The big-bore, high flowrate completion design used on Ormen Lange features a high-set production packer and large bore 9 5/8" production liner. This completion design makes it impractical to install a traditional cabled Permanent Downhole Gauge (PDG) system close to the producing sandface. With separation distances of greater than 1,000 meters between the producing sandface and the PDG, and frictional pressure drops and gravity head differences to contend with, there is significant uncertainty in how the pressure measurements recorded by the cabled PDG relate to the true flowing sandface pressures. For wells operating on drawdown constraint, reducing these uncertainties allows the drawdown to be optimised, which is critical to maximising production and exploiting the field reserves effectively. This paper presents a case history of the development, qualification and first time installation in the deepwater subsea environment, of a new cableless communication system. The system provides two-way communications between a battery powered pressure / temperature monitoring system located remotely at the producing sandface, and the onshore control room located at Nyhamna in Norway. The cableless communications technology functions by transmitting low frequency electromagnetic (EM) signals using the steel casing or tubing of the completion, or the rock formation, as a signal path. For Ormen Lange, high accuracy and high resolution pressure and temperature data is measured at the sandface using a precision quartz crystal sensor. This data is then transmitted in real-time through the cemented large bore production liner to a signal pick-up located above the production packer. Data is then transferred from the pick-up to a seabed transceiver via a cabled link and then onwards to the onshore control room. The communication channel is two-way, thus enabling the downhole system to be reconfigured on command from the onshore control room. Cableless gauge systems installed in several Ormen Lange wells have successfully transmitted high quality, high resolution pressure and temperature data recorded at the producing sandface, to the onshore control room and then onwards to the A/S Norske Shell internal data network. The data is being used for multiple purposes, including pressure build-up (PBU) analysis at the sandface, to determine permeability thickness and skin damage, to monitor the sandface completion efficiency and integrity, to maximise the production rate and as a diagnostic tool to determine gradient and confirm the density of the wellbore fluids during early stage well production clean-up. This first time application of a new cableless reservoir monitoring technology is enabling wellbore uncertainties to be reduced in the Ormen Lange big-bore high-rate gas wells. This has lead to production optimisation and an improved reservoir understanding, the learnings of which have been applied across the wider Ormen Lange field development, even for those wells having no cableless monitoring system installed.

Permission to copy is restricted to an abstract of not more than 300 words. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper was presented. Publication elsewhere is usually granted upon request provided proper credit is made. Abstract It is now a standard practice to equip production strings of offshore wells with SC-SSV's. Although theme are no rules concerning the use of Down Hole Safety Valves in an annulus submitted to gas injection for gas lift purpose, concerns have been raised about the availability and implementation of such equipment. This paper reviews the experience of T.CFP in Down Hole Annular Safety Valves that started 8 years ago. It covers the field experience of Annular Safety Valves in single and dual completion. Introduction The purpose of down hole safety systems is to protect personnel, the environment and the surface facilities from threats to safety caused by the hydrocarbons produced from the reservoir. This concept is well established and field proven equipment and procedures are available. However, procedures are available. However, the majority of the effort in analysing, designing, testing and implementation of ever more performance down hole safety devices, performance down hole safety devices, has mainly been orientated towards tubing valves. Down hole safety devices are mainly dedicated to the tubing, ie SC-SSV's acting as a back up of the safety equipment installed on Christmas-Trees. In gas lifted wells where gas is injected in a casing/tubing annulus, gas will have to pass inside the tubing through orifices or valves. Due to these communications, the tubing cannot be considered as a barrier between hydrocarbon in the reservoir and surface surroundings. Although the orifices or G-L valves are generally equipped with check valves preventing the tubing content to flow back in the annulus, it is our opinion that this equipment should not be regarded as a valid barrier. Consequently the only remaining barrier between bottom and surface is the wellhead. It is assumed that the production casing has been properly production casing has been properly fitted for gas lift operations. If the notion of an artificially lifted well fits poorly with a potential blow out, the risk lies potential blow out, the risk lies with the large quantities of high pressure gas trapped in the annulus, pressure gas trapped in the annulus, should any damage occur to the wellhead. This risk is maximized in offshore operations because of the concentration of life and equipment on platforms. These considerations have led T.CFP to look for solutions in Down Hole Annulus Subsurface Safety Valve. CASE HISTORIES The first need for a Down Hole Annulus Valve arose in the Middle East area in 1981 where big producers tended to water out. Wells were equipped with a 10 3/4 × 9 5/8" production casing for accommodating a 7" × 5 1/2" tubing. The Annulus Safety System consists in a subsurface 10 3/4 "Hydraulic Packer associated with two Ported Packer associated with two Ported Nipple and one 5.87" Safety Valve Landing Nipple (Figure 1). The assembly is run with the tubing string and located below a 5.96" SC-SSV. The Annulus Valve is installed by wire-line means. Both tubing and Annulus Valve are operated through the same Control Line. Hydraulic pressure to actuate the valve is identical to standard Tubing SC-SSV's.

Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere is usually granted upon request provided proper credit is made. Abstract The Petrojarl I is the first purpose-built floating production and extended well test ship designed for worldwide application under the same type of leasing arrangement as a floating drilling rig. All other floating production systems in operation today are designed for site-specific conditions and would require significant modification for other applications. In its present: configuration this turret-moored process plant/storage tanker receives production from a single subsea well via either rigid or flexible risers. Stabilized crude is exported by an off-loading system to a shuttle tanker. This paper reviews the manufacture, testing, installation and early operating experience for the subsea production equipment associated with the Petrojarl I Production/Test Ship (PTS). It provides an overview of the system together with some of the more important design parameters. It also recounts the actual manufacturing, testing, installation and early operating experience for the subsea and other critical systems. This new type of production system is seen to be technically feasible and is also proving to be an economic success even in current depressed market conditions. BACKGROUND AND SYSTEMS DESCRIPTION Golar Nor Offshore A/S first placed contracts for the construction of the production/test ship (PTS) Petrojarl I in June of 1984. The PTS would be offered to the world market on a charter basis for the following applications: Conducting extended well tests to enhance reservoir evaluation for better depletion strategies by the permanent production facilities. For this purpose the system must be fully capable of wireline operations as well as production flow testing. Depending on production rates the oil produced can partially or fully defray the cost of this extended evaluation.

Abstract Until 1983, traditional cement squeeze techniques were used to shut off excess water production from wells in the Forties Field. The success rate was low, some 50% of workovers failing within 5 days of the well being returned to production. Casing patches over 120 feet long are now being run to cover the squeezed off perforations and workover effectiveness has increased dramatically. Radioactive tracers are employed to ensure accurate depth control as the patches are run and set on drillpipe. It is envisaged that continuous patches could be run when extremely long perforated intervals are encountered and alternative uses, e.g., to repair perforated intervals are encountered and alternative uses, e.g., to repair mechanically damaged casing, can be foreseen. TEXT The Forties Field is situated some 150 miles North East of Aberdeen and production began from the first of four platforms in 1975 (Figure 1). production began from the first of four platforms in 1975 (Figure 1). Pressure maintenance, by water injection, was started almost immediately. Pressure maintenance, by water injection, was started almost immediately. By 1980, a workover schedule, primarily for water shut off, had been established. The use of bridge plugs had to be limited because access to lower portions of the reservoir was often required after water breakthrough to monitor flood sweep efficiency using the time lapse technique. A further limitation was that water breakthrough did not always occur from the lowest perforations first. Production logging occasionally showed that water breakthrough had occurred along the top of a shale break. Hence water shut off workovers were performed by squeeze cementing the perforations and then cleaning out the casing to allow logging access. The perforations and then cleaning out the casing to allow logging access. The success rate was not particularly high and a number of techniques were introduced to try and improve the situation. These included the use of low water loss cements, hesitation squeezes, acidising prior to squeezing, the use of cement retainers to keep kill fluids above the perforations. None gave a dramatic improvement, although minor successes were noted. Perhaps the most disturbing feature of this phase of the operation was Perhaps the most disturbing feature of this phase of the operation was that no acceptable test for squeezed off perforations could be found - other than returning the well to production. Pressure testing with completion fluid or mud was not indicative of success and it was felt that a 'dry' test (DST test) often shock loaded the squeezed off perforations causing premature breakdown.