AbstractThe natural gas industry is increasingly pursuing compact and lower weight processing technology for offshore, onshore, remote, and challenged gas processing. Increased modularity of process equipment and process intensification require innovative solutions. ExxonMobil Upstream Research Company (EMURC) has developed and qualified a new inline dehydration technology meant to replace conventional TEG tower and associated separator vessels to meet pipeline dewpoint specifications. Compact Mass transfer and Inline Separation Technology (cMIST™) achieves this goal with significant reductions in weight and footprint.The cMIST™ dehydration system relies on state-of-the-art technological advances in contacting and inline separation to achieve pipeline specification dry gas and/or prevent hydrate formation. It includes a novel droplet generator which creates small, well-dispersed droplets with a high surface area for absorption followed by an inline separator. EMURC has completed the technical qualification for the cMIST™ dehydration system and effective December 1st 2016, this system has been exclusively licensed to Sulzer for global deployment in offshore and onshore facilities.The cMIST™ dehydration system was demonstrated using a skid-mounted test unit in the Woodford trend area of Oklahoma, USA at an XTO Energy production facility. It was tested under a range of field conditions to examine the dehydration capacity, operability, and reliability of the technology and it achieved pipeline specification over a range of process conditions and during sustained operation.The cMIST™ dehydration system enables 50% dehydration system weight reduction and 50 - 80% absorber footprint reduction along with significant capital cost savings. The technology is highly modular to allow for simple transportation into remote, challenged, or offshore environments and provide installation configuration flexibility.
AbstractThe objective of this paper is to share lessons learned with the industry from a recent accident and provide a recommended procedure for evaluating airgap and possible horizontal wave impact loads for column-stabilized units operating in harsh environments.On 30 December 2015, when operating on the Troll field, a column-stabilized drilling unit, COSL Innovator, was hit by a steep wave that impacted directly on the forward port side of the deck box. This resulted in several damaged windows, one fatality, four injuries and structural damages to the front of the deck box.Following the accident, there is increased attention and concerns raised by some regulatory bodies for safe operation of semi-submersibles in harsh environment. In order to evaluate the adequacy of Class rule requirements and pertinent industrial design practices, DNV GL has investigated and analyzed the circumstances surrounding the accident. The conclusion from this work is that there is a need for improved guidelines for calculating horizontal wave impact loads on deck box structure if a column-stabilized unit is designed to operate with a negative airgap, together with improved methods for calculating the airgap with a prescribed annual probability of occurrence. DNV GL has developed "Offshore Technical Guidelines" (OTGs) that can be used to document compliance with classification rules stipulated in DNVGL-OS-C103 . Development of these guidelines has brought a deeper understanding with respect to airgap and associated horizontal wave impact loads on column-stabilized units.This paper discusses the technical challenges related to airgap prediction and wave impact load calculation, provides the technical background and insight of recently released Offshore Technology Guidance OTG-13  and OTG-14 , and suggests a way forward.
In a >100 USD/bbl market, the project economics are optimized by different parameters than in a market below 50 USD/bbl. In high oil price context, the focus is on maximizing the revenue (i.e. production), whereas in low oil price context, the focus on costs is more important. In today low oil price era, a new paradigm to optimize the project economics is << Less is More>>:– Less equipment/complexity can also be More safety and more Reliability – as less equipment lowers the probability of equipment failure, also reducing both CAPEX and maintenance costs– Less CAPEX/OPEX should enable More projects to become economically viable. Going to the essence of simple and robust systems enables solutions for the low oil price era. Indeed, while the HSSE commitment is not negotiable, the extra costs related to systems required for maximizing the production uptime are to be challenged to adapt the projects to the new market conditions. Using the example of mooring systems, a functionality review is performed so that the functional specification can be optimized for today's new set of project constraints. This applies along the EPCI chain:– Engineering: where relevant experience (industry standards and field proven solutions) can be used to avoid re-calculating everything to the highest degree.– Procurement where functional specification in place of – often over demanding - client specifications enables more standardization and thereby significant savings on price, schedule and sparing philosophy.– Construction where the clients can focus on ensuring/monitoring the HSSE and QA/QC performance of the project by choosing an ‘hands off’ approach on the execution part which enables the full benefit of using a seasoned contractor.– Installation – especially for Turret & Mooring systems – the installation aspects needs to be integrated from the beginning (Engineering). The most cost efficient way for a safe installation is to have the installation scope integrated in the mooring system contract (i.e. EPCI instead of EPC). All these simple principles (simplification, standardization, streamlining of the work, lean management) have to be implemented to enable project economic viability in today's market. This Less is More approach has been used on recent tenders and has allowed significant cost savings and schedule reduction leading to further cost reduction.
Degradable polymeric balls are becoming popular in well completions especially for hydraulic fracturing applications. Commercial degradable polymeric frac balls, however, are not suitable for high-temperature plug-and-perf applications due to the low glass transition (Tg) temperature of the base polymer. At the application temperature above Tg these commercial degradable polymeric frac balls become too soft and their mechanical integrity is compromised. This paper describes the application of a new degradable polymer composite frac ball made from a thermosetting polymer with (Tg) >500°F for use in hydraulic fracturing applications. This degradable polymer composite is good for a temperature envelope of 200°F to 350°F and differential pressures up to 10,000 psi for fracturing applications.
Multiple Pressure and impact tests were performed on the frac balls made from this material to demonstrate that the material had mechanical properties that would withstand the application requirements. Differential pressure tests were conducted on two types of ball seats at different temperatures. Frac balls were tested for plug-and-perf application on ball seats with a conical engagement.
AbstractThe Red Sea is a textbook case of a modern-day oceanic rift basin forming as a result of continental break-up. A characteristic feature of this setting in the central and northern Red Sea are more than two dozens of isolated bathymetric depressions, "deeps", filled with brines derived from leaching of the early-breakup Miocene salt deposits that lie beneath the entire Red Sea. The Atlantis II Deep is the largest basin of this type in the axial rift zone of the Red Sea. A topographic depression enclosing a volume of an estimated 15 km3 at water depths from 1900 to 2200 m, the Atlantis II Deep contains layered fluids with temperatures of up to 66°C and salinities of up to 27%. Beneath the brines, up to 30 m of fine-grained metalliferous sediments have been accumulating for the past 23 000 years (Anschutz, 1995). Unlike those in modern hydrothermal systems at mid-ocean ridges, where most of the metals are expelled to the open ocean in buoyant hydrothermal plumes, metals in the Atlantis II Deep are trapped and precipitated beneath a 200-m-thick brine layer. These sediments show extremely high concentrations of zinc, copper, silver, and gold (90 Mt of dry salt-free sediment at Zn>2%, Cu>0.5%, Ag>39 g/t., Au>0.5 g/t.). While the mode of metal deposition found in the Atlantis II Deep is not known from anywhere else on the seafloor today, it has yet been widely suggested as an analog for many ancient sediment-hosted ore deposits (Laurila et al. 2015). From 1975 to 1981 the German company PREUSSAG was contracted by the Saudi-Sudanese Commission for the Exploitation of the Red Sea Resources to explore the Atlantis II Deep. The project was aimed at assessing the overall technical viability of recovering and processing metalliferous muds on board of a mining vessel. The program encompassed several sampling cruises, a pre-pilot mining test (PPMT), environmental surveys, a study of pre-mining environmental conditions, as well as an economical evaluation. However, despite a highly successful PPMT, economic interest in the project waned due to declining commodity prices in the early 1980s. A substantial data set was derived from this campaign, including several kilometers of well preserved sediment cores and >20 000 pages of analog information. Utilizing this information, several GIS-based data mining efforts were carried out in recent years, driven by renewed interest in developing this unique resource. Our presentation will discuss results from these efforts and focus on the technical, economic and environmental boundary conditions of ocean mining of metalliferous sediments. Recently acquired geophysical data in the central Red Sea provide an unprecedented level of ground truth to historic data on Atlantis II.
AbstractDrilling capital expenditure represents significant portion of any oil and gas project. Drilling investment accounts to about 40% of the cost of the well. Therefore monitoring the health of equipments and processess associated with rigs are critical in bringing down both the cost of the well and the Non Productive Time (NPT). At the moment there are several Key Performance Indicators (KPIs) to monitor NPT but they are reactive in nature. Proactive measures can be taken to avoid NPT and reduce Invisible Lost Time (ILT) by exploiting the power of big data. The scope of this work is to create a framework to predict NPT and ILT causes from massive degree of unstructured data collected during the drilling operations. KPIs and performance values come from numerical metrics. In addition, the industry has also gathered an enormous amount of unstructured data from drilling and other reports. In many industries, Natural Language Processing (NLP) has been used to create value from unstructured data. Upstream reports are not exactly natural language ready reports. Our approach on generating value from these reports has two major steps (1) transforming NLP challenge to Technology language processing (TLP) in drilling context, and (2) classification of NPT causes.The two-step approach mentioned above results in a framework for mining unstructured reports to detect anomalies like symptoms, events, and actions. A modified NLP, referred here as TLP in the drilling context is used to achieve the first set of data extraction. Furthermore, a predictive model for classification of NPT and ILT causes is performed on the extracted data. The accuracy of these predictive models is an on-going effort, as it is dependent upon the transformation and detection of complex technical language that is inconsistent due to multiple reasons. However, this framework provides a foundation for predicting NPT / ILT during different phases of drilling operations. Use cases that predict attributes related to hole packoff or equipment failure shows the accuracy in the range of 50% to 70% due to a limited amount of extracted technical terms that are relevant. The framework calls for continual improvement of employing deep learning algorithm based on enhanced recovery of correlated technical terms across unstructured reports.While there are many attempts in using NLP for mining data in E&P sector, in this paper we present a framework for mining unstructured reports that leverage contextual Technology Language processing a step ahead NLP. Our framework incorporates the use of various machine learning algorithms to detect multiple attributes necessary to calculate NPT and ILT, and guides on how to enhance the predictive model.
AbstractAwareness of the challenge with lower available Wellhead fatigue life has increased as the Oil and gas industry has gained more knowledge through advanced analysis and tests. Loads on Wellhead are influenced by movements from drilling rig transferred through Marine Riser and BOP. These loads cause cyclical bending moments and Wellhead fatigue degradation. The intention of Reactive Flex-Joint (RFJ) is to lower the fatigue damage by reducing cyclical bending moment, which is a main contributor for Wellhead fatigue.It's was built a technology demonstrator (scale 1:25) in 2006 and patent of the system was approved. Later a full-scale workshop test model was constructed including a Flex-Joint (FJ) for simulation of environmental conditions. In addition there were preformed thousands of transient dynamic simulations with irregular sea conditions. An independent company duplicated these analyses and all results are verified by 3rd party. The 3rd party company also approved product qualification and use before offshore deployment. An environmental test through a complete drilling campaign of a new well was preformed spring 2016, verified the technology and efficiency covering a wide variety of environmental conditions. The BOP was instrumented to monitor live bending moments and inclination with and without the RFJ. More than 50 subsea tests proved 55 - 65% reduction of cyclical bending moment meaning 10 - 15 times extension of the remaining Wellhead fatigue life. The conclusion is that a modified FJ can reduce dynamic bending moments transferred from Riser to Wellhead during drilling and Work-Over operations. Reduced fatigue exposure gives increased Well access, improved Well Integrity and significant extended Wellhead fatigue life. The reduction of cyclical bending moments on Wellhead give extension of available days for connection, enabling additional Workover and/or side track drilling resulting in Increased Oil Recovery.
Patil, Devendra (Smart Materials and Structures Laboratory, University of Houston) | Kalia, Akshay (OneSubsea, a Schlumberger Company) | Zhu, Junxiao (Smart Materials and Structures Laboratory, University of Houston) | Ho, Siu-Chun Michael (Smart Materials and Structures Laboratory, University of Houston) | Zhang, Peng (Smart Materials and Structures Laboratory, University of Houston) | Lara, Marcus (OneSubsea, a Schlumberger Company) | Song, Gangbing (Smart Materials and Structures Laboratory, University of Houston)
AbstractLow hydrocarobon prices have raised concerns over the viability of offshore field development and maintenance over next several years. These oil and gas prices have called for engineering efforts to innovate new technologies to reduce the operational costs and improve the life span of the subsea exploration and production (E&P) systems in inhospitable environments like deep water. Subsea pipeline and jumpers are among these subsea E&P systems and it is crucial for operators to have these systems function in smarter and more efficient way, to adapt the inhospitable environment while generating profits. Due to their geometry and location, these pipelines are typically susceptible to vibrations induced by multiple factors, such as flow-induced vibrations (FIV) and vortex-induced vibrations (VIV). FIV and VIV can cause excessive stress on pipeline joints, thus limiting the operational lifespan of pipelines, specifically jumpers and risers. Every year, oil and gas operators spend significant amounts of money analyzing the cause and effect of these vibrations on the fatigue life of jumpers and pipelines, and installing traditional vibration mitigation devices like strakes and shrouds that have proven to be only partially effective. In most situations, these devices fail to suppress the vibrations and force operators to choke the flow from the well for safety, resulting in lost revenue.This paper introduces the pounding tuned mass damper (PTMD) - a novel device developed in a joint collaboration between OneSubsea and the University of Houston to absorb and dissipate the undesired vibrations in subsea pipelines and jumpers. The PTMD is based on principles of both the tuned mass damper and the impact damper. The tuned mass in the PTMD absorbs the kinetic energy of the structure and dissipates the absorbed energy through collisions on viscoelastic material. During development, detailed numerical analysis and experimentation were performed to study the effectiveness of the PTMD on the jumper. In the experiment, a full size M-shaped jumper was tested in both air and shallow water conditions for VIV at NASA's Natural Buoyancy Laboratory (NBL). The experiment also examined the robustness of PTMD for different frequency VIVs. Experimental results showed that the PTMD effectively reduced the in-plane and out-plane vibration of the jumper up to 90%. The observed reduction in vibration amplitude can reduce fatigue damage to jumpers, thus enabling operators to optimize spending on vibration mitigation devices, minimize lost revenues, improve system lifespan and availability, and enhance operational flexibility. Reduction in stress also means improved reliability and reduction in costs associated with inspection, maintenance, and repair of subsea jumpers and pipelines. These long-term financial benefits and ability to be installed on existing and new jumpers (pipelines) makes the PTMD a desired solution for vibration suppression in deep water environments.