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«Paper #2-11 SUBSEA DRILLING, WELL OPERATIONS AND COMPLETIONS Prepared by the Offshore Operations Subgroup of the Operations & Environment Task Group ...»

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Discharges of domestic and sanitary waste and food wastes usually are permitted. Sewage wastes are typically treated in a marine sanitation device, as approved by the US Coast Guard, prior to discharge to sea. This treated effluent is regularly monitored to verify treatment is within the permitted limits, such as no floating solids or foam and residual chlorine concentrations of at least 1 mg/L. Food waste discharges are allowed generally beyond 12 miles from land but are required to have no floating solids and generally must be macerated to below 25-mm particle size before discharge. Gray and black water discharges will elevate the oxygen demand in the waters close to the point of discharge but will rapidly disperse in the receiving sea water.

Deck drainage waters discharged from the rig drainage system vary with the amount of rainfall during the drilling program and also with wash-water usage. Rainwater runoff from nonhazardous areas of the rig, such as the living quarters area, is discharged without treatment.

Drain water from areas that might come in contact with oil, such as near the rig floor and mud pit area, is collected and sent to a holding tank and oil separation system. The water is separated before discharge and generally must meet “no free oil” requirements. Separated oil is collected and is either incinerated or sent for disposal or recycling.

Miscellaneous fluids such as desalination unit, blowout preventer, once-through fire water, noncontact cooling water, ballast, bilge, and other fluids comprise the process fluids for offshore drilling. They are generally classified as being either uncontaminated or treated with chemicals.

Uncontaminated fluid discharges are generally allowed as long as they meet “no free oil” limitations. Treated fluid discharges must meet the “no free oil” requirement plus toxicity and other limitations.

C. Air Emissions

The potential generally is low for emissions from offshore exploration and development drilling to cause significant atmospheric impacts. Air emissions are highly regulated by the EPA through an air permitting process for drilling in offshore Federal waters and by the State authorities if drilling is in state waters. Air emission limits are in accordance with the approved permit limitations.

The principal sources of atmospheric emissions considered from routine drilling operations are:

• Emissions from combustion of power-generation equipment on the rig.

• Exhaust emissions from helicopters and marine support vessels and from mobilization and demobilization of the rig.

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• Emissions from well clean up and well testing, if performed.

• Emissions from venting of storage vessels, bulk materials transfer, drilling fluids circulation and water treatment facilities.

• Fugitive emissions from process equipment.

Emissions from power generation on the rig and from support vessels typically are estimated based on predicted diesel fuel consumption during the drilling operation. Emissions from helicopters are derived from the predicted consumption of jet helicopter fuel. Well testing emissions depend on the predicted duration and flow rate of hydrocarbon production, if performed at all. Emissions of all other activities depend more on the types of equipment and products being used and the duration of the drilling program, however those are very minor emissions.

The atmospheric substances of concern from drilling operations are the following:

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The most significant air emissions from drilling operation are from combustion of diesel fuel used for power generation, transportation and well testing. In comparison, air emissions from miscellaneous activities such as venting of storage vessels, bulk materials transfer, drilling fluids circulation water treatment facilities and fugitive emissions from process equipment are considered to be negligible.

Diesel engines used for power generation are the source of the majority of drilling emissions.

This has been recognized by the drilling industry and steps have been taken in recent years to make the diesel engines more energy efficient. To reduce operational emissions, drilling contractors are making improvements in diesel engine efficiency using, for example, diesel injection technology that reduces energy consumption and NOX emissions without reducing engine response or power output (Cadigan and Payton, 2005).

–  –  –

Air emissions from helicopters and marine support vessels depend on the type of equipment being used, distance from operational shore base on land, and the duration of the drilling program.

If well testing is performed, hydrocarbons from the reservoir are flowed to the surface for pressure, temperature and flow-rate measurements to help evaluate well performance characteristics. Well-testing tools are installed in the cased wellbore at the specified zone of interest. During testing, formation fluids are allowed to flow to the surface test facility in a controlled manner. Those fluids may contain hydrocarbons (oil and gas) or formation water.

Flow periods and rates are restricted to the minimum necessary and in accordance with air permit allowances. The hydrocarbons are flared using high-efficiency igniters to ensure relatively complete combustion of hydrocarbons and minimization of emissions. The high-efficiency burners have combustion efficiency ratings of 99%. The short duration of the well test and flaring event and the rapid dispersion of the emissions in the offshore environment indicates that a residual impact should be insignificant.





D. Solid Waste

Non-hazardous solid waste generated on offshore drilling rigs includes general trash and garbage that are categorized, containerized and transported to shore under manifest for proper disposal in regulated landfills. Many companies now segregate at least some solid waste for re-use and recycling. Those efforts range from simply recycling large items like wooden pallets and scrap metal to more extensive efforts to segregate and recycle all waste streams. Hazardous and combustible wastes such as oil, oily rags, spent solvents, paint cans and used oil filters are placed in approved hazardous material containers, sealed, labeled and brought onshore for disposal in an approved hazardous waste handling facility. All drilling operations manage those waste streams in accordance with their Waste Management Plan which details the type of waste generated, the volume and final disposal.

E. Source Reduction, Recycling and Re-Use

For a specific well, drilling source reduction involves reducing the volume of hole which must be excavated to reach a producing formation by drilling smaller diameter hole sizes and by using non-aqueous drilling fluids which minimize wellbore enlargement, dilution volumes and sidetracks and redrills (as compared with water-based fluids). Techniques which can reduce the volume of cuttings generated include closer spacing of successive hole sizes and casing strings, increased casing sizes, expandable casing, increased bit sizes, bi-centered bits, and reamingwhile-drilling, plus use of casing-while-drilling technologies.

NAFs generate less liquid drilling waste than WBFs because they tolerate higher contents of drill solids and because “shale drill” (silt- and clay-rich) solids do not degrade as readily so that a high solids-removal efficiency is realized (EPA, 1999; Veil et al., 1995). Water-based drilling fluids generally require dilution volumes of 5 to 10 times the hole volume excavated whereas NAFs generally require 1 to 3 times the hole volume. Other rigsite methods are used to reduce the amount of liquid waste that must be discarded, including use of pipe wipers, mud buckets, and vacuuming of spills on the rig floor. Those techniques allow clean mud to be returned to the

–  –  –

mud system and not treated as waste. Other efforts, such as additional solids-control equipment to provide improved solids removal efficiency, are widely used depending on the economics and logistics of a given operation. Solids-control equipment, like centrifuges, can be used to remove solids from the recirculating mud stream. Although such a process does generate some solid waste, it avoids the need to discard large volumes of solids-laden muds. Waste from drilling fluids products also can be reduced through the use of products in bulk supplies rather than as sacked or drummed quantities.

The recycling and re-use of drilling fluids depends on many factors including type of formation being drilled, what hole volume has been excavated, type and capacity of the solids control equipment, drill solids content of the drilling fluid at the end of the operation, type of drilling fluid being used, and overall drilling operation. While water-based fluids are generally not recyclable from well to well, certain drilling operations during field development, such as batch drilling, can make them more reusable and reduce waste volumes. NAFs are much more recyclable and re-usable than WBFs and generally can be processed through centrifuges to remove solids then diluted and treated for continual re-use.

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BENEFITS AND OPPORTUNITIES WITH SUB-SEA COMPLETIONS

A. Environmental and Economic Benefits Subsea completions offer environmental benefits that accrue during the development of the resource (less time over the hole, fewer resources used, less capital equipment requiring resources to develop the field, etc.) as well as continuing availability during the production and eventual disposal of the production equipment (platforms, manifolds, etc.).

Subsea completions have an economic advantage compared to other field development alternatives such as bottom-founded structures (platforms, etc.). This advantage increases with increasing water depth and, in some cases; bottom-founded structures are not possible due to the sheer size potentially required for such a structure. At present, the maximum water depth for a fixed platform is 1,353 ft. (Shell’s Bullwinkle platform) and 1,754 ft for a compliant tower (ChevronTexaco’s Petronius). In one example, the cost of a bottom-founded structure was compared to a Floating Production, Storage, and Offloading (FPSO) facility. The FPSO cost was approximately one-half of the cost of a bottom-founded structure ($71MM). Similarly, operating costs of FPSO were $250,000/mo compared to satellite subsea trees of $25,000/mo.

During well construction and installation of the subsea completion, rig costs are paramount.

Currently, daily costs run from $500,000 to upwards of $1MM per day. Operators anxious to improve the profitability of an endeavor take every opportunity to reduce time over the well and reward contractors who significantly reduce their well construction/completion times. This includes reducing the number of trips (downhole insertions) to install completions as well as reducing non-productive time from excessive trips. Specific bottom-hole completion methodologies have evolved to minimize the number of trips to complete the well. This includes both methods of setting packers as well as single-trip multiple zone sand control completion methodologies.

As subsea completions are required in deepwater operations, it is useful to review the potential for deepwater operations in areas like the Gulf of Mexico. In a report published by the MMS (now BOEMRE), French et al.

(2006) stated the following:

“Approximately 350,000 barrels of oil and 1.7 billion cubic feet of gas come from deepwater subsea completions each day. Subsea completions currently account for about 34 percent of deepwater oil production and about 50 percent of deepwater gas production. Figure 62a shows that very little deepwater oil production came from subsea completions until mid-1995, but by the fall of 1996 that production had risen to about 20 percent. Since 2000, subsea oil production has increased slightly, whereas total deepwater oil production has increased dramatically. Deepwater gas production from subsea completions began in early 1993, and by mid-1994 it accounted for over 40 percent of deepwater GOM gas production (Figure 62b). Gas production from subsea completions increased from 1996 through 1999, remained constant in 2000, and increased rapidly after 2000.” Figure 9 reproduces key charts cited by French et al. (2006) that demonstrate how rapidly increasing hydrocarbon production was correlated with expanded use of subsea completions.

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The true success of a subsea completion lies in its ability to continue to produce over time. Any interruption of the production stream (particularly from deepwater, high-producing wells) can quickly affect the economic performance of a project. Fortunately, subsea completions are relatively trouble-free after the initial installation. Although a single database of all subsea completion equipment failures is not available, a survey by Hammett and Luke (1986) found an overall reliability of active subsea completions to be 80% from 1960 to 1984. When failures did occur, they were primarily due to downhole components.

The barriers and opportunities for subsea completions fall into five categories: regulatory controls, safety management, economic advantages, technological aspects, and environmental issues.

Regulatory Controls. Regulatory controls for subsea wells and completions in the United States are managed by BOEMRE as directed by the Secretary of the Interior. Those controls are stated in the Code of Federal Regulations (CFR) under Title 30, Parts 200-299. The primary part regulating operations in the Outer Continental Shelf (OCS) is 30CFR250 (Code of Federal Regulations, 2011a).



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