An iceberg is a body of floating ice that has broken away from a glacier and thus distinct from sea ice which is formed in the ocean. When water freezes, the molecules form hexagonal structures which form stacks of crystals with a lot of empty space, allowing ice to float (Olovsson 2018). When sea ice forms, most of its salt content is ejected, and so sea ice is mostly freshwater. Multi-year sea ice is usually less saline than first year sea ice and is usually suitable to melt and drink.
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Water has a very unusual property in its solid state. The density of distilled water at 20 °C is 0.9982 g/cm3. As water cools down, the density increases and reaches a peak at 4 °C, but then upon further cooling, the density declines again until it freezes at 0 °C. Ice has a density of 0.915 g/cm3, significantly less dense than water whereas for almost all other substances their solid form is denser and thus sinks in their liquid state.
Seawater is slightly more dense than freshwater because of the dissolved salts it contains. The salinity of seawater is typically 35 parts per thousand ppt (3.5 wt%) by mass, and at 20 °C its density is 1.0248 g/cm3. At 40 ppt and 20 °C, the density is 1.0286 g/cm3. Seawater freezes at a temperature depending on salinity level but usually starts around − 1.8 °C. Since most salt is ejected during freezing, it has a density like freshwater, 0.915 g/cm3, and floats on top of seawater.
Icebergs are calved off as glaciers discharge into the sea, and as they melt, they assume dramatic shapes with pinnacles and saddles formed by melting and wind action. Most calving occurs during the summer months when temperatures are highest, and icebergs usually take between one and three years to reach Newfoundland waters in an area known as Iceberg Alley. About 10,000 or so icebergs are calved off glaciers in the Arctic each year, most along the western coast of Greenland, but these levels are expected to increase with climate change (Truillo and Thurman 2014). Ocean currents driven by strong winds carry the icebergs south along the east coast of Newfoundland and as far south as Philadelphia, Pennsylvania (40° N). Once detected, icebergs are monitored and managed before they pose a threat to operations in the region.
About 85% of icebergs crossing the Grand Banks originate from the tidewater glaciers of West Greenland, with the remainder calving from East Greenland glaciers, Baffin Bay and Ellesmere Islands. About 90% of the mass of an icebergFootnote 25 lies below water and, in shallow water depth (< 100 m), has the potential of contacting the seabed and poses an impact risk to subsea facilities (Fig. 34). Icebergs with a draft less than water depth are a collision hazard to surface structures, vessels, mooring lines, and production risers. In deepwater areas, iceberg scour of the seabed is not a concern because the water depth will greatly exceed the deepest draft iceberg.
Figure 34Source: C-CORE
Subsea equipment needs to be buried to avoid ice keel.
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The number and size of icebergs vary widely from year to year. Sizes range from tens of tonnes to several million tonnes, and the mean number of icebergs that enter a 1° square (~ 60 nm per side) near the platforms on the Grand Banks ranges from 40 to 400 per year. Without active management, this translates into about one iceberg impact per structure every 10 years! The paths of icebergs are usually very erratic driven by a combination of wind, current, and wave drift force, and so even if an iceberg appears to sail by it may circle back and create an impact threat. The drift speed of icebergs usually ranges from 0.3 to 1 m/s.
On Nansen’s famous North Polar ExpeditionFootnote 26 of 1893–1896, a curious observation on the movement of icebergs relative to wind direction led to a fundamental discovery by his crew mate and student W. Ekman, which later became known as Ekman transport.
Nansen noticed that icebergs drifted in a direction at an angle to the direction the wind was blowing. Ekman considered the problem in his thesis and found that the average movement of the whole water column is actually perpendicular to the wind direction (90° to the right-hand side in the northern hemisphere), and the direction taken by an iceberg depends on how deep the iceberg extends below the surface. Shallow keels will move in the general direction of the wind; deep keels will move at a greater angle to the wind.
Detection, classification, and tracking are the primary components of ice management systems (Randell et al. 2009). Once a threat has been identified,Footnote 27 active physical management is executed. The two primary methods for deflection include towing and water cannon blasting. Towing is the most common practice with success rates reported as high as 85%. On medium-size icebergs, defined as having a 60–120 m waterline length, towing uses a single towline or an iceberg net. For larger icebergs in higher seas, dual-vessel towing may be employed. For smaller icebergs (known as growlers or bergy bits) and shorter distances, vessels equipped with water cannons spray seawater at the base of the iceberg, which can break the iceberg or change its direction. Prop wash refers to when a vessel backs up close to an iceberg and the wash from the propellers creates a localized current, thrusting the berg along a different course.
Platform support vessels collect information on ocean current and move alongside the iceberg to measure its draft, shape, and mass (Fig. 35). Stability analysis is performed, since whenever icebergs center of gravity and buoyancy shift, they can roll over and create safety hazards for towing operations. Using mathematical modeling techniques, combined with wind and wave forecasts and other physical and environmental information, iceberg movements are predicted and those which may drift close to the production area are identified. Icebergs that are identified to require intervention are approached while they are 20 km or more away from the platform.
Figure 35Source: Oceans Ltd
Iceberg profile and properties calculated from three-dimensional shape measurements.
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For facilities that are designed to disconnect and relocate to avoid interaction with icebergs (e.g., FPSOs and MODUs), management zones are defined (Fig. 36). Zone size is dynamic and determined by iceberg drift and T-time, the time required to suspend operations, secure the well, and shut in production. For operations to be safe, the T-time must be greater than the time for the iceberg to reach the facility. If the Alert Zone shrinks to the size of the Exclusion Zone, the facility is down-manned and wells secured. Iceberg towing is carried out in the control zone to prevent icebergs from breachingFootnote 28 the Alert Zone.
Figure 36Source: C-NLOPB, C-CORE
Schematic of ice management zones and T-time illustration.
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Depth vs. time and depth vs. cost plots represent a graphical summary of the time and cost of the drilling and completion process through the progression of the measured depth of the well. Depth–time plots are often used for drilling the well, and completion operations may or may not be included in the plot. It is usually not obvious what time and cost categories are included without a review of accompanying documents (e.g., total well cost in drilling operations will only include drilling cost).
Before a well can be drilled, engineers design the well on paper and specify all the required parameters involved in the process, such as casing dimensions and type, and drilling mud regime, for every stage of the process to target depth (Mitchell and Miska 2011). An Authorization for Expenditure (AFE) is required before activities commence. The operator generates an expected (P50) depth–time plot, and a best-in-class plot may also be included.
The depth–time plot appears as a downward staircase as the well is drilled deeper and further away from its spud point. The measured depth is plotted along the y-axis with increasing values going down the axis. Measured depth represents the amount of borehole drilled along the wellbore. Flat portions of the plot arise when there is no new wellbore constructed, which will occur when tripping,Footnote 29 installing and cementing casing, coring, weather delays, etc. The well-on-paper depth–time plot and AFE are based on the expected drilling requirements and well casing program, and the benches reflect the trips planned to change drill bits and related construction activities.
Operations are expected to follow the curve, but in practice wind up ahead or behind schedule. Unplanned events (e.g., weather, ice events, equipment failure) will cause deviation from the expected curve, and sometimes significantly. If the changes are significant, one or more supplemental plots and AFEs may be required, and these are often plotted on the original curve. Supplemental AFEs are usually required if the occurrence of an unplanned event increases cost by 10% or more of the planned cost.
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When the target is reached, the depth–time and cost–time plots bottom out and stay flat since no new wellbore is being drilled, but both time and cost continue to increase and extend the lines along the x-axis. Flat time along the bottom of the depth–time plot is usually longer than other steps down the stairs since during this time the well is getting ready to be handed over to completions or completions operations are included in the plot. Completion activities may occur immediately after the well has been drilled or the well may be suspended and completed later. Both are common and the type of well and rig schedule determine if separate or continuing operations are performed. Not all the bottom flat time is due to completion activities, but for many wells if completion activities are included in the plot, a significant portion of this bench will be due to completion activities.
When drilling out a section of a well, instability may occur and if cannot be brought under control, the section will be abandoned and plugged back, and a sidetrack will be drilled from higher up in the well, causing the depth–time and cost–time plots to depart from its downward progression and abruptly rise to the depth where the sidetrack kicks off before following the staircase pattern again. Any rise in the plots indicates bypasses or sidetracks which may be planned or unplanned. Exploration wells often have planned sidetracks to test different targets, but in development wells sidetracks are often performed because of problems in drilling or accessing a productive reservoir (e.g., the reservoir may be cemented and a new horizon has to be found).
White Rose E-18 7 Water Injector Well.
The time vs. depth curve for Husky Oil’s White Rose E-18 7 horizontal water injector well is depicted in Figure 37. The well was spud on December 10, 2006, reached total depth on February 12, 2007, and the GSF Grand Banks was released on March 2, 2007. The well took about 84 days to drill and cost about $35.5 million before the well was suspended and completed later (Fig. 38). Well completion was finished on May 8, 2007, at a cost of $11.9 million.
Figure 37Source: Husky Oil
Water injector well E-18 7 in the White Rose Ben Nevis/Avalon formation (red curve) took 84 days before the well was suspended for completion.
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Figure 38Source: Husky Oil
Water injector well E-18 7 in the White Rose Ben Nevis/Avalon formation cost about $35.5 million before handed over to completions.
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Terra Nova L-98 9 Producer Well.
Petro-Canada’s Terra Nova L-98 9 well was spud on March 4, 2004, reached total depth of 3740 m on April 8, and was completed on April 29 at a total cost of $33.9 million (Fig. 39). The AFE budget is shown in red with the actual drilling cost shown in blue. Completion cost was a small part of the well’s total cost.
Figure 39Source: Petro-Canada
Drilling and budgeted cost for producer well L-98 9 in the Terra Nova development.
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The main function of an oil production facility is to stabilize the produced crude by separating the water and gas from the oil streams, the oil and water from the gas streams, and the oil and gas from the water streams, and then treating each output to satisfy transport and injection specifications, and offshore disposal requirements. For example, crude for shuttle transport is often required to meet the specifications for vapor pressure of 75.8 kPa at 50 C and BS&W < 0.5 vol%.
Water that is produced with petroleum is referred to as produced water. Most offshore platforms dispose of produced water directly into the ocean but must meet stringent regulations on the entrained and dissolved oil and other chemicals in the produced water. In Arctic regions (Beaufort and Barents Sea) and environmentally sensitive regions (e.g., Garden Banks in the US Gulf of Mexico), no discharge rules apply. The wide variation in the concentration and type of constituents sometimes make produced water challenging to treat and discharge.
The physical and chemical properties of produced water depend upon the location of the field, the geologic formation, and the type of hydrocarbon produced (Veil and Clark 2011). The major constituents of concern are salt content (expressed as salinity, conductivity, or total dissolved solids), oil and grease (organic compounds captured through an n-hexane extraction procedure), inorganic and organic compounds introduced as chemical additives to improve drilling and production operations, and naturally occurring radioactive material.
Changes in produced water due to pressure and temperature changes from production can impact precipitation of scales and corrosion which may lead to leaks and costly repairs if not inhibited and monitored. Inhibition of most scales is through application of organic compounds which act to poison (prevent) the growth sites of the crystals. Corrosion mitigation typically takes investment in corrosion-resistant alloys and/or a chemical corrosion–inhibition/monitoring program.
Water may be injected into oil reservoirs to supplement oil recovery, and in each of the producing fields offshore Newfoundland, water is injected into one or more formations. Water injection is commonly used in reservoirs with aquifer support to improve oil recovery and to maintain reservoir pressure to avoid compaction. Seawater will generally require treatment and the type of treatment and cost depends on the source and issues identified. If operators inject water into reservoirs to maintain pressure, they typically use seawater with some chemicals since this is the lowest cost option. In some cases, subsurface water may be processed if seawater causes injection problems. To inject produced water,Footnote 30 suspended solids and oil must be removed to an appropriate degree to avoid plugging and fouling the reservoir, and this is usually only pursued if produced water disposal is prohibited.
The operational requirements for seawater injection generally require filtration, deoxygenation, and corrosion control. The details of the treatment steps are specific to each project. For example, some projects may require injected water to be filtered to 1 µm, while other systems may require 10 µm. Deoxygenation in some systems may be achieved by chemical addition; other systems may require gas stripping and chemical treatment. Each process will have its own capital and operating cost requirement.
Seawater that has been filtered, deaerated, and treated to control oxygen levels and bacteria is metered and injected into one or more oil zones of specially drilled water injection wells. The volume of injected seawater is usually about the same quantity as the volume of crude and produced water extracted to match voidance replacement.
Gas can be injected into reservoirs to supplement recovery by maintaining reservoir pressure or as a means of disposing of gas which cannot be flared or used. Surplus gas in each of the Grand Banks fields is compressed and reinjected back into reservoirs. Generally, there is no need to control hydrocarbon dew point as in export gas since injected gas after compression will get hotter not cooler, but it may be attractive to remove heavy hydrocarbons for economic reasons. Dehydration is required to avoid water dropout and corrosion problems. A topsides dehydration unit dries the produced gas to a water content of about 1 lb/MMcf to eliminate the potential for hydrate formation. In water injection regions, gas flood is balanced with water volumes for optimum pressure management.
Gas lift is a common method of artificial lift which uses high-pressured gas to lift well fluids. Natural gas injected in the production tubing within the wellbore reduces the density of fluids, which acts to lower the flowing bottom hole pressure, which increases flow from the reservoir to wellbore. Gas lift is easy to install, robust, and effective over a broad range of producing conditions and assumes the availability of a continuous supply of lift gas. All the producing fields offshore Newfoundland apply gas lift in operations, some more than others (recall Table 3). Gas injection into a reservoir requires a gas injection well, whereas gas lift transports gas from the topsides to the wellbore, through tubing where it helps lift the crude out of the hole, and after topsides separation is then recirculated in a closed-loop system.
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