Filter-cake cleanup in open-hole gravel-pack completions has traditionally involved several stages: gravel-packing, pulling out of the hole with the work string, running in hole with production tubing, running in hole with coiled tubing, circulating the excess carrier fluid from inside the base pipe and spotting a breaker solution. Furthermore, in cases where removal of both the polymeric components and the CaCO3 bridging agents is necessary, an enzyme or an oxidizer soak has typically been followed by an acid treatment. This process is time consuming and costly, in addition to being non-optimal in terms of uniform cake-cleanup in long open-hole completions, due to rapid reaction between acid and CaCO3 particles. Recently proposed simultaneous gravel-packing and cake-cleanup method incorporating breakers into the gravelpack carrier fluid have been demonstrated to be an efficient technique through more than a dozen field applications, as evidenced by higher productivity compared to offset wells completed with conventional techniques. Because of the inherent risk in simultaneous gravel-packing and cake-cleanup with water-packing technique, carrier fluids containing breakers for filtercake removal have been used in conjunction with shunt-packing, which has been demonstrated through both field applications and large-scale yard testing not to rely on either the filter-cake or the formation properties. However, because shunt technique relies on viscosity for gravel placement, application of the simultaneous gravel-packing and cake-cleanup technique with polymer-free visco-elasticsurfactant (VES) carrier fluids has been limited to wells requiring a density of about 9.8 ppg (for circulating packs) and a bottom hole circulating temperature less than 200°F. In this paper, we present new surfactant formulations, which have unique chemistry that allows them to form visco-elastic surfactant solutions in high-density brines and remain stable at elevated temperatures. Densities up to 13.8 ppg with a rheological profile suitable for shunt-packing at bottom hole circulating temperatures exceeding 250°F are achievable with this new surfactant, covering a large majority of the gravelpack applications. It is further demonstrated that this new surfactant system does not only allow the use of certain chemicals that can be used for CaCO3 dissolution in conjunction with a gravel-pack process, but also requires these chemicals as co-surfactants in order to develop a visco-elastic structure. In addition to discussion of the unique chemistry of this VES formulation, data pertaining to proposed gravel-pack applications are presented. These include rheology, gravel suspension properties, filtercake dissolution characteristics, and retained permeabilities. A field case history utilizing the new VES fluid incorporating filter-cake cleanup chemicals is also detailed.

Ormen Lange is the second-largest gas field in Norway, currently providing 20% of the domestic gas consumption for the UK. As one of the world's largest subsea big-bore gas wells -with production rates up to 350 MMscf/d per well, a 120-km tieback to shore, subzero seabed temperatures and a design life of more than 30 years -these wells provide unique technical challenges. Due to the low reservoir rock strength, high velocities and the life expectancy of these wells, sand control was identified as a prerequisite from day one. This paper clarifies the logic of the selected sand control method and describes the extensive testing required to qualify the sand control hardware and associated completion fluids for the expected operating conditions. The execution of thirteen successful sand control completion installations will be discussed, including both ends of the success spectrum, and well performance will be covered.Throughout the four-year installation campaign to date, a number of new technologies were qualified and successfully integrated into the lower completions. These included cableless gauges to provide data closer from the reservoir inflow area, tagged proppant for individual subsea well fingerprinting if proppant is found at the gas plant, and water-tracer technology to aid in identifying the subsea source of potential formation water breakthrough.This subject explains the extent of the effort to progress an ambitious field development based on big-bore gas wells only (to reduce well count) from the drawing board to flawless execution and world-class production. Relevance also relates to other major big-bore, high-rate gas subsea developments with sand control requirements that are currently being pursued in similar harsh environments (deep water, Arctic conditions, sub-zero seabed) that might have interest in the application of Ormen Lange's successfully implemented technology.

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.

Sand production is a global problem which causes millions of dollars in equipment damage, deferred or lost production and non-productive time (NPT) every year. Consequently, the accurate selection, modeling and evaluation of sand control techniques is crucial for completion and production optimization as well as risk minimization. This has traditionally been done using spreadsheets, industry rules of thumb and previous experience but, as completions become more complex with longer intervals and smaller fracture pressure windows, error margins are tightening and the cost of failure increasing so a more robust approach is required. This paper details the application of a novel commercially available gravel pack software in the prediction of circulating pressures and gravel placement during the wellbore displacement, step rate test and gravel pack stages of completions operations for two horizontal open hole wells completed with alpha/beta gravel packs. Each well is first simulated to predict expected packing and pressure trends, then evaluated using measured surface and downhole gauge data to identify actual packing mechanisms and better understand downhole events, and finally optimized by directly comparing predicted and measured data to validate model accuracy and reliability. This detailed approach enables the early identification and mitigation of potential risks as well as the ability to better investigate any failures for continuous improvements in both design and operations. Overall, the model is found to match closely with measured data, providing a robust engineering tool for the simulation, evaluation and optimization of horizontal open hole gravel pack (OHGP) completions. The methodology presented facilitates the more accurate design of increasingly complex treatments and helps identify deviations from expected pressure and packing trends to reduce risk, improve reliability and maximize the likelihood of success.

The challenges in developing the Ormen Lange field were the harsh weather conditions, deep-water depth, subsea topography and sub-zero seabed temperatures. Due to environmental constraints and the selected sand face completion type, a water-based fluid system was required. This paper discusses the design of the fluids to give full hydrate inhibition, maximize breaker effectiveness, provide low overbalance, and reduce corrosion risk. An extensive research and development program was initiated that spanned over two years. The study included bridging and chemical component selection, brine evaluation, hydrate suppression measurement, elastomers compatibility, extensive breaker treatment studies, formation damage measurements using actual reservoir core and long term corrosion testing. An in-situ generating acid/enzyme breaker treatment deployed in the gravel pack carrier fluid was developed to optimise filtercake cleanup whilst providing a non-corrosive environment for the selected gravel pack screens and lower completion metallurgy. The basis of design and knowledge gained in the laboratory testing phase was transferred to the field and the first three wells of the initial development phase have been drilled and completed trouble-free. The resulting production rates have met expected targets proving low formation damage and an efficient cleanup was achieved. Introduction When the Ormen Lange field comes into full production, it will make Norway the second largest exporter of natural gas in the world and will supply 20% of the UK's gas requirement. Maximum daily exports from the Ormen Lange field will amount to 80 MSm3/day of gas and 50,000 bbls of condensate. The gas will be piped to the UK through the Langeled Pipeline which is the world's longest underwater gas pipeline at 1200 km long. The field was discovered in 1997 and is the second largest gas field on the Norwegian continental shelf. It is situated 140 km west of Kristiansund in the Norwegian Sea in deepwater, with depths up to 1100 meters and seabed temperatures as low as minus 1°C. The field has proven gas reserves of 400 billion m3 (14 Tcf), with an expected field life of 25–30 years. The first phase of the field development consists of two subsea templates with eight subsea big bore wells requiring a total investment close to 10 billion USD. During the later phases of the project, a third and possible fourth template will be installed bringing the total number of wells up to 24. Each of the big bore wells is designed for production rates up to 10 MSm3/day (350 MMScf/day). Therefore optimum drilling and completion fluid selection was considered to be a key focus area to maximise the open area to flow and associated well productivity, in order to comply with the planned lifetime and production targets.