bluuebunny/crossref_metadata_2025_split huggingface dataset:
Subsea Seawater Treatment and Injection - Performance Tests of Filtration Membrane Modules at Simulated Subsea Conditions
Authors: Plasencia Jose , Andreotti Marcelo , Wang Hua , Alam Zamir 
Published: April 2018

The use of seawater treatment and injection to increase oil recovery is extensively practiced worldwide. Seawater can be treated at different levels to provide the required water quality compatible with the reservoir for pressure maintenance. In this respect, membrane technologies including ultrafiltration, nanofiltration and reverse osmosis can be used for fines, sulphates and salt removal respectively. The use of subsea treatment systems built on these filtration technologies is proposed as an alternative to bulky and heavy conventional topside systems. Subsea systems can eliminate the need for expensive floating facilities that often have space and weight restrictions. For a reliable operation of a subsea system it is required to verify the filtration membranes performance at water depths that can reach 3000 m (300 bar and 4°C).
Laboratory tests of hollow fiber ultrafiltration (UF), spiral-wound nanofiltration (NF) and spiral-wound reverse osmosis (RO) membrane modules were performed at simulated deep-water conditions to assess their integrity and performance. A high-pressure dynamic testing system, with precision temperature and pressure control was built to enable accurate measurements. Short and long-term dynamic tests, including pressure cycling fatigue tests, were performed by operating membrane modules at the simulated subsea environment (300 bar and 4°C). Static tests were also performed to assess the impact of deep subsea conditions on membrane module structural integrity and membrane physical properties. The results indicate that the tested UF, NF, and RO membrane modules are promising for deep subsea applications. The mechanical integrity and membrane module performance were maintained within the predefined acceptable limits at both static and dynamic test conditions. These promising results are a big step towards the technical feasibility of using membrane technology for subsea seawater injection systems.
Well Construction Process Modeling and Simulation
Authors: Baker Jason , Ferraioli Patrick 
Published: April 2018

The objective of this paper is to present a methodology for determining tripping performance at multiple levels of detail. Looking at it from the highest level of a rig fleet, then a singular rig, and its well construction process, then individual machines, machine states and finally specific functions. The intent is to pinpoint the contributors to the critical path processing time and correlate with additional factors impacting performance. This paper highlights the methodology for processing machine data, identifying drill floor activities, showing how specific machine states and functions impact the dynamic critical path of operations.
During offshore oil and gas well construction, a significant amount of time is spent on drilling operations. The operation involves a sequence of manual and semi-automated processes performed in unison as safely and efficiently as possible. The dozens of machines used during these operations operate independently, the driller orchestrates these machines to execute many complex activities. As these machine operations are highly coupled, the delay of any single machine function can impact the critical path of the overall operation, thus reducing the efficiency of the entire operation. Drilling rates within the offshore drilling industry have some degree variation given different wellbore conditions, operating procedures, environmental conditions, equipment designs and drill floor layout among others. Through the life of a well, these operational variations and inefficiencies are not immediately visible in the overall operation. These variations are manifested as invisible lost time, which in turn provides an opportunity to improve the efficiency of the machine, rig and fleet. This paper highlights the challenge of decomposing the drilling operations into its critical path activities and dependencies, then decomposing machine functions into discrete states, and finally operating modes to enable precise measurement of overall system performance. Leveraging commercial simulation software, state machine algorithms were developed to analyze the process using real-time machine data to automatically identify machine states, process activities and capture descriptive statistics. The results provide further insight into system performance that is being used to provide real-time feedback to operations personnel, as well as assisting with post event analysis. The methods developed during this project are also being leveraged in other projects to understand true system behavior and performance, considerations of future performance and to optimize new system designs.
Malikai TLP Project: Health Safety and Environment Measures Implemented for GOAL ZERO
Authors: Ratnasingam Alvin Rajan , Adrian Edmund , Fazilah Ungku Nor , Alex Wilson 
Published: April 2018

Abstract
Malikai TLP is a Deepwater manned platform operated by Shell. The Malikai TLP began construction in 2013. The Malikai TLP brought a huge challenge and complexity in terms of materials, quality control and assurance, interfaces between different contractors and subcontractors, construction and installation requirements and competent and experienced personnel. During the constructions phase, there were 3000-4000 workers based at site working together to build the TLP. There were significant amount of hazards that could be realized due to the types of construction and installation related activities such as working at height, working over water, confined space, working with electrical equipment, blasting, painting, grinding activities, scaffolding, lifting and handling of heavy equipment to name a few. The hazards at the site could have led to severe consequences including fatalities, physical injuries, burns and electrocution. With this realization, the Company implemented numerous measures to address the health, safety and environmental concerns including the welfare, competency and safe working environment for the workers. This paper presents an overview of the measures taken with the hope of achieving GOAL ZERO that emphasizes no harm to any personnel working at the site.
A Comprehensive Innovation Method to Assess Uncertainties and Increase Performance of Infill Project in Mature Oilfields
Authors: Shi Hongfu , Ma Kuiqian , He Yifan , Han XiaoDong , Ren Bo 
Published: April 2018

Abstract
During the last 10 years, a series of megaprojects have been implemented to develop new areas and improve the recovery factor of mature oilfields in Bohai Bay, and the oil equivalent of Bohai has kept steady for more than 188 MMbbls for 6 years. There were many challenges in front of the comprehensive adjustment of mature oilfields including difficulties of engineering facilities upgrading, inter well anti-collision, complexity of remaining oil distribution. Driven by the needs of the project, the conductor was innovative and bold in marine engineering, drilling and completion, reservoir engineering to reduce risk, improve efficiency and increase the IRR (internal rate of return). The redevelopment project of S&Q oilfields was a typical example which included 1 FPSO upgrading, 10 platforms, 300 kilometers submarine pipeline and cable, and more than 370 infill wells.
Changing Landscape of Deepwater Field Developments
Authors: Landwehr Marcel M. , Mansfield Steven E. 
Published: April 2018

Abstract
Over the past few years the offshore industry has undergone a profound change.
Operators, contractors and suppliers have been forced to find new ways of working as the industry landscape changes, putting pressure on price and schedules. These new ways of working are taking shape in the form of alliances and mergers within the service industry, while operators take a more holistic approach throughout project lifecycles with their established contracts and suppliers.
This paper will review the changes & how new ways of working minimize interfaces, maximize efficiency and capitalise value-added contributions from the service industry.
This paper will also consider how different ways of contracting are evolving to drive the industry to further change regarding how we engage & balance risk between the various industry players.
Acknowledging the progress and promise of these new engagement models, Operators have requested Suppliers to engage during earlier stages as opposed to the traditional process previously followed.
Early engagement brings project execution expertise and experience while providing an innovative outlet for service providers to submit their best design proposals without the constraints of company-specific requirements. These models also provide opportunities to reduce cost, but more importantly – reduce interface, risk and the critical path of project schedules within this new industry landscape ensuring an earlier return on investment.
These changes will require all players in the offshore industry to focus their efforts to achieve additional improvements that go beyond internal processes, mergers, and acquisitions. Although these are necessary to ensure that the industry remains competitive, they alone won’t be sufficient. Operators, Contractors and Suppliers need to also work together to cause and manage a shift in balance between risks and rewards.
Finally, changes in one part of the industry (e.g. Equipment / Contractor type alliances) provide new opportunities in other sectors where collaboration has not yet materialised.
As such there is a promise of further improvement of cost, risk and schedule when these opportunities are materialised.
Managing Risks in Relief Well Operations: From Planning to Execution
Authors: Poedjono B. , Macresy L. , Sikal A. 
Published: April 2018

Abstract
The complexity of drilling a relief well requires a robust workflow, which defines all actions to be undertaken at each of the drilling phases. This workflow is used for decision making at every organization level from the field level to management.
To ensure successful execution, all risks must be identified, and detailed preventive and mitigation actions put in place. These actions reduce risk to an acceptable and reasonably practical level at all times.
The relief well drilling process needs to be consistent and must contain these key elements: A multidisciplinary team with clearly defined roles and responsibilities at each operations step for optimal communication.A thorough understanding of relief well techniques, methodologies, and processes, including various solutions. These solutions must be confirmed with simulation, communication techniques, well control and fluid dynamic killing modelling, relative positioning with various measurements and their uncertainties, and drilling in the presence of magnetic interference.All team members and third parties should use drilling simulations during the planning phase to identify any gaps, and ensure redundancies are in place. Scenario planning will ease the go/no-go decision making during execution.Incorporating existing workflows into the entire relief well process, such as anticollision risk management and hazard and risk control, to reduce the risk of having multiple sidetracks or having to drill an additional relief well.
This paper will present the relief well workflow process and provide insight into the seven phases of the workflow, including planning, approach target, locate target, follow target, intercept target, killing operations, and plug and abandon operations.
A Novel Coating to Reduce Solids Deposition in Production Systems
Authors: Bethke Gregory K. , Snook Braden , Herrera Gilbert , Kelly Amy E. , Joshi Sanjeev , Jain Shekhar , Choudhary Suresh , Hammami Ahmed , Evans Lee 
Published: April 2018

Solids deposition in production systems can cause operational issues and costly mitigation. A novel hydrophobic coating has been developed that decreases deposition of solids, such as asphaltenes, scale and wax, under flowing conditions in well tubulars and flowlines. The coating may potentially lower field development costs by reducing umbilical tubing, chemical injection systems, and insulation that are currently used to manage deposition risks. Lab tests and field trials were used to evaluate the effectiveness of the coating.
Lab tests, from benchtop to large-scale flowloop, were designed and undertaken according to the solid of interest. In all cases, coated test sections were compared to uncoated sections under similar operating conditions. The impact of the coating on asphaltenes deposition was studied using the Organic Solids Deposition and Control (OSDC) device. Three types of scale (i.e. calcite, barite and halite) were investigated using rotating cylinder electrode (RCE) benchtop experiments and a small-scale flowloop. Coating performance with respect to wax deposition was evaluated with over forty flowloop tests. A field trial with a waxy African crude complemented the flowloop results.
Results from the lab tests and the field trial show that the coating does help mitigate the risk of asphaltene, scale and wax deposition under the conditions studied. Benchtop tests with two crude oils showed decreased asphaltene deposition for coated components. Lab results for scale also show a benefit from the coating. Calcite and halite deposition was dramatically lower on coated coupons and flowloop components, respectively, compared to their uncoated counterparts. Barite deposits on the coating were easier to remediate compared to the uncoated surface. The wax flowloop results have been consolidated into an operating envelope describing conditions where there is: no deposition with coating, reduced deposition with coating, and unaffected deposition (i.e. coated and uncoated behave similarly). A wellbore field trial with a waxy African crude validated the flowloop results. Wax deposition in the wells is typically managed with frequent scaping, sometimes as often as several times per day. With the coating applied to the inner wall of the tubular, the coated well showed a 75% decrease in scraping frequency relative to comparable wells with no coating.
This novel hydrophobic coating has been shown to help mitigate asphaltene, scale and wax deposition under the conditions studied. Based on the positive results of the performance testing, a commercial-scale application facility is being designed and constructed by Shawcor. Plans are underway to deploy the coating, where conditions are applicable, throughout the industry.
Intelligent Completions: Design and Reliability of Interval Control Valves in the Past, Present, and Future
Authors: Joubran Jonathon 
Published: April 2018

Abstract
The first intelligent completion was deployed in the Snorre field offshore Norway in August 1997, marking a major milestone for advanced completion engineering, reservoir insight, and production control. For the first time, an operator could manipulate tubing outflow performance at, or near, the sandface inflow node, without intervention or workover, but rather live via remote control using an interval control valve (ICV). Twenty years later, technological advancements have significantly increased the reliability and capability of intelligent completion tools with applications in ultra-deepwater, mature fields, as well as in the cost-sensitive unconventional arena.
This paper discusses the significant technological advancements and reliability of ICVs by comparing the following: case history examples of technology, applications, and installations from the past and present; associated technological and operation challenges with solutions and resulting reliability increases; and a view of the future design and reliability aspects of ICVs with respect to hydraulic vs. electric control and actuation. ICV case history examples are discussed below:
Comparing two field-wide offshore deepwater Africa campaigns in 2007 and 2015 with respect to ICV reliability, operational improvements, and technology from eight years of continuous improvement. Using a remotely operated hydraulic ICV installed above the production packer as a circulating device and a gas-tight barrier. This ICV was actuated through pressure signals to a battery-operated control module and micro-hydraulic pump vs. control lines to surface. History of ICVs installed as part of the mature fields of the Middle East and why high-actuation force will always be a requirement. A current high rate water injection completion campaign as part of an offshore mature field in which ICV position sensors transmitting choke positions in real time have significantly increased the operator's confidence of zonal-flow allocation. A Middle East operator's current application for low-cost ICVs. History of ICVs installed in multi-lateral completions and why they should stay in the motherbore.
The steady increase in ICV reliability is the result of advancing technology, as well as continuous improvement in operational procedures. These case histories help detail each advancement.
The future of intelligent completions and ICVs is tied to precision of device control, system reliability assurance, and effective use of sensor data to generate recognizable value. Precision and data require electronic control and transmission; however, hydraulic actuation offers more advantages with current available technology. This paper concludes with an argument for the future of practical ICV installation, zone control, actuation, and closed-loop operator interface.
Emergency Chemical Scavenging of Hydrogen Sulfide During Gulf of Mexico Well Flowback
Authors: Budd N. , Joshi N. B. , Paille A. , Li Q. , Miller T. , Kapadia K. 
Published: April 2018

Abstract
During an initial Drillship flowback of a newly completed subsea GoM well, the produced fluids were found to contain unexpected and significant concentrations of hydrogen sulfide (H2S). Despite no detectable levels of H2S in the native reservoir fluids produced from nearby wells in the same sand zone, the flowback separator gas-phase consistently showed H2S concentrations in excess of 100 ppm. It is believed that the souring was caused by irregularities during the completion phase, and the flowback was suspended indefinitely until the serious HS&E concerns could be addressed.
Collaboration between the operator and the chemical partner resulted in appropriate operating procedures and chemical selection to allow the well to flowback through existing infrastructure. To mitigate the presence of sour fluids in the carbon steel subsea flowline and topsides plant, the chemical partner was able to prove through laboratory testing that a liquid-phase subsea H2S Scavenger application would prove highly effective. To deliver the chemistry, the scavenger was injected topsides (25 ppm scavenger to 1 ppm gas-phase H2S) into a continuous dead oil circulation that would be used mix with the sour fluids at the wellhead and provide a turbulent flow regime for mixing. This stage of the procedure was preceded by a 500-gallon oil-soluble corrosion inhibitor pill delivered between two pigs to protect the infield flowline from any acid gas induced corrosion.
Once well flowback was re-initiated with the treated dead oil circulation, the chemistry was observed to be highly effective at scavenging H2S in the subsea flowline. Draeger tubes and inline gas meters showed no detectable levels of gas-phase H2S during continuous scavenger treatment. To confirm success of the chemical treatment, injection was temporarily ceased and H2S levels were once again detected and began to climb. The value delivered by the relatively small amount of scavenger chemical was tremendous, as the chemical partner was able to help the operator prevent multi-million dollars in workover expenses. Though not immediately quantifiable, the mitigation of topsides HS&E concerns was equally as valuable since the souring was neutralized prior to boarding.
Fluid Loss Control in Smart Bentonite Drilling Mud Modified with Nanoclay and Quantified with Vipulanandan Fluid Loss Model
Authors: Vipulanandan C. , Mohammed A. , Samuel R. G. 
Published: April 2018

AbstractIn order to enhance the performance and sensing properties of the water based bentonite drilling mud hydrophilic bentonite based nanoclay was used. The bentonite content in the drilling muds were varied from 2% to 8% by the weight of water and temperature was varied from 25°C to 85°C. The nanoclay (particle size in range of 12 nm to 20 nm) content was varied up to 1% by the weight of the drilling mud to modify the rheological properties, enhance the sensing electrical resistivity and reducing the fluid loss of the drilling mud. The fluid loss experiments were performed on bentonite drilling muds modified with nanoclay at 100 psi up to about 420 minutes till the end of the fluid loss. Based on the experimental and analytical study the electrical resistivity was identified as the sensing property of the smart drilling mud so that the changes in the properties can be monitored in real-time during construction.Addition of 1% nanoclay to 8% bentonite drilling mud reduced a fluid loss to zero at 25°C. The results also showed that 1% nanoclay decreased the electrical resistivity of the drilling mud from 15% to 36% based on the bentonite content in the drilling mud and temperature. Compared to the Vocadlo model, Vipulanandan rheological model better predicted the shear stress- shear strain rate relationships all the drilling muds investigated in this study. In all cases, except for the 8% bentonite drilling mud at 25°C, adding 1% nanoclay more than doubled the yield stresses and the maximum shear stress tolerances. The rheological properties of the drilling muds have been correlated to the electrical resistivity of the drilling mud using the Vipulanandan correlation model. The API fluid loss model was compared to the new kinetic Vipulanandan fluid loss model in predicting the experimental results for fluid loss. Compared to the API fluid loss model, Vipulanandan fluid loss model was effective, based on the lower value of root mean square error value, in predicting the short-term and longterm fluid loss with time, nanoclay content and temperature. The new model predicted the short-term and long-term fluid losses very well. This model also has a limit on the total fluid loss but the API model doesn't have a limit.