bluuebunny/crossref_metadata_2025 huggingface dataset:
El anegamiento afecta el crecimiento y producción de biomasa en tomate chonto (Solanum lycopersicum L.), cultivado bajo sombrío
Authors: Baracaldo Adriana , Carvajal Rubén , Romero Angela Patricia , Prieto Andrea Marcela , García Francisco Javier , Fischer Gerhard , Miranda Diego
Published: March 2015

El estrés por anegamiento e inundación de las plantaciones se ha convertido en un factor abiótico limitante del crecimiento, el desarrollo y la productividad de los cultivos. Para estudiar el efecto del anegamiento sobre el tomate tipo chonto, híbrido larga vida Roble F1, se realizó un experimento en condiciones de invernadero de plástico, con y sin sombrío (una polisombra negra con 56,4% de reducción lumínica en un día soleado) de plantas anegadas. Se utilizaron materas plásticas de 1 L de capacidad, con turba rubia como sustrato en mezcla con suelo orgánico en proporción 1:1, las cuales fueron anegadas con una lámina de agua hasta 4 cm por encima del sustrato durante 4, 8 y 12 días. Las variables evaluadas incluyeron altura de planta, número de hojas y frutos, y biomasa seca de los órganos. El estudio mostró que los periodos de 4, 8 y 12 días de anegamiento redujeron significativamente la altura de la planta y el número de hojas, después de 12 y 16 días de iniciado el anegamiento, respectivamente, mientras el número de frutos en las plantas anegadas fue significativamente menor a los 40 dda cuando terminó la evaluación. La hipoxia radical en las plantas anegadas durante 8 y 12 días, redujo la producciónde biomasa seca, especialmente en frutos y raíces, mientras la interacción 12-días-anegamiento y sombrío disminuyó la masa seca total de la planta. La planta de tomate, en general, parece estar adaptada al efecto de este tipo de sombrío. Con el aumento de la duración del anegamiento aparecieron síntomas como clorosis y caída de hojas basales, además de la epinastia y coloración roja foliar, así mismo la formación de raíces adventicias.
Altered energy flow in the food web of an experimentally darkened lake
Authors: Batt Ryan D. , Carpenter Stephen R. , Cole Jonathan J. , Pace Michael L. , Johnson Robert A. , Kurtzweil Jason T. , Wilkinson Grace M.
Published: March 2015

Theory suggests that alternative resources may begin to support a food web when highly used resources become less available relative to alternatives. To test the potential for alternative resources to support consumers, we experimentally darkened a lake whose consumers had relied heavily on algal resources (phytoplankton and benthic algae). We estimated the support consumers received from resources before and after darkening using a Bayesian mixing model and stables isotopes of carbon, nitrogen, and hydrogen. Between a prior year and the darkened year, phytoplankton biomass diminished by 60%, and surface dissolved oxygen saturation, pCO2, and net ecosystem production indicated a shift from autotrophy to heterotrophy. Although a specialist copepod maintained a high reliance on phytoplankton after darkening, a generalist zooplankton predator (Chaoborus spp.) derived more support from terrestrial sources. Fishes received less support from benthic algae after darkening, and received greater support from floating‐leafed macrophytes or terrestrial resources. Phytoplankton support of fishes increased or was similar between years, resulting in a convergence of the proportion of support that fishes and zooplankton received from phytoplankton. The changes in algal support of fishes suggest that fishes had an increased connection to the pelagic habitat and decreased connection to the benthic habitat after darkening. After darkening, most consumers received more support from resource alternatives like terrestrial material (snail, Chaoborus spp., some fishes) or from floating‐leafed macrophytes (some fishes). These shifts indicate that resource support of consumers is dynamic, and highlight the potential for increased support of consumer biomass by alternative resources.
Heating Strategies for Steam-Assisted-Gravity-Drainage Startup Phase
Authors: Guindon Leah
Published: March 2015

The work introduces an analytical model to predict startup duration for steam circulation by electromagnetically heating with either induction (medium) or radio-frquency (RF) ranges. The results obtained reveal that induction slightly decreases startup time (ranging from 3 to several months' time) for frequencies smaller than 10 kHz, and it can reduce startup time to 30% of original steam circulation for 100 kHz frequency.
Trenching of Pipelines for Protection in Ice Environments
Authors: Paulin Michael , Humby Damien , Cocker Joseph , Lanan Glenn
Published: March 2015

Subsea pipelines located in ice environments need to be protected from potential ice gouging (also known as ice scouring) created when a moving ice keel interacts with the seabed. The integrity and operability of the pipeline can be affected by direct contact between the ice keel and the pipeline, or from loading imposed on the pipeline through soil deformation caused by ice gouging. The typical method considered for protecting against the risk of damage caused by ice gouging is through pipeline burial.

Conventional methods of pipeline burial use equipment such as ploughs, mechanical trenchers, and jetters, the majority of which have been designed to accomplish a maximum of 2 to 3 m of pipeline burial. Dredges can be used, but they have water depth limitations and limited productivity. Land-based equipment has been used for shore crossings, but is limited to shallow depths where temporary construction berms can be used as a working platform.

The capabilities of existing technologies are based on current industry practice developed for pipeline burial in ice-free environments. Pipeline burial requirements have generally been for improved hydrodynamic stability, mechanical protection (e.g., from anchors), controlling pipeline movements (e.g., expansion and buckling) and/or for flow-assurance purposes (reducing heat loss). A 2- to 3-m burial depth has been generally adequate to satisfy these conventional requirements. As developments are proposed for areas that experience relatively deep ice gouging (up to 5 m), burial depth requirements will exceed the capabilities of current pipeline burial technologies. New technologies capable of working in deeper water, achieving greater burial depths, achieving reasonable trenching advance rates, operating in harsh environments, and trenching through variable and difficult seabed soils will be required.

This paper highlights the issues and challenges surrounding pipeline trenching and burial in ice-gouge environments. The current state of practice is discussed along with the technology gaps that need to be addressed to prepare for future offshore developments in ice-covered waters where there is the potential for seabed ice gouging.
Assessment of Deliverability of a Natural-Gas-Gathering and -Production System: Development of an Integrated Reservoir/Surface Model
Authors: Alexis Dennis A. , Ayala Luis
Published: March 2015

The present work describes the development of a 1D steady-state isothermal reservoir/surface gas-pipeline-network model. The model was developed by combining the reservoir with surface-facility description parameters to capture effectively the variations in reservoir flow dynamics with changes in surface-network operating conditions. The developed model is an extension of the general pipeline-network model in which the deliverability from the wells is calculated in addition to the nodal pressures and gas flows in different pipe sections in the system on the basis of a set of operating conditions. Validation of the developed model was acheived through history matching with field data obtained from a currently operating gas-gathering and -transportation network in the northeastern USA. After successful validation, the model was used as a diagnostic tool to evaluate "what if" scenarios to identify the pressure and deliverability changes that can happen in the network. On the basis of the model predictions, recommendations were made to the operator in terms of total production, total sales, and fuel consumed by the compressors present in the network. This integrated-modeling approach helped in analyzing the system response as a whole and gave good insight into how the well shut-in pressures used in the model had a significant impact on the deliverability predictions.
Produced-Water-Treating Systems: Comparison of North Sea and Deepwater Gulf of Mexico
Authors: Walsh John Michael
Published: March 2015

In general, water-treatment systems in the North Sea differ from those in the deepwater Gulf of Mexico (GOM). The two most apparent differences are the extensive use of hydrocyclones in the North Sea, and the use of large, multistage horizontal flotation units in the deepwater GOM. Deepwater-GOM platforms use hydrocyclones, but not nearly to the extent that they are used in typical North Sea platforms. Typically in the North Sea, if flotation is used at all, it is a vertical compact unit. The objective of this paper is to provide an understanding of the reasons for these differences. In this paper, field data and modeling results are presented to explain these differences. The models accurately correlate the measured drop size and oil-in-water concentration observed in the two regions. In addition, the modeling tools are used to answer hypothetical “what if” questions. This allows isolation of individual variables such as fluid temperature, shear, separator residence time, and fluid density. Thus, the modeling provides a detailed understanding of the relative importance of these variables. It also provides a direct comparison of the performance of North Sea vs. GOM process configurations. While the qualitative conclusions are well-known (i.e., deepwater separation systems are designed to minimize weight and space), the detailed understanding provided here provides insight into the design of water-treatment systems in general. It also emphasizes, in a quantitative way, the importance of carrying out effective water treatment early in the process and the necessary use of large end-of-pipe equipment when this is not possible.
Inaccuracy in Pipeline-Compressor-Station Construction-Cost Estimation
Authors: Rui Zhenhua , Metz Paul A. , Chen Gang , Zhou Xiyu , Wang Xiaoqing
Published: March 2015

The intent of this paper is to investigate installed cost overruns ofpipeline-compressor-station projects. A total of 220pipeline-compressor-station projects constructed between 1992 and 2008 havebeen collected, including material, labor, and miscellaneous, land, and totalinstalled costs; and compressor-station capacity; location; and year ofcompletion. Statistical methods are applied to identify the distribution ofcost overruns and overrun causes. Overall average overruns ofpipeline-compressor-station material, labor, miscellaneous, land, and totalcosts are 3, 60, 2, -14, and 11%, respectively. Cost estimations ofcompressor-station-construction components are biased except for the materialcost. In addition, the cost-estimation errors of underestimatedcompressor-station-construction components are generally larger than those ofoverestimated components. Results of the analysis show that compressor-stationproject size, capacity, location, and year of completion have different impactson individual construction component cost overruns.
An Evaluation of Risk of Hydrate Formation at the Top of a Pipeline
Authors: Nazeri Mahmoud , Tohidi Bahman , Chapoy Antonin
Published: March 2015

Water condensation and/or hydrate formation at the top of pipelines are serious design/operation considerations in pipelines with stratified flow. Water condensation could result in top-of-the-line corrosion, particularly in sour-gas systems. Hydrate formation is believed to be another serious risk if the inhibitor in the aqueous phase cannot protect against hydrate formation at the top of the pipeline. In this paper, we report the results of some preliminary tests conducted in a new experimental setup constructed for investigating gas-hydrate risks in various operational scenarios (e.g., top of pipelines, deadlegs/jumpers, startups, shutdowns). The reported three series of tests conducted in the new experimental setup address hydrate-formation risks at the top of pipelines or deadlegs caused by temperature gradient, and the risk of hydrate formation in the gas phase in the presence of kinetic hydrate inhibitors (KHI) during pipeline cool down and startup. The results provide a better evaluation of the risks involved in various systems and provide guidelines for avoiding the associated problems.
Computational Fluid Dynamics-Based Study of an Oilfield Separator--Part I: A Realistic Simulation
Authors: Pourahmadi Laleh Ali , Svrcek William Y. , Monnery Wayne
Published: March 2015

A realistic computational fluid dynamics (CFD) simulation of a field three-phase separator has been developed. This realistic CFD simulation provides an understanding of both the microscopic and macroscopic features of the three-phase separation phenomenon. For simulation purposes, an efficient combination of two multiphase models of the commercial CFD software, Fluent 6.3.26 (ANSYS 2006a), was implemented. The flow-distributing baffles and wire mesh demister were also modeled using the porous media model. Furthermore, a useful approach to estimating the particle size distribution in oilfield separators was developed. The simulated fluid-flow profiles are realistic and the predicted separation efficiencies are consistent with oilfield experience.
A Simplified Mechanistic Model for an Oil/Water Horizontal Pipe Separator
Authors: Pereyra Eduardo , Mohan Ram S. , Shoham Ovadia
Published: March 2015

A new methodology for oil/water horizontal pipe separator (HPS) design and performance prediction is developed. The separator diameter is determined on the basis of oil/water flow-pattern prediction. A batch separator model is adopted and modified for pipe flow to predict the separator length for achieving a desired separation quality. An experimental program is carried out to validate the proposed model.
Implementing a Deepwater-Pipeline-Management System
Authors: Samosir Theo , Popineau Dominique , Lechon Alain
Published: March 2015

As an operator, Total has experienced significant deepwater maintenance andrepair activities, including cut-out and replacement of a damaged section ofwater-injection line, replacement of a flexible riser, replacement of an anchorline and its pile, and repair of an umbilical termination head (UTH).

There are few deepwater-pipeline operators with experience in pipelinerepairs that need to be carried out with significant preparation time forintervention tools, including engineering and testing of the tools. Deepwateroperations [including inspection, maintenance, and repair (IMR)] require acompletely different paradigm than conventional offshore operations, with needfor specialized competencies, contractors, and tools. The pipeline-repairactivities mastered in conventional offshore operations are becoming difficulttasks in deep water because they have to be performed remotely and the pipelinecharacteristics are quite different. Furthermore, there are many importantchallenges that still need to be overcome, such as repair of pipe-in-pipesystems, repair of production bundle, repair of flowline with hydrogen sulfidecontent, and repair of flowline connection, all of which challenge research anddevelopment to find proper tools and methodologies for deepwaterintervention.

This paper describes the strategy developed and implemented ondeepwater-pipeline intervention, based on a deepwater operational experiencebuilt over a decade. It also presents experiences of dealing with integrityissues and how to move forward in existing operations while preparing forfuture developments. Once the proper technologies are acquired, apipeline-repair system should be established as part of anoperational-management philosophy.

From the design stage, an operator involved in the development of deepwateroperations should give serious consideration to how condition monitoring of thepipeline and its appurtenances will be performed and to how pipeline sectionswill be repaired or replaced should there be any failure during production.Being well prepared to face unexpected failures in the deepwater-pipelinenetwork would allow the operator to maintain the level of integrity of thedeepwater-pipeline network, minimize production loss and shortfall, minimizeintervention costs, and maintain the operator's image with international mediaand the national oil company.
Risk-Based Passive Fire-Protection Optimization
Authors: Munoz-Garcia Enrique
Published: March 2015

Passive fire protection (PFP) has been used in the oil and gas industry for many years as a method to avoid/delay global collapse of offshore installations. However, location of PFP has normally been based on simplistic assumptions, standards, guidance, and methods that do not always consider the real response of the structure to fire. The resulting PFP schemes can be conservative, leading to unnecessary cost to the operator in terms of application and maintenance costs. More importantly, there is the potential for the PFP scheme to be insufficient for the actual fire hazards, which will increase the level of risk to the personnel onboard. Fire-induced progressive collapse is a function of the level of redundancy of a structure; it is for this reason that redundancy analyses have sometimes been used as a simplistic method to calculate the level of PFP required. However, this method does not take into account the size of the fire threat against which the PFP is designed and could lead to less-than-conservative results because it considers removing only one member of the structure at a time, without considering reduction in the strength of the surrounding members as they are also being heated by the fire. Performance-based fire-collapse analysis provides an understanding of the response of the individual members, as well as the entire structural system, to fire. Understanding the failure mechanisms, susceptibility to progressive collapse of the structure, and key members that must remain in place during an accident situation allows for the optimisation of the PFP scheme, protecting only the required members while allowing for local failure of redundant members. The present paper provides a comparison between the different methods, and provides case studies that have resulted in optimum PFP schemes linked to design fires on the basis of acceptable risk levels.
Optimization of Integrated Template Structures for Arctic Subsea-Production Systems
Authors: Pribytkov Evgeny A. , Zolotukhin Anatoly B. , Gudmestad Ove T.
Published: March 2015

This paper analyzes the various selection methods of integrated template structures (ITSs) for use in the Arctic environment. First, an analysis of several actual projects is carried out, with the specific features of each described thoroughly. An important part of the work is devoted to the requirements of ITSs conceived in relevant NORSOK (Norsk Sokkels Konkuranseposisjon), International Organization for Standardization (ISO), and DNV (Det Norske Veritas) standards. The main elements of subsea production modules are examined in this work, along with their specific characteristics and components. Operation and installation of subsea modules in the Barents Sea are also analyzed in this paper. Four scenarios, with differing numbers of ITSs (two, three, four, and six) and differing quantities of well slots in each, are considered. For each scenario, a study of related marine operations (required for installation) is performed, and a program for installation-cost estimates is developed, resulting in the determination of an optimal design for the ITSs. Various parameters affecting the cost of subsea infrastructure are analyzed and studied from different perspectives (e.g., geometrical well-pattern systems, distance between drilling slots, drilling and construction costs). Risk analyses of the threats and consequences involved in the process are performed, and risk-assessment matrices and mitigation actions are established. As a result, a model for selecting an optimal ITS for the Arctic/Sub-Arctic region is created.
Hybrid Approach by Use of Linear Analogs for Gas-Network Simulation With Multiple Components
Authors: Leong Chew Y. , Ayala H. Luis F.
Published: March 2015

The generalized Newton-Raphson method is routinely deployed in industrial and academic applications in order to solve complex systems of highly nonlinear equations. Prime candidates for this solution methodology are complex natural-gas transportation networks, of which the nonlinear governing equations can be written in terms of nodal, loop, or nodal/loop formulations to solve for all network pressures and flows. A well-known issue of the Newton-Raphson iterative methodology is its hapless divergence characteristics when poorly initialized or when flow loops are poorly defined in loop or nodal/loop formulations. In this study, a method of linear analogs is discussed, which eliminates the need for user-prescribed flow or pressure initializations or loop definitions in the solution of the highly nonlinear gas-network governing equations. A comprehensive solution strategy based on analog transformations is presented for the analysis of a gas-pipeline network system comprised of not only pipes, but also common nonpipe network elements such as compressors and pressure-dependent gas supplies (e.g., wellheads). The proposed approach retains advantages of Newton-nodal formulations, while removing the need for initial guesses, Jacobian formulations, and calculation of derivatives. Case studies are presented to showcase the straightforward and reliable nature of the methodology when applied to the solution of a steady-state gas-network system analysis with pipeline, compressor and well-head components.
Degradation (or Lack Thereof) and Drag Reduction of HPAM Solutions During Transport in Turbulent Flow in Pipelines
Authors: Jouenne Stephane , Anfray Jérôme , Cordelier philippe Robert , mateen Khalid , Levitt David , Souilem Inès , Marchal Philippe , Lemaitre Cécile , Choplin Lionel , Nesvik Jonathon , Waldman Thomas
Published: March 2015

Rules of thumb that are used in the industry for polymer-flooding projects tend to limit the distance over which hydrolyzed polyacrylamide polymers can be transported in pipelines without undergoing significant degradation. However, in sensitive environments, such as offshore facilities where footprint minimization is required, centralization of the polymer-hydration process and long-distance transport may be desirable. More-reliable rules are required to design the pipe network and to estimate mechanical degradation of polymers during transport in turbulent conditions. In this work, we present evidence in the form of empirical large-scale pipeline experiments and theoretical development refuting the claim that polymer pipeline transport is limited by mechanical degradation. Our work concludes that mechanical degradation occurs at a critical velocity, which increases as a function of pipe diameter. Provided the critical velocity is not reached in a given pipe, there is no limit to the distance over which polymer solution can be transported. In addition, the drag reduction of viscous polymer solutions was measured as a function of pipe length, pipe diameter, fluid velocity, and polymer concentration. An envelope was defined to fix the minimum and maximum drag reductions expected for a given velocity in larger pipes. For pipes with diameters varying between 14 and 22 in. at a velocity greater than 1 m/s, the drag-reduction percentage is anticipated to be between 55 and 80%. A more-refined model was developed to predict drag reduction with less uncertainty. In conclusion, classical design rules applied for water transport (fluid velocity < 3 m/s) can be applied to the design of a polymer network. Therefore, for tertiary polymer projects, the existing water-injection network should be compatible with the mechanical requirements of polymer transportation. For secondary polymer projects, changing the rules of design by taking into account the high level of drag reduction should bring some economy to the pipe design and installation.
Design Method Combining API and ASME Codes for Subsea Equipment for HP/HT Conditions Up to 25,000-psi Pressure and 400°F Temperature
Authors: Pathak Parth D. , Kocurek Christopher G. , Taylor Samuel L.
Published: March 2015

A current challenge in the offshore industry is the design of subsea equipment for pressures exceeding 15,000 psi and temperatures exceeding 250°F. This combination of pressure and temperature has been fairly accepted as the start of the high-pressure/high-temperature (HP/HT) region. The current American Petroleum Institute (API) standard for designing subsea equipment, API Specification (SPEC) 17D (2011), is limited to a working pressure of 15,000 psi and provides little guidance on temperature conditions exceeding 250°F. This paper demonstrates a design methodology which combines the API and American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC) for designing an example subsea pressure containing component for HP/HT conditions greater than 15,000 psi and 250°F. This paper shows the evaluation of a combined load-capacity chart for an API SPEC 17D flange flow-loop [API SPEC 6A (2010), 4 in., 20 ksi) for a design pressure of 20,000 psi and a temperature of 350°F with external tension and bending loads. Both the linear elastic and elastic plastic methods for protection against plastic collapse are used to determine the structural capacity of the flange body. These methods combine the API material and design allowables and ASME design methods. Stress classification and linearization are used for the evaluation of design capacities with linear methods. Modified load-resistance design factors are used both to evaluate design capacities and to account for the difference in ASME and API hydrostatic-test pressures with elastic-plastic methods. The structural capacity is combined with thermal analysis to determine the effects of high temperature on the flange capacity. To assess the cyclic-loading capacity of the flange, stress-based fatigue analysis and fracture-mechanics analysis are also compared. The results obtained are comparable to existing API Technical Report (TR) 6AF1 (1998) charts. This work has been performed to demonstrate both the acceptance of existing methods for HP/HT conditions and to introduce the advanced ASME design methods for designing API SPEC 17D subsea equipment. The methods presented are acceptable for designing equipment up to working pressures of up to 25,000 psi and temperatures up to 400°F.
Mechanical Vapor Recompression for the Treatment of Shale-Gas Flowback Water
Authors: Hayes Thomas D. , Halldorson Brent , Horner Patrick H. , Ewing John Jay R. , Werline James R. , Severin Blaine F.
Published: March 2015

Used extensively by the food, chemical, and pharmaceutical industries, the mechanical-vapor-recompression (MVR) process is viewed as a reliable method for recovering demineralized water from concentrated brines. Devon Energy has supported the operation of an advanced MVR system at a north-central Texas (Barnett shale region) treatment facility. At this facility, pretreatment included caustic addition and clarification for total-suspended-solids and iron control. Pretreated shale-gas flowback water was then sent to three MVR units, each rated at 2,000–2500 B/D (318–398 m3/d). Data were collected during a 60-day period in the summer of 2010. Distilled-water recovery volume averaged 72.5% of the influent water to the MVR units. The influent total dissolved solids (TDS) fed to the MVR units averaged just under 50 000 mg/L. More than 99% of the TDS were captured in the concentrate stream. The fate of multivalent cations; total petroleum hydrocarbons (TPH); and benzene, toluene, ethylbenzene and xylenes (BTEX) throughout the treatment system was determined. Most of the iron and TPH removal (90 and 84%, respectively) occurred during pretreatment. The total removal of iron, magnesium, calcium, barium, and boron from the distillate exceeded 99%. BTEX removal from the distillate exceeded 95%. Electric power at the facility was provided by two natural-gas generators, and compressors associated with the MVR units were driven by natural-gas-fueled internal-combustion engines. Energy requirements at the entire treatment facility were tracked daily by total natural-gas use. Best-fit correlations between treated water and distillate production vs. total plant use of natural gas indicated that there was a base power load throughout the facility of approximately 120 to 140 Mscf/D (3400 to 3960 m3/d) of gas. Approximately 48 scf natural gas/bbl influent water treated (270 m3/m3 influent) or 60.5 scf/bbl distillate produced (340 m3/m3 distillate) was required; this represents an energy cost of less than USD 0.25/bbl treated (USD 0.04/m3 treated) and approximately USD 0.30/bbl of distillate product generated (USD 0.048/m3 distillate), assuming a natural-gas cost of USD 5/million Btu (USD 4.72/GJ). Performance in terms of water recovery and product-water quality was stable throughout the 60-day test.
Upstream Offshore-Facility Weight-Growth Study
Authors: Rui Ray (Zhenhua) , Walker Jason
Published: March 2015

Offshore-facility weight is significantly related to the cost, schedule, and complexity of offshore-facility projects. Therefore, controlling the weight growth of offshore facilities is important to project success. This paper seeks to understand weight growth and its causes among different project phases. By use of the detailed database of oil and gas projects provided by Independent Project Analysis, we conducted a rigorous statistical analysis of offshore weight growth to identify the root cause(s). This paper evaluates the weight growth for 153 global offshore projects at the end of the concept selection and authorization gates. The study results show that industry weight growth is much higher than expected. Front-end loading (FEL) is a core work process of project teams before authorization. FEL is a process to develop sufficient strategic information to address risk and make decisions to commit resources to maximize the chance of a successful project. The FEL work process is divided typically into phases or stages, with a pause for assessment and decision making about whether to process. Although the industry typically allocates 13% of dry weight for weight contingency at the end of FEL 2 and 6% of dry weight at authorization to account for unexpected weight growth, one-half of the topsides had more than 10% weight growth from authorization to completion, and more than one in three substructures had more than 10% weight growth from authorization to completion. The data also show that estimated weight-contingency range is much narrower than that of actual required contingency. This analysis shows that the weight growth of most offshore facilities is caused by poor engineering status for the facilities at authorization. The analysis also shows that setting aggressive schedule targets erodes the benefits of good engineering definition. In general, projects with good engineering and aggressive schedule targets have an additional 9% weight growth compared with projects with good engineering and nonaggressive schedule targets. The weight growth of offshore facilities was found across many different offshore-facility concepts (e.g., fixed platforms, spars, tension-leg platforms). This research provides an understanding of industry offshore-facilities weight performance and the main causes of weight growth, and offers recommendations for improving weight predictability.
Evaluating Wellbore Accessibility and Productive Performance for a Long-Reach Multilateral Tight Gas Well in Changbei Block
Authors: Li Li , Zhi Guo Hong , Millan Hilarion , Qiang Zhang , Tao Zhang , Lei Cui , Sheng Li Yin
Published: March 2015

Changbei gas field is on the north edge of the Mauwusu desert in the Ordos basin in north-central China. The game-changing dual-lateral well concept is used in this tight gas reservoir. The typical well completion is kicked off at about 1700 m, and the hole is built to an inclination of 85° at the top of the reservoir with the 12¼-in. section. The first leg of the 8½-in. reservoir section is drilled for 2000 m. The second leg is drilled with an openhole sidetrack from leg 1. More openhole sidetracks are drilled from legs 1 and 2 if unstable intervals are penetrated. Upon reaching total depth (TD), a 7-in. slotted liner is run to protect any unstable claystone intervals.

As part of the well and reservoir surveillance activities and with the aim of improved understanding of the reservoir and well behavior, production logging is required to obtain the gas-contribution profile along the horizontal wellbore; the profile is used to confirm the size of the sand bar, facies distribution, wellbore condition, and production contribution from each leg. Previous attempts with wheel-driven tractors and conventional production logging tools (PLTs) were unsuccessful because most of the PLT runs encountered bad downhole conditions, such as water/mudcake, which led to failure of the tractors and PLT centralizers. The mudcake and debris could not be cleaned from wellbores, even though the wells had been produced at high rate.

To collect needed data, an advanced PLT consisting of an array of minispinners and optical and electrical holdup sensors was conveyed by an electrically powered tractor operating on the inchworm principle to successfully log a long-reach multilateral well. A workflow was followed to obtain wellbore accessibility and perform flow profile evaluation for the complex downhole conditions at Changbei. This was the first time a flow profile was obtained in Changbei block.
Achieving Economically Successful Deployment of Coiled Tubing at Sea as Downline to Repair a Gas Pipeline
Authors: Machado Frederico , Souza Raphael , Fonseca Roberto
Published: March 2015

Offshore pipeline pre-commissioning activities normally involve the use of downline to permit the communication between surface equipment (normally rigged up in a vessel or rig) and the subsea pipeline injection/vent point. Recently, a major operator in Brazil deployed a 1 3/4-in. coiled tubing (CT) string as downline at sea using a methodology to maintain a smooth bend radius to help reduce fatigue issues during operations. Using CT as downline for this operation saved the operator USD millions by eliminating the need to replace a pipeline section.

The 40-kilometer (km) pipeline had a blockage composed of pigs, debris, and hydrates. After two failed interventions, the operator decided to install a subsea hot tap on each side of the plug, displace the hydrocarbon, and clean the pipeline to cut the section and replace it with new pipe. The blockage was located 6 km from the center of the pipeline. CT string was deployed to the seabed (1400 m) and was attached using soft sling in a deployed 8-ton clump weight positioned next to the pipeline. A 25-m flying lead hose was used in the bottomhole assembly (BHA) to connect the CT to the pipeline subsea hot tap near the plugged section and compensate vessel movement. After attaching the CT string on the clump weight, the vessel was moved away from this point to deploy 40 m of the CT on the seabed, forming a smooth bend radius. A Nitrogen generator unit (NGU) was used to displace gas in the pipeline to the production unit flare. Cleaning operations were completed using a pig propelled with filtered seawater provided by pumping equipment located on the production unit. The execution plan required that all fluids be recovered onboard the support vessel through the CT attached to the subsea hot tap.

Using CT and established best practices, the team was not only able to clean the pipeline section as planned but also eliminate the need to cut and replace the pipeline section. The CT string was kept under water for more than 170 hours, demonstrating its capability to satisfactorily function as downline equipment during this operation.
Residual Curvature and Moments in CT due to Bending
Authors: Newman Kenneth R.
Published: March 2015

When CT with internal pressure is bent around the reel or guide arch, and straightened in the injector chains, it experiences both plastic and elastic deformation. This results in internal residual stresses which cause bending moments and residual curvature. A “straightener” can be used to reverse bend the CT, which causes it to be fairly straight (no significant residual bend) but it still has significant residual stresses. Residual curvature and stresses decrease the buckling load (the CT is more prone to buckling) and cause safety issues if the CT is suddenly released. They can affect the fatigue life, but they are not in themselves an indicator of the amount of fatigue damage (as some have mistakenly thought). This paper presents the concepts and equations used to determine the residual curvature and residual stresses for a sequence of bending events, axial loadings, with internal pressure. These concepts and equations are then used to demonstrate the behavior of CT for several practical situations such as when it is run in and out of a well, and when it passes through a straightener.
Advancement in Mechanical Manipulation Enables Pulling Forces of 60,000 lbs on E-line – Operational Experiences from Pulling Stuck Plugs and Tools
Authors: Buch Jørgen , Mourani Houssam , Ngo Dong
Published: March 2015

Objectives/Scope:

Accidental plug setting and stuck tools is a cause of great frustration, operational delays and ultimately deferred production. A cost-efficient and swift resolution is always desired. This paper presents a new development in engineering in the form of a hydraulic stroking tool with the ability to apply 60,000 lbs of force. The tool has already been applied in the North Sea; lessons learned from these recent operations are disclosed in this paper.

Methods, Procedures, Process:

In one operation, a plug was accidentally set across the Christmas-Tree (XMT) and blowout preventer (BOP), effectively eliminating the XMT as a well barrier element and constituting a serious HSE risk. Conventional solutions failed to release the plug due to an insufficient pull force and then a failing jar.

In another well, the setting tool had malfunctioned, resulting in a partially set plug and a stuck tool. Repeated attempts with heavy duty fishing equipment had damaged the fishing neck, further complicating the fishing operation as the seting tool had failed before it could break the stud connecting to the plug.

Results, Observations, Conclusions:

The high performance of the recently developed stroking tool turned out to be the solution to save both of these demanding operations. In the first well, it was estimated that the force required to shear the plug from the setting tool would be 43,300 lbs. The operation was completed in three runs with no misruns, which saved the operator from prolonged exposure to HSE risk, including well control situation.

In the second well, the force required to shear the stud and free the setting tool was 40,000 lbs. Two release devices were combined in the toolstring, one below the hydraulic stroker and one below the cable head in order to allow further contingencies to mitigate risk and increase safety. After four attempts, the shear stud parted, thus completing the setting sequence and freeing the stuck setting tool. The operator got the well back on track, saved five days of rig time and avoided the costs of a workover rig.

Novel/Additive Information:

The case stories in this paper constitute the first jobs performed with the new tool. Two important features discussed are reduced HSE risks and increased operational efficiency.
Combined Electric Line Milling and Clean-out to Eliminate Fluid Costs for Multi-Stage Frac Preparation in Southeast Saskatchewan
Authors: MacLeod Anthony , Ray Jeremy , Bittner Scott
Published: March 2015

Objectives/Scope

Clients utilizing Coiled Tubing (CT) for straddle frac operations in multi-stage horizontal wells often encounter cement stringers preventing the frac bottomhole assembly (BHA) from reaching plug back total depth (PBTD) and the packer from sealing to the casing wall. This paper presents the learnings from a >90 well campaign of preparing for fracking operations using an electric line (e-line) milling and clean-out tool. The wells were mostly cemented, 4.5″ liners with frac sleeves. This technique reduced frac preparation costs in the cemented wells by approximately 30%.

Methods, Procedures, Process

The common practice in Southeast Saskatchewan (SE Sask) is to perform a “well prep” operation prior to the frac equipment's arrival to the well site. A CT unit equipped with a rotating scraper/mill—and associated fluids—is used for the clean-out, adding to the logistical coordination and well costs. Fluid has several costs associated with it: the cost of the fluid/water itself, heating for winter operations, trucking and disposal. However, “well prep” is considered “cheap insurance” by most operators working in SE Sask compared to the potential costs of a waiting frac crew.

Results, Observations, Conclusions

An operator in SE Sask has had success with an alternative clean-out solution to replace the use of fluid for well preps by introducing an e-line method consisting of an electric milling & clean-out tool with a casing collar locator (CCL). The mill is conveyed by e-line tractor and is equipped with a scraper mill to confirm the PBTD and ensure that there is no cement debris or sheath present that could negatively affect the frac operation. Various bailers can be added to collect the cement debris in the same run and ensure it is removed from the wellbore.

In combination with the clean-out service, a CCL is deployed and logged to surface to pinpoint the exact sleeve location to be referenced during the frac operation. This new, efficient clean-out solution has proved slightly more time-consuming (~3-5 hours) but yielded significant cost savings of approximately 30% per well of prep costs. These savings come from using e-line equipment, eliminating fluid costs and offering inherently safer operations with a low carbon footprint.

Novel/Additive Information

Moreover, the paper will discuss the future applicability of this ‘additional application’ for pre-logging runs as a means to reduce total completion costs in cemented wells. This is achieved by using the e-line milling tool as a pre-run for casing inspections or cement evaluation logging.
Crown Plug Pulling Performed as Riserless Light Well Intervention in the Gulf of Mexico – Overcoming the Challenges
Authors: Andrews Garry , Luviano Angel
Published: March 2015

Objectives/Scope

Having a reliable backup plan is vital to ensure successful riserless light well intervention (RLWI) operations. This paper will present learnings from a subsea operation where the contingency solution was engaged to resolve a critical issue. The need for thorough back-up planning will be discussed along with the planning process, execution and lessons learned.

Methods, Procedures, Process

Crown plugs are conventionally retrieved using slickline jarring; however, high performance shifting tools on electric line are gaining foothold due to their ability to apply a focused, axial force downhole. Up to 33,000 lbs of force can be exerted through the use of a bi-directional, hydraulic ram. These electric line (e-line) stroking tools can be fitted with various shifting or pulling tools for lightweight mechanical services. For subsea interventions this is good news as space is particularly limited on vessels, which means that intervention solutions that simplify logistics by reducing equipment and crew is sought after.

Results, Observations, Conclusions

The case to be presented is from a RLWI operation in the Gulf of Mexico where a crown plug had failed to release. Slickline (SL) was the first method to be put into action. On the first attempt 148 jars failed to retrieve the plug, then another 199 jars yielded the same result. It was believed that these repetitive attempts had broken the seal, resulting in saltwater inflow that had created hydrates. 25% Methanol Ethanol Glycol was pumped while jarring, but eventually the contingency plan was activated. This consisted of a hydraulic stroking tool, which successfully managed to remove the upper crown plug and thus allowed the operation to continue without further downtime.

The operator would have had six months of deferred production (being unable to open the sleeve to the upper zone) if the crown plug was not retrieved as they would have needed to wait for a riser. This underlines the importance of having an adequate contingency solution to overcome the challenges in riserless interventions. The benefits will be increased operational efficiency and reduced overhead costs.

Novel/Additive Information

This was the first operation where a crown plug was pulled during a RLWI operation with an e-line bi-directional stroking tool. The tool in this case was capable of 33,000 lbs of force; however, since the execution of this operation, further developments in engineering have led to a redesigned stroking tool with the ability to apply up to 60,000 lbs of force. What opportunities that opens up for RLWI operations will also be presented.
Utilizing a Wall Thickness Measurement Device to Improve the Accuracy of Coiled Tubing Fatigue Calculations
Authors: Traugott D. A.
Published: March 2015

Coiled tubing (CT) monitoring tools are being utilized on a larger percentage of field jobs now as compared to the past. They are being used on both CT intervention and CT drilling operations. The objective of this paper is to demonstrate how a wall thickness measurement device can enhance and improve the calculations made by a CT fatigue algorithm.

Experimental work was done which shows how the wall thickness can vary depending on the pump rates, the fluid being pumped and the amount of tubing that is spooled on the reel. Reference four provides detailed information related to wall reduction in CT during pumping operations. Typically, fatigue models will utilize an estimated, nominal or minimal wall thickness to perform the fatigue calculations.

The amount of wall reduction in CT can vary greatly and as a CT string acquires fatigue, there is a chance that the estimated wall thickness may not reflect the actual wall thickness of the pipe. Recent modifications to fatigue tracking software allow the user to incorporate the real-time (or recorded) measured wall thickness into the fatigue calculations. This paper will discuss the experimental work, the modifications to the model, and case histories in which the wall thickness measurement device was used.

Calculating the CT fatigue using the measured wall thickness will increase the accuracy of the CT fatigue profile. This will allow CT service companies to operate at an increased efficiency. Operating companies will also benefit from this technology because there will be fewer fatigue failures at the well site due to the increased accuracy in the fatigue calculations.