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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 18โณ 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 8.5โณ hole diameter, made possible by using 8โณ 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 Sรธr (South) was discovered by well 6407/1โ2 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 Sรธr 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.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Norway > Norwegian Sea > Ile Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Bank Area > Block 6407/1 > Tyrihans Field > Ile Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Bank Area > Block 6407/1 > Tyrihans Field > Garn Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Information Technology > Modeling & Simulation (0.88)
- Information Technology > Communications (0.69)
Abstract Field rejuvenation is a continuous effort within PETRONAS Carigali Sdn Bhd. This paper describes the effort taken to add value on the Temana field located in offshore Malaysia (Figure 1). In the development of the Temana Saddle Area within the Temana brown field, a multidisciplinary team was established with the objective to identify the opportunities and implementing the development in a timely and cost effective manner. The Temana Development Project Team applied PETRONAS Carigali Life of Field (LoF) workflow as the main guidelines on the reviewing and assessing the resource potential and evaluating the options on resources development strategy as well as surface facilities optimization. Temana field is complex with numerous fault blocks and reservoirs (Figure 2). The seven unmanned ageing offshore structures strategically located around the field offered another unique set of challenges to the team. This paper also covers the process of abandonment the non-productive well to re-utilize to access other drainage location with technology applied. Introduction Temana field is located in the Balingian geological province, some 30 kilometer offshore Bintulu, Sarawak. It has 7 existing platforms (as shown in Figure 3) with two additional production processing facilities platforms. Temana Saddle, which is located in the Central area, Block 54/99, has almost the same distance between the closest existing structures TEJT-T and TEJT-C. The main objective of Temana Saddle development is to develop some prospective resources from recent appraisal well discovery, TE-72 by optimizing the existing asset such as platform slot, idle well and other production facilities. Based on detail reservoir simulation study, the optimum production rate is expected about 6,000 stb/d from 3 infill development wells. From drilling point of view, the development of Temana Saddle could be carried out either from TEJT-T or TEJT-C platforms. However, considering the availability of empty slot and idle well in TEJT-T as compared to TEJT-C where all slots are currently utilized, the team proposed to focus their study on optimizing the TEJT-T. In order to maximize the drainage locations, optimize the drilling operation and engineering data gathering of Temana Saddle development, the sub-surface team recommended for the first two wells to utilize the available one spare slot by adapting the twin well technology; and the third location may require abandonment of one well due to the slot unavailability. The main reservoir target in Temana Saddle is the 54-I65 sand, nevertheless, the 54-I20 sand has also been identified as the upside potential for this development. Both reservoirs are expected to be in virgin conditions since pressure data taken in the appraisal well indicating initial reservoir condition with no communication with existing reservoirs in Temana field. The reservoir pressure is estimated above 1500 psia. Since data and information at this area is very limited, a 3D Static and Dynamic 54-I65 reservoir models was developed to address the remaining uncertainty involved such as hydrocarbon contact, reservoir quality, drive mechanism and its impact in formulating the optimum development strategy and potential recovery. From drilling perspective, the main challenge in developing Temana Saddle area is drilling the high angle wells whereby deviation angles reached to maximum 75ยฐ. This problem is due to the shallow reservoir target that is about 3000 TVD SS in the Temana Saddle area as well as about 2 kilometer away from TEJT-T.
- Geology > Structural Geology > Fault (0.48)
- Geology > Geological Subdiscipline > Stratigraphy (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.55)
- South America > Peru > Talara Basin (0.99)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Balingian Province > Block SK305 > Temana Field (0.99)
Abstract Ten years since production commenced from the Lennox Field and one year from the start of full gas cap blowdown, the challenge to produce oil from the Lennox oil rim has never been greater. The Lennox Field is one of six fields comprising the Liverpool Bay Development located in the UKCS, East Irish Sea. The Lennox oil rim is at a critical stage in the development of the asset as it transitions from an oil field to a gas field. The field was initially developed with horizontal and multi-lateral wells placed to maximise oil reserves and minimise movement of the gas-oil and oil-water contacts with re-injection of all produced gas to maintain reservoir pressure. Since other sources of gas in the area commenced their decline, Lennox must now sustain plateau nominated gas sales and as a result there is little time left to recover the remaining oil. In a first for the development, a dual lateral well (110/15a-L13/L13z) was drilled in mid 2005 as a sidetrack to a poorly performing single bore well and completed with an intelligent completion to supply gas lift gas from the gas cap. The intelligent completion will assist the well to flow, maximise oil recovery and eventually allow a simple conversion to a gas well. The well was a success with better than expected reservoir intersections and the initial oil rate exceeding predictions. The project, initially designed to address unswept oil in the Lennox Field, was expanded to apply the artificial lift technology used at L13 to mature Lennox wells to allow continuous lift at higher watercuts and lower reservoir pressure. The result has highlighted the need to continually re-evaluate opportunities and challenge existing development plans and assumptions. Introduction The Lennox Field is located in UK blocks 110/14a and 110/15a, in the East Irish Sea and is one of six oil and gas fields that comprise the Liverpool Bay Development (Figure 1). Lennox differs from the other fields in that it contains hydrocarbons in both an oil rim and gas cap. The Lennox gas is ultimately required to fulfill the gas sales contract, once the other gas fields in the development can no longer supply all the contracted gas demands, but in the meantime Lennox production has been focused on maximising production from a 45m thick oil rim, which provided plateau oil production rates of 40,000 stb/d.
- North America > United States > Texas (1.00)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (1.00)
- Geology > Sedimentary Geology (0.69)
- Geology > Rock Type > Sedimentary Rock (0.47)
- Geology > Geological Subdiscipline > Stratigraphy (0.46)
- Europe > United Kingdom > Irish Sea > East Irish Sea > East Irish Sea Basin > Ormskirk Sandstone Formation (0.99)
- Europe > United Kingdom > Irish Sea > East Irish Sea > East Irish Sea Basin > Liverpool Bay > Block 110/15 > Lennox Field (0.99)
- Europe > United Kingdom > Irish Sea > East Irish Sea > East Irish Sea Basin > Liverpool Bay > Block 110/14 > Lennox Field (0.99)
- (8 more...)