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Abstract Drilling of the Tyrihans reservoir sections was affected by significant seepage losses. These added up to ~1000 m after drilling five wells with 13 reservoir sections, including pilots and laterals, and a total exposed reservoir length of ~15000 m. In this study, we estimate whether the reported losses can be explained by dynamic filtration mechanisms and related seepage losses. Daily drilling reports were evaluated to reconstruct the downhole drilling environment. Accumulated dynamic and static filter loss periods were calculated. A dynamic filtration HPHT filter press was used to measure dynamic filter losses of laboratory and field samples of the drilling fluid used on Tyrihans. Measurement results were evaluated and extrapolated to field scale. Finally, losses experienced in the field and calculated values were compared. Results strongly indicate that the reported losses on Tyrihans were dynamic seepage losses and that these losses dominate the total loss volumes clearly. The filtration volumes measured in the laboratory were significantly influenced by the shear rate applied. High shear rates caused a larger dynamic filtration component. There are indications that a reduction of coarse bridging particles during drilling and an increase of finer particles relative to the optimum particle size distribution increases the dynamic filtration component. Dynamic fluid losses may in magnitude be misinterpreted as lost circulation into microfractures or in developing fracture systems. A correct assessment of the nature of the losses is essential to select an efficient treatment. Elevated downhole and circulation temperatures as well as long reservoir sections creating large filtration areas cause increased dynamic seepage losses. To reduce these losses higher viscosity base oil could be considered in OBM or a less turbulent flow regime should be engineered. The latter can be achieved for example by increasing drilling fluid viscosity, reducing pump rates or choosing a smaller drill pipe diameter. Efforts should be put into maintaining the optimum particle size distribution of filtercake-building bridging particles. Such changes in fluid design should be carefully evaluated, as they can have a negative impact on other fluid parameters such as equivalent circulation density, swab and surge or reduced hole cleaning efficiency. Research should be initiated to develop low-dynamic-loss fluids. This requires a better understanding of dynamic loss mechanisms and the identification and verification of additives that protect filtercakes against shear and erosion.
ABSTRACT Tyrihans is an oil and gas-condensate field offshore Mid-Norway. Oil reserves are 29 million Sm3 and gas reserves are 35 billion Sm3. The field will be developed as a subsea project with 5 templates having 9 producers and 3 injectors. Production start-up is July 2009. The field development is innovative in the following aspects:Cost effective development with a 43 km tie-back to the Kristin platform through an 18″ pipeline. Tie-back is possible because the pipeline will have direct electrical heating to prevent formation of hydrates and to preserve temperature. Pressure support with both gas injection and raw sea water injection. This is feasible by installing two water injection pumps subsea and using available power and compressor capacity at neighbouring fields. Extensive use of advanced wells. The oil producers are dual-lateral with approx. 1.5 km horizontal reservoir sections, equipped with down-hole ICVs (Inflow Control Valves) and gas lift. Both main bore and laterals will have 8.5″ hole diameter, made possible by using 8″ expandable liners Important reservoir management and simulation issues are:Tyrihans consists of two structures, which cannot be produced independently. Handling gas and water coning in a two-front system and keeping track of fluid contacts are challenging. The northern structure consists of an 18 m thin oil zone with a gas cap. To simulate recovery from thin oil zones is challenging. The simulation model has horizontal grid, in order to have the required vertical resolution of the oil zone. Correct modelling of pipeline flow and flow assurance. The long, single pipeline tie-back makes well testing difficult. Reservoir monitoring and management must then be based on subsea flow meters and gauges. Production optimization will be performed from an onshore support centre. With the chosen reservoir development strategy high recovery is obtainable. The simulated oil recovery in the southern part is 52%, and the gas recovery in the northern part is 80%. INTRODUCTION Tyrihans is an oil and gas condensate field offshore Mid-Norway (Figure 1). Tyrihans Sør (South) was discovered by well 6407/1–2 in 1982 as the first discovery on Haltenbanken offshore Mid-Norway. The well test showed a rich gas-condensate. Tyrihans Nord (North) was discovered the following year, proving a gas cap with a thin oil zone. An appraisal well in Tyrihans Nord in 1996 was drilled through the OWC and proved an 18 m thick oil column. In 2002, an appraisal well in Tyrihans Sør showed a 35 m oil column below the gas cap. With total in-place volumes of 71.4 million Sm3 oil and 57.4 billion Sm3 gas, an independent development of Tyrihans was not economical feasible. In the meantime, the neighbouring gas-condensate field Kristin was under development. It was decided to develop Tyrihans as a subsea (SS) field, tied back to the Kristin platform. A subsea development makes investments in a platform/vessel unnecessary. However, long tie-backs are challenging with respect to oil recovery and flow assurance. This paper will focus on the SS development facilities and how high oil recovery will be obtained on Tyrihans.
The paper reviews the way leading up to the Subsea Factory Compressor Stations with focus on important technology step-stones and breakthroughs. A dedicated and long term focus on technology development through R&D has been carried out within a series of disciplines supporting the subsea production application. The development has been along two important axis; multiphase flow and subsea systems. A comprehensive R&D effort was initiated in the beginning of the eighties resulting in a highly successful and profitable development and implementation on the Norwegian continental shelf, namely the subsea industry. Through a series of successful tie-backs and long distance multiphase flow lines, the ultimate concept was achieved for gas-condensate systems represented by the unprocessed transportation of well stream directly to shore. The first multiphase pumps were installed in the late -90 and in 2000 the first subsea separation station was started up. Today subsea boosting and separation is proven technology. In 2011, building the first subsea gas compression station was initiated, taken the last step to a full subsea factory installation. To realise subsea compression, the main components have been subject to a systematic technology qualification process. The paper describes how Statoil's large scale laboratory facilities has been mandatory for full scale qualification testing as well as focus on quality to achieve the necessary level of confidence. The Subsea Compression projects solely, have carried out nearly 60 qualification activities, further detailed in the paper. The paper also looks forward and point out that the subsea processing solutions that have been qualified and implemented can be utilized to achieve cost efficient solutions with low environmental footprint.
During a market condition that is characterized by volatile oil price, there is a strong incentive in the Oil & Gas Industry on maximizing the hydrocarbons recovery from existing fields, rather than initiating new field developments. For offshore deep water field applications, subsea boosting technologies are considered to be a solution to improve the field recovery, while also acting as enabling technology that allows for development of deep, harsh and stranded reserves, which otherwise deemed non-accessible. This paper presents the performances and application area of two novel subsea boosting solutions developed by Aker Solutions: 1. The boosting of condensate and oil as well as pressure increase by water injection through high pressure subsea pumps 2. The subsea boosting of gas flow with associated liquid, though high performance subsea compression. Special focus is given to the subsea centrifugal pump and compression technologies and how these new solutions can solve the existing challenges represented by providing high performance pressure boosting for both oil production with high gas content, as well as gas production with high liquid content. Highlights on the key features of these novel technologies are provided, with specific focus on the benefits the technology brings to the market, like the high differential pressure generated together with the high efficiency and mechanical stability. These are all game changers for deep water IOR developments.
Abstract Tracers are applied as embedded in polymers that are placed in the downhole completion. The Tracer Systems are designed to change behaviour as a function of the surrounding medium. Such behavior can be the release of tracer into one medium while keeping tight in another. Released tracers will migrate to surface where topside fluid samples are analyzed and the tracer concentrations in those are the basis for extracting Well Inflow Information. The Tyrihans well, B-IAH T2, was cleaned-up in two sections and the 1100m long toe section was equipped with 3 unique oil soluble tracers that were placed along the production zone. The objective was to evaluate the quality of clean-up and (if necessary) also during a production restart 6 months later. The well had a downhole temperature of 137°C, higher than the operating temperatures for available Permanent Tracer Systems. So a new Tracer System had to be developed and qualified for the case. RESMAN's tracer systems indicate that the toe is contributing as expected to the fluid production and that additional production occurs along the well bore. All completion fluids in the lower completion seem to be fully cleaned-up. All 3 tracers adds value to the interpretation. Extra information on the fluid dynamics of the clean-up process could be indicated.