Deep Panuke Project Description - Encana

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2.3.8.1 Drilling Fluid ProgramWater-based muds (WBM) will be used in development drilling. These muds are used to protect andclean the drill hole, for overbalancing formation pressures, and for bringing cuttings to the surface. Theselection of the drilling fluid is based on factors such as the hole angle, the formation types drilled(mudstone, sandstone, clays, etc.), and the time of exposure.WBM is a suspension of solids and dissolved material in a carrier base fluid of water. WBM tends to beused for wells that are normally pressured or do not encounter difficult geology. Based on theexperience gained while drilling the Deep Panuke delineation wells, it was determined that only WBMwill be used for any new development drilling activities.The typical composition of WBM (seawater gel mud type) for Deep Panuke are as follows:• barite;• bentonite;• potassium chloride (KCl);• polymers;• water;• glycol;• soda ash/sodium bicarbonate/lime;• caustic soda; and• salt (sodium chloride or calcium chloride).During drilling of the new wells, the mud is circulated down the drillpipe from the drilling unit to thebottom of the wellbore and returned to the drilling unit in the annular space (between drill pipe and openhole/casing) carrying the cuttings from the well. Each hole section of a wellbore requires different fluidproperties. Thus after each hole section, the mud is modified or changed out. WBM that is no longerrequired will be disposed of overboard, along with WBM cuttings in accordance with the OffshoreWaste Treatment Guidelines (OWTG) (NEB et al. 2002).For the wells to be re-entered and completed, some drilling is required to remove cement suspensionplugs. This will be done using a viscosified brine solution and so traditional drilling mud will not berequired. Prior to removal of the last suspension plug on the existing wells, the well will be displacedwith filtered completion brine which will act as an overbalanced annulus fluid for setting the productionpacker. Some viscous pills of polymer gelled brine may be used to ensure removal of all solid particlesin the wellbore. The completion fluid will be clear brine with additives for corrosion and oxygeninhibition as well as H 2 S scavengers.Deep Panuke Volume 4 (Environmental Assessment Report)• November 2006 2-28
Once the well completion is set and the production tree is in place, it will be necessary to flow the wellto clean up and remove completion fluids from the reservoir. This operation will be done using a welltest package installed on the drilling rig. In order to flow the well, it is necessary to provide anunderbalance for the well to flow naturally. This underbalance can be achieved in a number of waysbut, in general, involves lowering the density of the completion fluid inside the tubing string. It istypically not recommended to use fresh water to lower fluid density in a gas well as this can lead to theformation of hydrates. Circulating nitrogen into the completion tubing is one alternative to loweringfluid density but tends to be equipment intensive on the drilling rig. Another alternative is to displacesome of the completion fluid in the tubing string with either diesel or glycol or a combination of both.This will likely be the method used for Deep Panuke wells. The underbalanced fluid column, alsoreferred to as the “fluid cushion”, is caught by the well test equipment on the drilling rig and burnedthrough the oil burner on the flare boom. Typically this represents a very small volume of diesel in theorder of 20 to 30 m³.Through the life of the field, workovers will be required in the wellbores. These workovers will requirevarious pieces of equipment to be sent offshore to perform downhole work. Completions brines may beused during these processes. These brines will be composed of water and a salt formulation kept insuspension using a viscosifier (polymer).2.3.9 Hydrostatic TestingThe export pipeline for both M&NP and SOEP Subsea Options and the production and injectionflowlines will be hydrostatically tested. It may be necessary to treat the seawater introduced into thepipeline with corrosion inhibitors and biocides as these chemicals protect the interior surface of thepipeline if the time between the installation of the pipeline and its commissioning into service exceedsthe timeframe allowed for leaving untreated seawater in the pipeline. Leaving untreated seawater in thepipeline for more than one month can establish conditions which permit corrosion to occur at a laterstage in the life of the pipeline. The introduction of treatment chemicals is a safety measure for theprevention of corrosion over the life span of the pipeline.The hydrostatic test plan for the export pipeline is detailed in Table 2.4 and the following paragraphs.For the export pipeline (M&NP Option), the discharge of hydrostatic fluids occurs at the MOPU. Thecooling water pumps, running at 2400 m 3 /hr, will be flowing into the discharge caisson whiledischarging the hydrostatic fluid. This provides a dilution factor as outlined in the table below. There isno dilution for the export pipeline (SOEP Subsea Option) since the release point is at the tie-in location.For the flowlines, hydrostatic fluids may be discharged at the MOPU or at the individual subseawellheads. This will be confirmed during detailed design. Therefore, no dilution for the flowlines isassumed as a worst case scenario.Deep Panuke Volume 4 (Environmental Assessment Report)• November 2006 2-29
Page 1 and 2: 2 PROJECT DESCRIPTIONThis section p
Page 3 and 4: Potential Radioactive Components: T
Page 5 and 6: 2.2.2 Subsea Wells and FlowlinesThe
Page 10 and 11: 2.2.3.1 M&NP OptionThe proposed pip
Page 12 and 13: The onshore portion of the pipeline
Page 14 and 15: 2.3 Construction and Installation2.
Page 16 and 17: 2.3.2 Export PipelineA proposed pip
Page 18 and 19: A dedicated subsea umbilical will b
Page 20 and 21: Table 2.2 Construction MethodsCateg
Page 22 and 23: These subsea structures may be fast
Page 24 and 25: For the new production and injectio
Page 26 and 27: Figure 2.8Typical Production Well S
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 78 and 79:
Use of a dedicated condensate pipel
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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