Opawale, A. O. (FMC Technologies) | Arreola, S. (FMC Technologies) | Ciprick, K. (FMC Technologies) | Ibouhouten, B. (FMC Technologies) | Kruijtzer, G. L. (FMC Technologies) | Verbeek, P. H. J. (FMC Technologies) | Akdim, M. R. (FMC Technologies)
Wellhead desanding may increase the productivity of an oil/gas well as it opens the opportunity to a minimized choked-back production. Utilizing a wellhead desanding system upstream of the choke valve, minimizes the risk of erosion of the downstream equipment as for example; valves piping, etc. In addition, better sand separation may be achieved at high pressures due to presence of dissolved gas in the crude oil. These benefits motivated the development of the Wellhead DeSander technology as a significant improvement to conventional cyclonic desanders, gravity-based sand traps and strainers.
The novel desander system utilizes a stationary non-rotating swirl element which removes sand particles from produced multiphase fluids driven by a centrifugal force. Separated sand particles are temporarily stored in an accumulator vessel designed with an automated system that detects the level of accumulated solids and initiates the flushing procedure. In this paper the development and qualification of the Wellhead DeSander technology will be extensively described.
Case studies describing flowback operations at shale plays across the US are presented. Field data is shown demonstrating the separation performance of the Wellhead DeSander at various operating conditions such as: fluid production rates in the range of 1,500 to 14,700 Barrels Per Day (BPD), produced sand concentration upto 5 % volumetric (V/V), heavy paraffinic hydrocarbon, Gas Volume Fraction (GVF) > 90 % and watercut upto 84 %. Separation performances of the Wellhead DeSander have been measured with and without an upstream conventional sand trap. Separation efficiencies upto 99 % have been achieved with the Wellhead DeSander technology. The Wellhead DeSander can provide substantial economic benefits such as reduced erosion of a process facility and minimized operating costs with sustained optimal well productivity when solids are produced.
Subsea cooling in oil and gas production might seem to be opposite to the usual flow assurance challenge, maintaining a high enough flowing temperature of the produced stream in order to ensure problem free transport of the crude from well to the host. During FEED and detailed design, particular focus is aimed at maintaining a required temperature with insulation and even electrical heating are employed in order to achieve this. Hydrate formation, wax and asphaltene deposits are challenges that are connected with too low temperature, and considerable effort is spent in quantifying acceptable temperature, and cool down times of subsea equipment. So one might ask why and where is the need for subsea cooling? It turns out that there are situations where the well fluids are very warm and reduction in the temperature is required for profitable development of a field. For example, where an expensive flow line material would render the installation too costly, a reduction in temperature might make the investment evaluations look attractive, or where heat is generated subsea by for instance a subsea gas compressor. The temperature greatly affects the corrosion rate, and by changing the temperature, chemical dosage can be optimized, which further strengthens the financial analysis of a field development. This paper focuses on active subsea coolers, i.e. subsea cooling systems that are equipped with adjustable means, and attempts to analyze and benchmark four different subsea cooler types using a generic wet gas production case. A recent development involving a sea current controlled active cooler is introduced and compared with three other active cooler types and how they operate with a given set of operation and turndown conditions are presented. A comparison of weight, size, auxillary equipment and required topside scope is also included.
Existing operating facilities are often restricted by key bottle necks in the processing facilities that limit overall production. Typical bottlenecks limited capacities of separators and scrubbers that lead to liquid carry-over and in turn impact downstream compressors; water-in-oil emulsions leading to off-spec crude oil and too high oil-in-water content to meet discharge or re-injection specifications. By addressing and removing these bottle necks in a cost efficient matter the overall production and revenue of the crude oil production facility can be increased. Especially in the current environment, any investment costs should be balanced by a quick return on investment to make good business case for investment. In this work a general retrofit strategy is presented, that consists of several steps, including problem analysis, bottleneck finding, different solutions strategies, and a selection phase.
Over the past 10 to 15 years subsea processing has been globally established as a market segment within the subsea development arena, and subsea separation has been a vital part of this development with Troll C, Tordis SSB, Pazflor and others. The track record of these installations have been outstanding, some of them with documented uptime of more than 99%. Still focus in the market seems to turn towards more ‘clean’ pumping or compression solutions at a time where the boosting technology options increases, while separation seems to be linked to more complexity and higher capex and are often not included as an option in evaluating a field.
Still, subsea separation has some distinguished qualities that cannot be matched by other IOR methods. The more obvious scenarios are linked to flow assurance issues such as hydrate or slugging conditions in a field, but in addition some fields with very low production pressure or very long transportation distance to shore. Equally important is the operators need for flexibility in the design to cover for uncertainty in the production over the life of field and to count for future unexpected situations. This could be for a greenfield, redevelopment of a brownfield, or in general uncertainties about future sand or water production. Subsea separation is a simple way of mitigating these uncertainties, while at the same time increasing the operational envelope of the overall system compared to a pump or compressor alone. The paper will present examples of how separation can hugely add value compared to boosting alone by using simple, robust technology, resulting in more predictability an increased Net Present Value (NPV) for the operator.
Change. Look around. It is happening faster than most of us have seen in our entire careers. The market is driving change with a desperate insistence. The old ways of doing business are no longer sustainable. Change is therefore inevitable. New technologies as well as new business models are evolving. We have learned in our leadership training that we can follow change, we can get out of the way of change, or we can lead change. The astute business leader will always chose the latter, while recognizing and avoiding the temptations of falling into the behaviors of the former. So what does it mean to lead change?
The market is seeking two seemingly conflicting goals:
The market will determine how these two mandates balance out. Future industry leaders will be determined by the companies and organizations that best achieve both of these goals simultaneously. Finding and developing synergies between these goals will be recognized. The challenges before us are clear, but they will require significant changes to our existing business models and our inertia as an industry.
Our featured papers illustrate some ideas and methods to promote change in the ways we have conducted business, thus achieving positive results. The first paper illustrates an operator’s experience using standard equipment for the expansion of an existing subsea field in Brazil. Our industry tends to focus on locally developed solutions, but this was a case of finding the right answer in the global tool box. The authors explain the organizational resistance to this change, with the end results providing a very positive outcome. The second paper proposes a scientific method of efficiently establishing qualification requirements to increase safety and reliability of offshore operations—integrity assurance. This is a good example of recognizing a standardized way of focusing on the important issues facing technology qualifications. Our third paper is a contribution from academia describing concerns about fatigue strength evaluations of subsea wellheads, suggesting an analytical treatment that will actually reduce the calculated fatigue-damage rates from thermal effects of operations, thus reducing risks (costs) of the system.
I also invite readers to consider reading the suggested additional papers describing some enabling technologies involving large-load-deployment systems, subsea in-line oil/water pipe separators, and operational experiences in subsea gas compression in the North Sea. All of these papers promote new approaches to executing offshore developments that involve change but promise to deliver positive outcomes in the appropriate applications. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 26138 Simplified Hydraulic Design Methodology for a Subsea Inline Oil/Water Pipe Separator by M. Stanko, Norwegian University of Science and Technology, et al.
OTC 26904 A New Subsea Large-Load-Deployment System by T. Krasin, Canyon Offshore, et al.OTC 27159 Gullfaks Subsea Compression—Subsea Commissioning, Startup, and Operational Experiences by Bjørn Birkeland, Statoil, et al.
Duhamel, Nicolas (FMC Technologies)
The first worldwide offshore FLNG projects are moving up to construction and commissioning phases, with first gases most likely planned for the next two years. These floating facilities will operate in exposed environmental conditions (typically Hs up to 2.5m), under which it has been demonstrated that side-by-side offloading remains a safe and viable operation. The excellent track records of marine loading arms in the LNG industry; as well as the great economical advantage to distribute LNG to conventional LNG carriers, naturally led to the development of offshore loading arms, being the references on the FLNG market today.
Nevertheless, the higher performances, enhanced availability and the ability to relocate the FLNG in any location of the world naturally forced the FLNG projects owners to look carefully at LNG tandem offloading, as a natural way to offload as per FPSO culture. Whereas the main showstopper was the lack of maturity of LNG tandem offloading technologies a few years ago, latest developments made on the FMC ATOL (Articulated Tandem Offshore Loader) in partnership with oil & gas majors, DP suppliers and LNGC operators change the stakeholders dreams into reality.
The FMC ATOL has not only been validated through comprehensive kinematic, stress and fatigue analysis to confirm a 99+% operability in the harshest Australian type conditions, it has also been fully validated thanks to an 1/5 scale model tested under the harshest environmental conditions with third parties involvement.
Field proven components designs and technologies resulting of 50 years of conventional LNG transfer records and today of offshore side-by-side LNG transfer with loading arms are transposed to the ATOL LNG tandem transfer solution and prototype-tested to real project conditions, like the FMC ATOL swivel joint which successfully passed a long life test equivalent to a 10-year maintenance-free period (considering 1 offloading a week). These are 7 years of development and 30 000+ hours of engineering which rose up the technology readiness level high enough for the deployment of the FMC ATOL on field.
On top of that, a consolidated execution plan has been developed detailing a 30 months delivery time, including project specific engineering, purchasing, construction and tests. As part of this execution plan, the FMC ATOL has been developed emphasizing the turnkey approach, to minimize the integration works duration on the FLNG to a strictly limited number of mechanical and electrical interfaces. Such all-in-one design allows performing an extensive tests campaign on the ATOL before its delivery, inclusive of functional tests, static and dynamic tests and simulations of emergency disconnections.
This is how FMC Technologies provides performance, safety and reliability guarantees before the integration of the FMC ATOL on the FLNG, in mirror of how the success story of the FMC OLAF on Prelude FLNG project has been built.
Vast amounts of data are generated from a typical subsea control system, which provides visibility of the current subsea system condition to the operators. However, the extent of visibility is often limited by ineffective data processing and analysis. This paper will illustrate how data processing can be optimized through the implementation of subsea condition monitoring system, and subsequently reduce operational expenses (OPEX).
Similar to the subsea control system, all data is instantaneously received by the subsea condition monitoring system to provide operator with live data updates, which also allows historical trending for easy analyzing. Raw data can easily be displayed; however will only be valuable when translated to an actionable data. The condition monitoring system processes and analyzes each data points and translates them to a measurable condition index, which defines the subsea asset's integrity and determines how severely it impacts production and system availability. Data is presented in a dedicated user interface according to equipment and issue related information, which allows onshore operator and product experts a better focus and control during troubleshooting, root cause analysis or daily surveillance. With the capability of remote surveillance and utilization of existing instrumentation and equipment, the condition monitoring system can be conveniently implemented on both new and mature fields.
The condition monitoring system's data processing methodology will be illustrated and compared with the typical subsea control system. A field operational example will be shared to demonstrate how the processed data provides an early warning whilst the equipment is still operating. Having a constant knowledge of the equipment's condition from the continuous real-time update allows early proactive maintenance planning, hence reducing system downtime and maximizing intervention efficiency.
By extending the subsea control system with a separate condition monitoring system, operator will have a full control and in-depth knowledge about the subsea production system. Proactively recognizing and understanding equipment condition based on performance trends will help avoid costly unplanned repairs.
The challenges encountered in deepwater development have led to the use of increasingly complex subsea systems. Consequently, operators have become more reliant on subsea monitoring equipment and instrumentation to provide field information for understanding production and equipment conditions. Production monitoring is typically the field operator’s main priority, and equipment condition and performance are sometimes overlooked, resulting in equipment failures and long production downtimes because of unplanned maintenance.
Equipment failures often occur without warning and may sometimes, when caused by environmental factors, become inevitable. To determine the cause, field operators sift through vast amounts of distributed data from the subsea control system.
The system downtime can be reduced and system availability can be increased by performing effective equipment diagnosis. With the current low-oil-price environment, subsea operators are looking to maximize returns on investment, and condition-based monitoring offers the possibility of lowering operational expenses while increasing field production.
Condition monitoring is a proactive maintenance strategy combining software and people. Data are used to diagnose changes in the integrity of a system such that corrective action may be planned in a cost-effective manner to increase system availability. Condition monitoring is not a novel technology and is currently used in the aeronautical and automobile industries. The condition monitoring system takes integrity monitoring beyond traditional key performance indicators by utilizing all available data and information from the system and looking for trends of equipment degradation prior to equipment failure.
A condition monitoring system is typically based on the following three-step monitoring process:
Delescen, K. (Shell Brasil Petróleo Ltda) | Nicholson, M. (Shell Brasil Petróleo Ltda) | Olijnik, L. (Shell Brasil Petróleo Ltda) | Ortiz, W. (FMC Technologies) | Maia, A. (C-Innovation) | Lacourt, R. (Edison Chouest Offshore) | Nunes, H. (Edison Chouest Offshore)
The Parque das Conchas (BC-10) project consists of five fields, Ostra, Abalone, Argonauta B-West, Argonauta O-North and Nautilus, located in the Campos Basin area, offshore Espirito Santo, Brazil. The project is situated 75 miles (120 kilometers) southeast of the city of Vitoria, in water depths of 4,921 to 6,562 feet (1,500 to 2,000 meters). During the development of Phase II and III, Shell adopted an innovative integrated approach for the delivery, testing, installation and commissioning of the Subsea Production System. This approach led to significant gains in operational efficiency and overall helped in the optimization of the rig schedule. Some of the critical elements for success of the Project were the alignment of hardware delivery with logistics and custom clearance activities, a fit-for-purpose test facility in Vila Velha, a dedicated Multi Purpose Supply Vessel together with its ROV services, and a dedicated multidisciplinary team which leveraged the optimization of the learning curve through the execution of the project.
The objective of this paper is to show how Well Access Technology is changing from field and project specific equipment packages to be subsea tree-vendor and field independent multipurpose systems developed during early 2000 for open water and landing string systems. Fifteen years of experience from performing Riserless Light Well Intervention (RLWI) on more than 350 different subsea wells has provided the knowledge to develop today's state of the art multifunctional subsea service technology. The experiences and synergies of RLWI operations have enabled continuous development of the technology to meet tomorrow's requirement in subsea services.
This Paper will give insight into the challenges experienced by going from standard methods with hydraulic power supplied from the surface through heavy and expensive, large diameter umbilicals, to stack integrated ecofriendly closed loop subsea electrohydraulic control system. Demonstration will be provided on how experience has enabled interfaces and communications both electrical and hydraulic, with various manufactures' subsea trees, through the use of modular and flexible solutions with services customized for desired operational needs for the short and long term throughout the life of field. Add-on control unit module enabling control of cross vendor systems will also be presented.
Technology, operational experience and standardization have evolved over the years and have resulted in a set of robust system building blocks, which enable multi-functionality. The most recent systems are able to perform a large number of operations on a multi-field basis. From early 2000's, combined Workover Control Systems (WOCS) have been developed. These enable operation between open water systems and landing string systems, as well as for control of multi-fields and multi-vendor systems.
The scope of RLWI service is currently being expanded. An optimization of the second generation RLWI system suitable for deepwater application in the USA GOM will be described featuring the latest generation of fiber optics, electrical and electro hydraulic technology.