraordinary petroleum province, a look to the future and the present efforts on optimization are also commented.
Large Diameter Steel Catenary Riser Solutions for Semi-submersible Platforms in Offshore Northwest Australia
Authors: Vijayaraghavan V. , Shi X. , Lu R. , Wang T. , Haverty K. , Hagatun K. , Richards A. , Thompson H. M. , Healy N. , Jin E.
Published: April 2015

The offshore northwest Australian sector is dominated by large gas plays and as the sector matures there is an increasing move towards deepwater developments. Riser solutions are key concept selection drivers and often high gas throughputs have led to a drive towards large riser diameters to limit the associated subsea infrastructure. The need for high availability in LNG projects leads to a requirement for high reliability, permanently moored Offshore Facilities. A representative development scenario employs large diameter (18" to 24") import and export Steel Catenary Risers (SCRs) supported by a Semi-submersible platform in 1,400 m water depth. This is potentially the deepest development offshore Australia. It is a relatively novel solution for the region given that the riser solution in the region has been primarily limited to flexible risers.

SCR designs are governed by their fatigue performance in the touch down zone (TDZ). Feasibility of the large diameter SCRs is challenged by the Australian sea conditions dominated by southern ocean swells. Several options are considered to enhance the fatigue life of the SCRs. These include increasing the Semi draft to reduce heave motions, aligning the riser plane in a direction normal to the predominantly northeastern swell environment, using upset ends at critical locations to reduce curvature response, lazy wave configuration to decouple vessel motions from TDZ response, and weighted SCR to reduce TDZ response. These options are considered either individually or in a combination thereof. The technical feasibilities of and the challenges associated with these options are discussed. Some of the possible challenges include the manufacturability of upset ends, feasibility of top end terminations and installation of buoyancy modules. A relative cost comparison is also made between the different options.

The metocean conditions in offshore Australia are compared with US Gulf of Mexico (GoM), where SCRs have been widely used. Their implications for SCR fatigue and extreme response are explored. Findings that are critical to the riser design include riser porch vertical velocity at extreme conditions, relative contribution of surge/sway versus heave motions to fatigue damage, contribution of vortex induced motions (VIM) to fatigue damage, and effect of long term currents on riser VIV response.

Given the relative novelty of SCR applications with a Semi-submersible in offshore Australia, and the challenges associated with fatigue performance of large diameter SCRs in that harsh environment, this paper will serve as a valuable guide for future riser design and field development in the region.
Offshore Condensate Stabilization and Exportation
Authors: Vocke William , Newman Daniel , Villio Robert , Cook Charles , Taylor Denis
Published: April 2015

This paper discusses aspects of the process design approach used for the Delta House production facility (Mississippi Canyon 254 "A"). Specifically, the challenges associated with the disposition of NGL's (considering constraints imposed by export pipeline requirements and the desire to maximize liquids sales volumes) are addressed.

Delta House's process system was initially designed assuming a reservoir composition similar to an analogous nearby well. Based on this composition, liquids from compressor scrubbers were to be routed to production separators with lower operating pressures. This philosophy is very common for offshore facilities and caused minimal liquid recycle and a negligible increase in compression requirements.

Subsequent to this initial process design, a well sample phase behavior (PVT) analysis became available. The PVT data was believed to be representative of the majority of the production associated with Delta House. The PVT data indicated that the reservoir had an approximate stock tank gas-to-oil ratio (GOR) of 2100 and 38° API crude oil gravity. These PVT results represented a significant change from the initially assumed composition. Additionally, the reservoir fluid was very rich with condensate, particularly propanes (C3's), butanes (C4's), and pentanes (C5's).

A significant liquid recycle and a drastic increase in compression requirements were observed when the compositional basis of the reservoir was entered into the steady-state process simulator. In addition, meeting the oil pipeline Reid Vapor Pressure (RVP) specification became a significant challenge due to the rich nature of the crude. The current liquid handling philosophy no longer appeared suitable, and various options were quickly investigated and evaluated. The two most practical options were direct injection of the condensate into the gas pipeline and a full crude stabilizer. It was determined that a hybrid (a Condensate Stabilization System) of the two options was the most economical option due to the ability to recombine the stabilized condensate with the crude oil for sales.

This paper addresses the reasons, benefits, and methodology of installing a Condensate Stabilization System on the Delta House Floating Production System (FPS). It also discusses the process equipment that composes the system, the intended operating conditions, as well as the effects of seasonal variables (oil pipeline RVP specification and ambient temperatures).

A Condensate Stabilization System provides a means to optimize facility production and allows for better RVP control. This is achieved by controlling the reboiler temperature which correlates to the amount of light ends that are recycled to the bulk separation train. It also greatly reduces compression and horsepower requirements. Finally, a condensate stabilization system affords operators the ability to achieve greater margins by providing the flexibility to move liquids from the gas processing and sales system to the oil system.
Rotary Converter for Long Step-out Subsea Power Supply
Authors: Normann T. , Müller L. A. , Amundsen M. , Lien L. Krogstad , Chen A.
Published: April 2015

New subsea power transmission technology is required in order to enable increased oil and gas recovery in deep waters and at long tieback distances. Such prospects may not be feasible to develop with today's electrical power solutions, as traditional AC power transmission methods for supplying the increased power demand to subsea compression and pumping stations are reaching their limits. HVDC is far from matured for subsea use, and may not even be necessary technology, as low frequency AC can cover the market.

Aker Solutions has developed a new patented invention, called a Rotary Converter, for low frequency (LF) AC power transmission. This unit allows an extension of the maximum power transfer of subsea cables to more than 3x the step-out and 3x the power level compared to existing technologies.

The Rotary Converter (RC) consists of a subsea motor with low input frequency (10 - 30Hz) that runs a generator on a common slowly rotating shaft in a subsea enclosure. The generator supplies high frequency power (50 - 200Hz) to subsea ESPs, pumps, compressors or other loads.

The RC is supplied from a topside VSD via a long cable, and the low frequency ensures that the capacitive power / current in the cable is significantly reduced compared to conventional transmission frequency (50/60Hz or more), allowing more power, smaller cable cross-section, lower transmission voltage and better system stability.

Furthermore, by introducing a variable coupling (e.g., hydrodynamic) between the motor and generator, the Variable Rotary Converter (VRC) can replace power electronic based subsea VSDs. Input frequency can either be conventional for short to medium step-outs, and low frequency input for longer step-outs. This allows for simple and robust torque and speed control.

Key highlights from the Rotary Converter prototype development and tests are also shown in relation with relevant power system simulations. Various applications for this technology are presented, for instance within subsea control system supply, allowing increasing the power supply capability in brownfield scenarios where all-electric control systems are increasingly used.

This technology will be a new tool to enable the oil and gas industry to develop subsea fields that would normally require an additional offshore platform or FPSO, and rather use existing infrastructure with longer cables instead.

The main benefits of this new invention can be summarized in longer step-out distance, more power, better system stability, and lower CAPEX / OPEX for subsea control systems, pumping, and/or compression.
Offshore Methane Hydrates in the Gulf of Mexico: A Study in Economic Viability
Authors: Wells Jaeger , Sansom Paul
Published: April 2015

Methane hydrates have long been discussed as the next cradle of energy. Considered a resource of near infinite reserve potential, methane hydrates could supplant conventional hydrocarbon-based energy for the foreseeable future. In recent years there has been considerable activity in the petroleum industry to fully understand onshore and offshore hydrate deposits and methods of extraction and production; however, a commercial scale level has not been achieved. While there have been efforts to commercialize methane hydrate development in some parts of the world, the Gulf of Mexico remains relatively unexplored in this arena. This paper evaluates the economic viability of a commercial scale offshore methane hydrate production operation in the Gulf of Mexico—by creating a sample capital cost budget.
Online Transient Simulation in Deepwater Operations: Practical Experiences
Authors: Canon Javier M. , Yau Sarah , Francisco Aurea , Angola BP , Espeland Morten , Lundsbakken Knut Even
Published: April 2015

This paper summarizes practical experiences after 2 years of use of an online multiphase flow transient simulator in an operating deepwater blackoil field offshore Angola. FAMS (Flow Assurance Management System) is based on state of the art thermal-hydraulic models from bottomhole to slug catcher outlet interfaced to live field instrumentation data. The application is accessed via a web-based graphical interface.

Lessons learned presented here cover technical aspects of the tool such as reliability and accuracy under different scenarios, as well as non-technical issues such as system support model and interaction between supplier and end users. Taking transient simulation models; which are traditionally restricted to project development stages, into a real-time environment can have a positive impact on Flow Assurance workflows; particularly around minimizing effort in complex thermal-hydraulic studies, planning of unforeseen operations, training of junior engineers, validation of models and identification of code capabilities and limitations.

Continuous use of FAMS over a 2-year period has helped identify its accuracy beyond field data uncertainty. Monthly steady state reports (FAMS vs. field) prepared by the Operations team have shown good agreement between predictions and measurements. Transient conditions such as production shutdowns and hot oil circulation have also been studied and showed good agreement. This has served as means of validation of flowline insulation performance. Code / model limitations have been identified particularly in the area of slug modelling. Integration of FAMS within the BP IT infrastructure and processes have proved challenging as a blueprint for this type of application is yet to be developed. In spite of challenges in this area, the tool uptime and overall health has proved acceptable. Experiences also highlight the importance of clear and rigorous processes for maintenance of the tool between tool provider, IT department and end users, as well as an appropriate allocation of resources with clear roles and responsibilities.

Currently there are not many documented cases of use of transient online systems in day to day operations. Experiences described here help demonstrate the value of online transient simulation tools in deepwater environments while highlighting challenges and areas of improvement for this technology.
Development of Extreme Wave Conditions in the Northern South China Sea: New Method Applications and Sensitivity Studies
Authors: Li Linbin , Li Luodong , Li Ping
Published: April 2015

This paper is based on the JIP SOCSOHS (South China Sea Oceanographic Hindcasting Study) sponsored by China Classification Society (CCS) in 2012. It focuses on the determination of the extreme wave parameters under tropical cyclone conditions, and highlights benefits and limitations of the applied new methods by comparison and sensitivity studies. Firstly, method of grid-point pooling for prediction of extreme significant wave height (Hs) is used to account for the cyclone track variability and to realize smoothing of the site-specific data for the physically homogeneous and large scale areas. Secondly, long term distributions of maximum wave height (Hmax) crest elevation (Cmax) are derived following the storm event based approach. Thirdly, short term distribution of wave period conditional on the large individual wave height in a sea state is given by multiple regressions analysis for the random wave simulation of JONSWAP spectral. And fourthly, the long term distribution of wave period (THmax) associated with the design wave height is investigated by giving a reasonable range of spreading which should be considered for offshore structure design. The approaches presented are generic and valid for other offshore areas. It should lead to improvements in development of metocean criteria for waves as well as other parameters.
Interpretation and Evaluation of Offshore Hydrocarbon Reservoir from Anisotropic 3D Inversion of Towed Streamer EM Data
Authors: Zhdanov Michael , Endo Masashi , Mattsson Johan
Published: April 2015

The towed streamer EM system makes it possible to collect EM data with a high production rate and over very large survey areas. At the same time, 3D inversion of the towed streamer EM data remains a very challenging problem because of the huge number of transmitter positions of the moving towed streamer EM system, and, correspondingly, the huge number of forward and inverse problems needed to be solved for every transmitter position over the large areas of the survey. We overcome this problem by exploiting the fact that a towed streamer EM system's sensitivity domain is significantly smaller than the area of the towed streamer EM survey. We apply the concept of moving sensitivity domain, originally developed for airborne EM surveys, to the interpretation of marine EM survey data. This makes it possible to invert the entire towed streamer EM surveys with no approximations into high-resolution 3D geoelectrical sea-bottom models. Our implementation is based on the 3D integral equation (IE) method for computing the responses and Fréchet derivatives for 3D anisotropic geoelectrical models. In the framework of the concept of the moving sensitivity domain, for a given transmitter-receiver pair, the EM responses and Fréchet derivatives are computed from a 3D Earth model that encapsulates the towed EM system's sensitivity domain. The Fréchet matrix for the entire 3D Earth model is then constructed as the superposition of Fréchet derivatives from all transmitter-receiver pairs over the entire 3D earth model. This makes large-scale 3D inversion a tractable problem with moderate cluster resources. We present case studies of 3D anisotropic inversion of towed streamer EM data from the Troll West Oil Province and Mariner field in the North Sea.