Deep Panuke Project Description - Encana

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Use of a dedicated condensate pipeline to shore would necessitate the construction of onshorecondensate handling facilities such as storage tanks which would result in substantial capital costs. Thepipeline would have to be buried over its entire length (not easily accomplished over rocky areas) tomeet regulatory requirements and to protect it from possible damage from mobile fishing gear. Inaddition, the condensate pipeline would not be protected from clam dredges unless deeply buried. Thepotential environmental effects associated with rupture of such a condensate pipeline would also be aconcern. The quantities of condensate to be produced from the Deep Panuke field do not justify thecosts associated with a dedicated condensate pipeline. Thus, a dedicated condensate pipeline to shorewas deemed not economically feasible and was therefore rejected.The use of condensate as the primary fuel on the MOPU was also considered. Using condensate as fueleliminates the substantial capital and operating costs associated with a condensate pipeline to shore andassociated onshore handling facilities. The use of condensate as fuel on the platform conserves theresource by maximizing the quantity of natural gas exported to shore and by utilizing all components ofthe Deep Panuke resource.A seafloor subsea storage tank for holding a six-month volume of condensate offshore was alsoconsidered. While subsea storage tanks have been used at other offshore facilities, there is a high risk forpotential seafloor scour due to the relatively shallow water at the Deep Panuke site. That wouldnecessitate large quantities of rock protection around the tank. The prohibitive costs of such aninstallation resulted in this option being considered not economically feasible.2.10.2.10 Production Capacity AlternativesThe 2002 Project basis for production capacity was 11.3 x 10 6 m 3 /d [400 MMscfd]; however,alternatives for smaller facilities with peak production capacities of 8.5 x 10 6 m 3 /d [300 MMscfd] and5.7 x 10 6 m 3 /d [200 MMscfd] were also considered. Concepts were initially developed for jacketsupportedstructures for each alternative. It was found that the platform footprint, weight, and costreduced considerably when the production capacity was reduced from 11.3 x 10 6 m 3 /d [400 MMscfd] to8.5 x 10 6 m 3 /d [300 MMscfd]. However, the reduction in topsides weight (and cost) when theproduction capacity was further reduced to 5.7 x 10 6 m 3 /d [200 MMscfd] is marginal since the size ofprocessing equipment does not decrease in the same proportion as production capacity. The economicmodelling case at the 5.7 x 10 6 m 3 /d [200 MMscfd] production rates showed that the payout period wastoo lengthy at this rate, severely impacting the economics. It was concluded that the 8.5 x 10 6 m 3 /d [300MMscfd] plant size is more economically feasible for the Mean reservoir case and therefore wasselected for the plant production capacity rating.Deep Panuke Volume 4 (Environmental Assessment Report) · November 2006 2-78
2.10.2.11 Export Pipeline AlternativesThere are two alternatives for the export pipeline. EnCana proposes to transport product for sale via asubsea pipeline from the offshore processing facility to one of two delivery points:· Goldboro, Nova Scotia (M&NP Option); or· SOEP 660 mm [26 inch] pipeline tie-in (SOEP Subsea Option).Both export pipeline alternatives are technically feasible and routes have been chosen to minimizeenvironmental impact. The selected alternative will be determined pending the outcome of commercialdiscussions between the operator of SOEP, ExxonMobil, and EnCana.2.10.2.12 Subsea Tie-back AlternativesThe Deep Panuke reservoir areal extent has changed substantially from the 2002 Project basis of onelicense, PL2902, to the current Project basis covering PL2902, EL2387, SDL2255H, PL2901 andEL2360. The pool size estimate requires a minimum of five production wells for the P90 case (value at90 th Percentile) and a maximum of eight production wells for the P10 case (value at 10 th Percentile) toeffectively deplete the resources. The large extent of the pool necessitates the use of a subsea solution.The Project plans to utilize four suspended wells from the exploration drilling program as productionwells which allows for reduced capital costs and environmental interactions. One new production wellwill be drilled for the Project start-up. Up to three additional production wells could be drilled in future.A subsea tie-back study was carried out to determine the optimal method of tying in the wells to thefield centre. It should be noted that a new acid gas injection well must also be tied back to the fieldcentre; however, the geology in the area allows numerous options for the location of this well so thiswas not considered as a driver for the lay-out study.From a layout consideration, it was determined that a tie-back of individual wells to the field centre wasthe best technical solution. The proposed well locations do not suit a template or manifold arrangement.The field centre location was determined by minimizing the tie-back lengths of the wells to lower capitalcosts and improve flow assurance.Three alternative methods for flowline installation were considered: 1) “S-lay” barge method; 2) “reellay” technique; and 3) flexible flowline method. The “S-lay” lay barge method involves the use of anoffshore barge to weld and then lay lengths of rigid pipe on the seabed by means of a “stinger”overhanging the stern of the barge. Subsequently, the pipe is trenched using a subsea trenching orploughing spread. The “reel lay” method involves pre-welding rigid pipe lengths together at aspecialized “spool base” onshore and then reeling the entire flowline onto a large diameter reel. The reelDeep Panuke Volume 4 (Environmental Assessment Report) · November 2006 2-79
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2 PROJECT DESCRIPTIONThis section p
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Potential Radioactive Components: T
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2.2.2 Subsea Wells and FlowlinesThe
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2.2.3.1 M&NP OptionThe proposed pip
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The onshore portion of the pipeline
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2.3 Construction and Installation2.
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2.3.2 Export PipelineA proposed pip
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A dedicated subsea umbilical will b
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Table 2.2 Construction MethodsCateg
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These subsea structures may be fast
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For the new production and injectio
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Figure 2.8Typical Production Well S
Page 28 and 29: 2.3.8.1 Drilling Fluid ProgramWater
Page 30 and 31: Table 2.4 Hydrostatic Fluid Dischar
Page 32 and 33: Acid GasInjectionFeed GasCompressio
Page 34 and 35: Although the M&NP Option is the onl
Page 36 and 37: Spent TEG has no measurable H 2 S a
Page 38 and 39: Table 2.7 Water CompositionComponen
Page 40 and 41: 2.4.2 Utilities2.4.2.1 Electrical P
Page 42 and 43: will be designed considering emerge
Page 44 and 45: zones over the pipeline although th
Page 46 and 47: 2.7 Emissions and DischargesEnCana
Page 48 and 49: Table 2.8 Routine Project Emissions
Page 50 and 51: 2.7.1.1 Air PollutantsThe following
Page 52 and 53: esult in eye irritation, respirator
Page 54 and 55: Typically, a re-entry and completio
Page 56 and 57: 2.7.5.3 Deck DrainageDuring constru
Page 58 and 59: 2.9.2 Pipeline Leak PreventionThe p
Page 60 and 61: 2.9.5 Subsea Protection StructuresT
Page 62 and 63: • consider concept alternatives f
Page 64 and 65: Table 2.10Centre Substructure Type
Page 66 and 67: is much more weather-dependent than
Page 68 and 69: Table 2.11 Processing Location Alte
Page 70 and 71: After carefully considering the con
Page 72 and 73: Flaring acid gas consists of direct
Page 74 and 75: Table 2.13Produced Water Disposal A
Page 76 and 77: Therefore, injection into an annula
Page 80 and 81: is taken offshore on a special lay
Page 82: Table 2.15Acid Gas Injection Locati
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Deep Panuke Project Description - Encana

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