In certain parts of the world it is highly relevant to use spiral welded pipes for offshore applications. This is driven by cost, project characteristics and the desire to manufacture the pipe close to where it is to be used. Spiral welded line pipe has been used extensively for onshore applications, however there has been some reluctance to specify spiral welded line pipe for offshore applications. A joint industry project is beeing carried out together with coil manufacturers, pipe manufacturers, installation contractors and operators to review the status regarding offshore applications for spiral welded pipes and identify the most critical technology gaps using a technology qualification process. Detailed suggestions as to how the gaps can be met have been made. An update on efforts to close these gaps is ongoing. The challenges for spiral welded line pipe include design, metallurgical and quality control issues. The design issues include fracture arrest, collapse and displacement controlled loading conditions which are all highlighted in DNVs standard for submarine pipelines (DNV OS F101). The design issues regarding load controlled displacement are mainly due to limited experience with spiral welded line pipe subjected to large strains. For running fracture the limited experience with spiral welded pipe for offshore applications is an issue. There are 5 new spiral welded pipe mills in United States so availability has improved. The review includes an assessment of typical pipe material test results and whether properties required for offshore applications can reasonably be expected. Introduction Det Norske Veritas (U.S.A.), Inc. (DNV) and MCSKenny are carrying out a joint industry project (JIP) to investigate the suitability of spiral welded pipe for offshore applications. It appears that the industry has a general understanding that the performance of spiral welded (SAWH) pipes is different to Submerge Arc Welded (SAWL)/ High Frequency Welded(HFI)/ Electric Resistance Welded ERW linepipe when exposed to the same loading conditions, and that currently existing design standards for offshore applications may not be applicable. An important issue is to establish how the spiral wound linepipe can be produced consistently to a high level of quality, and what is required by the design standard for spiral welded pipe to be fit for purpose for offshore use. Some of the main areas of concern regarding the quality of spiral wound linepipe will be discussed. The aim is to assess whether SAWH linepipe can be considered equivalent to SAWL and HFI/ERW linepipe. The use of spiral welded linepipe (SAWH) for pipelines has generally been the most popular manufacturing choice of linepipe for onshore low pressure pipelines, pipelines transporting water, ship borne piping, or very shallow water, low pressure pipelines (= 500 ft). Recently there has been more interest in the use of spiral wound linepipe, due to the following reasons:There are five new SAWH pipe mills in America with "state-of-the-art" technology.SAWH linepipe is a cost-effective solution compared to the other manufacturing processes.Generally, the chemical compositions, mechanical properties and dimensional tolerances are assumed to be comparable to SAWL pipe.SAWH linepipe can be manufactured in 80 ft lengths with diameters from 20 to more than 100-inch OD and wall thicknesses ranging from approximately 9 to 25 mm.Some SAWH pipe mills have coating capabilities for 80 ft pipe lengths (FBE and 3-layer coating systems). 80 ft pipe lengths could mean less fabrication costs for the installation contractors.

Recently the offshore industry has shown an increased interest in developing a competitive Dry Tree Semi (DTS) concept. Several DTS designs have been proposed by floater designers and many of them have been evaluated by Operators and Classification Societies. So far, no DTS has been selected as host platform for a deepwater field development project. A Dry Tree Semi can be utilized for both drilling and production, eliminating the cost of the MODU which can run at approximately USD 500,000 per day and higher for ultra deepwater fields. Once a discovery is made, the field is no longer dependent on the MODU market for drilling access. The DTS concept increases the potential for deepwater development, especially for marginal fields. The result is increased reserves and productions in the Gulf of Mexico. It is essential to ensure that proper qualification of the concepts and all systems/components with novel technology has been carried out, in order to establish the foundation for a safe and successful project implementation, and reduces potential risk on personnel, environment and property. This paper provides an overview of the current technology and the concepts needed to be matured in order to make the project ready from operators and Classification Societies perspectives. The paper will discuss the key technical challenges of the DTS concept in general and how to make this technology ready to implement. Key technical issues discussed in this paper are global performance of the floater, riser system and responses, tensioner capabilities as well as technology qualifications. The paper will make relevant comparisons with other competing floating systems like TLPs, FPSOs and spar units. The methodology recommended to be utilized for the evaluation of the DTS technology is based on Chevron's Project Development & Execution Process. Within this process there is a Technology Selection workshop where the necessary technologies for the project are identified and determined as, enabling or enhancing, engineering or technology, and " proven technology?? or " new technology??. The " new technologies?? are then evaluated through the Technology Qualification Process. The Chevron's TQ Process was co-developed with DNV and is based on DNV-RP-A203 " Qualification Procedures for New Technology??.

New concepts and technology are vital for the Oil & Gas industry to meet ever more challenging requirements for drilling and production in deep and ultra-deep waters. When new technology is deployed, whether with novel equipment or standard equipment in novel applications, it is critical to build confidence in ts safety and reliability before implementation. Given that current industry standards and codes might not address all potential modes of failure for new technologies, a systematic technology qualification process can be used to identify and mitigate any potential threats. Compliance with the required functionality and reliability requirements can be demonstrated through qualification methods such as testing and analyses, and the uncertainty or risks associated with the technology, system and interfaces can be eliminated or minimized. Several recognized technology qualification methodologiesare currently available to the industry that completely or partially address qualification of new technology: ISO 20815 Petroleum, Petrochemical and Natural Gas Industries - production assurance and reliability management [1], NASA technology readiness level assessment system [2], DOE G 413.3-4A technology readiness assessment guide [3], Technology Readiness Assessment (TRA) Guidance, United States Department of Defense [4], , API RP 17N Recommended Practice for Subsea Production Systems Reliability and Technical Risk Management [5], API RP 17Q Subsea Equipment Qualification [6], and DNV RP A203 Technology Qualification [7]. Two of the widely accepted technology qualification (TQ) methodologies in the offshore Oil & Gas industry are API 17N [5] and 17Q [6] and DNV RP A203 [7]. Although both methodologies are quite similar, the differences may confuse technology developers, this paper addresses differences including the circumstances under which one might be more efficient/cost-effective than the other, how new technology is defined, and how much rigor is needed to address potential threats. In summary, this paper reviews and examines the similarities and differences that are presented in the two widely accepted TQ methodologies. Further, this paper provides insights on how to employ these methodologies to meet specific end user needs. In addition, a case study is included to demonstrate the comparisons between the methodologies.

As oil and gas companies extend their presence to remote and ultra-deep waters, one of their main challenges is to maintain environmentally responsible operations while maximizing returns on investment. Attention is directed to the increasing power demand offshore which triggers a quest for alternative and cleaner power supplies. One proposed solution is presented through the conceptual study abbreviated OPera - the Offshore Power system for the new era. OPera consists of a highly efficient power hub and an electrical transmission system, supplying cleaner power to a network of offshore installations. To detail the OPera conceptual study, the Brazilian pre-salt area was selected as a case example. The power hub has a gas fired combined cycle power plant that increases power generation efficiency by more than 15 percent, compared with conventional gas turbines alone. The power generation arrangement reduces CO2 emissions with approximately 40 percent. By consolidating power generation, the power hub also allows equipment to run at more optimal load. This is a major benefit, as it further reduces fuel consumption and overall emissions. The power hub is fueled by associated gas or parts of the export gas produced. The OPera concept is highly flexible in size and configuration, making it relevant for different types of fields. The power plant consists of modular gas and steam units of 50 and 100 megawatt (MW) capacities, allowing the combined capacity to be tailored. Depending on water-depth, different platform and hull-designs can support the power plant. The power hub can connect with different numbers and types of installations, being located in different water depths.

High pressure high temperature (HPHT) technology and field development have received much attention in recent years. Materials for HPHT environments, including ultra-high strength alloys and soft polymer compounds will in some cases be close to their capability limits. Materials testing and qualification have therefore been challenging for HPHT equipment design and project execution. At the same time, lower oil prices have put cost pressures on project developments. To overcome both technical and financial challenges while ensuring satisfactory project safety and performance, holistic and systematic solutions promoting materials standardization and innovation are necessary. In this paper, case studies and lessons learned from several recent and widely recognized Joint Industry Projects on subsea materials are presented. The philosophy of materials standardization and innovation behind these efforts will be discussed and their positive impacts on HPHT materials qualification and testing will be summarized.