Several improvements on fluids, equipment, completion design and practices have been successfully implemented in the first subsea well of Morvin HPHT field offshore Norwegian Continental Shelf. These improvements are:Using new heavy weight reduced solid oil-based completion fluid for running the lower completion (predrilled liner) and achieving the expected initial productivity ;Extra well cleaning prior to running the lower and upper completion;A designed predrilled liner combined with open hole swell packers for zonal isolation and HPHT tracer-subs for data acquisition;Downhole barrier being installed as an integral part of the lower completion, eliminating the middle completion ;New HPHT permanentretrievable production packer; andSuccessful installation of downhole P/T gauge with pig tail connection below the tubing hanger. Completion operation on the first well was completed in 40 days (i.e. 12 days less than the planned days) with no major operational set back, safety and environmental incidents. After the well clean up, the well has been flow-tested up to 1500 Sm3/d (limited by rig capacity) and the well testing evaluation shows that the well delivers productivity as expected. Tracer samples analyses also show good production contribution from both reservoirs being penetrated by 1000 m of 8-½?? horizontal hole section. The HPHT reservoir (819 bar / 162 oC) in Morvin wells requires a different approach to completion design and practices in order to avoid well control incidents, operational problems, and achieve full well integrity during its production lifecycle. It demands the use of non conventional materials and fluids, careful equipment selection which is seldom available off-the-shelf in today's market, equipment qualifications and new procedures1. This paper describes the original completion concept that was much influenced by well completion experiences from the Kristin field, the world's first HPHT field to be developed subsea from multi-well templates. The paper then discusses the improvements made from the original completion design, challenges and contingencies. Introduction Today, oil and gas E&P activities have been steadily expanded into handling more complex and challenging projects such as high pressure high temperature (HPHT) wells. Among the regulatory bodies, the Norwegian Petroleum Directorate (NPD) defines HPHT wells as deeper than 4000 mTVD and/or having an expected shut-in wellhead pressure (SIWHP) exceeding 690 bar and/or having a bottom hole temperature exceeding 150 oC2. The main factors affecting the completion design and well integrity in HPHT wells are the extreme surface pressure, very high temperature, and various load scenarios during their lifecycle combined with the corrosivity level of the well environment. Risk of failures in this HPHT completion design is usually associated with2:High stress environment, both tension and compression.High operating temperatures.Chemical activity of well fluid components enhanced by the high temperature.Narrow margin between the boundaries of load uncertainties and equipment's material rating. Longer planning process is sometimes required to anticipate long lead times of HPHT specific equipment. Longer time is also needed for the equipment qualification.

The last well on the Morvin subsea High Pressure High Temperature (HPHT) field, located offshore Norway, was a combined production and exploration well. This well had as objective to drill through two known producing reservoirs and then continue drilling whilst dropping into two deeper and unexplored reservoirs. Drilling conditions on Morvin are very tough due to extremely hard and abrasive sandstone formations combined with long horizontal reservoir sections with temperatures of up to 167° C. Neighbouring wells had been on production for several months causing depletion in the upper formations. This depletion had to be carefully monitored and managed to prevent any losses/well control scenarios. In order to prove the reservoir fluid system in the exploration part of the well several operations were conducted. These consisted of, amongst others: extensive logging, coring, pressure points and a newly developed formation sampling tool. The results were used to adjust the well path and to decide whether the new formations would be completed, or cemented back. An HPHT oil and water tracer system was developed to be installed in the completion. The specially developed tracer technology enables the localisation of any possible water or oil producing formations. In addition, blank pipe combined with openhole swell packers were installed between the different formations for zonal isolation. Wireline conveyed bridge plugs give the possibility to plug water produsing zones back. This paper describes the strategy which was followed, together with the technology that was used, to prove the reservoir fluid system in the exploration part of the well. After assessing all data it was decided to complete both exploration formations. The well was successfully put in production 5 weeks after the exploration part was finished making this an extreme fast track project.