Drilling Fluids and Drilled Cuttings With HSE

In oil field production system, the oil and gas processing stations are important hazard areas. In the transformation progresses a multitude of safety problems occur frequently each year, which cause personal injury accidents and lead to psychology shadow to each employee. That also exposes existing problems in oil and gas construction areas over the years. In order to better improve the HSE management level and reduce accidents as well as personnel damages, the HSE management level must be constantly improved in construction site.

The primary functions of drilling fluids used in oil and gas field operations include removal of drilled cuttings (rock chippings) from the wellbore and control of formation pressures. Other important functions include sealing permeable formations, maintaining wellbore stability, cooling and lubricating the drill bit, and transmitting hydraulic energy to the drilling tools and bit. Drilled cuttings removed from the wellbore and spent drilling fluids are typically the largest waste streams, by volume and weight, generated during oil and gas drilling activities.

Though various drilling fluids are available, they can generally be categorized into the following:

  • Water-based drilling fluids (WBDF): Fluids for which the continuous phase and suspending medium for solids is seawater or a water-miscible fluid. There are many WBDF variations, including gel, salt-polymer, salt-glycol, and salt-silicate fluids.
  • Non-Aqueous Drilling Fluids (NADF): The continuous phase and suspending medium for solids is a water-immiscible fluid that is oil based, enhanced mineral oil based, or synthetic based.

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The selection of a drilling fluid should be made after evaluating its technical suitability and environmental impact. The use of fluids that contain diesel as the principal component of the drilling mud liquid phase is not good practice for offshore drilling programs and should be avoided.

Typically, barite (barium sulfate) is the solid medium used to increase the specific density of most drilling fluids, with bentonite clays also used as a viscosifier. Drilling fluids can also contain a variety of other components to enhance their performance and/or to address reservoir compatibility requirements.

Drilling fluids are (i) circulated downhole with direct loss to the seabed, along with displaced cuttings, particularly while drilling well sections nearest to the surface of the seabed, or (ii) recovered for reuse when returned to the drilling rig via casing or marine riser and routed to a solids removal system. The
direct loss system is to be considered an interim solution for the first drilling phase and applied only when the chemical content is low and water-based drilling mud is used.

In the solids removal system, the drilling fluids are separated from the cuttings so that they may be recirculated downhole, leaving the cuttings behind for disposal. The volume of cuttings produced will depend on the depth of the well and the diameter of the hole sections drilled. The cuttings contain residual drilling fluid.

The drilling fluid rheological properties and density are adjusted during drilling via solid control systems; the fluid is eventually replaced (i) when its rheological properties or density can no longer be maintained or (ii) at the end of the drilling program. These spent fluids are then contained for reuse or disposal. Disposal of spent NADF by discharge to the sea must be avoided. Instead, NADF should be transferred to shore for recycling or treatment and disposal.

Feasible alternatives for the disposal of spent WBDF and drilled cuttings from well sections drilled with either WBDF or NADF should be evaluated. Options include injection into a dedicated disposal well offshore, injection into the annular space of a well, and containment and transfer to shore for treatment
and disposal. When no alternative options are available, residual WBDF might be discharged to sea at the end of a drilling program, provided that the overall ESIA conducted for the site has considered this scenario, demonstrating the environmental acceptability of this practice.

When discharge to sea is the only alternative, a drilled cuttings and fluid disposal plan should be prepared, taking into account cuttings and fluid dispersion, chemical use, environmental risk, and necessary monitoring. Discharge of cuttings to sea from wells drilled with NADF should be avoided. If discharge is necessary, cuttings should be treated before discharge to meet the guidelines provided in table 1

TABLE 1. EFFLUENT LEVELS FROM OFFSHORE OIL AND GAS DEVELOPMENT
PARAMETER GUIDELINE
Drilling Fluids and Cuttings – NADF
  • NADF: Reinject or ship-to-shore, no discharge to sea
  • Drilled cuttings: Reinject or ship-to-shore, no discharge to sea except:
    1. Facilities located beyond 3 miles (4.8 km) from shore;
    2. For new facilities:a Organic Phase Drilling Fluidb concentration lower than 1% by weight on dry cuttings;
    3. For existing facilitiesc: Use of Group III non-aqueous base fluids and treatment in cutting dryers. Maximum residual Non Aqueous Phase Drilling Fluidd (NAF) 6.9% (C16 -C18 internal olefins) or 9.4% (C12-C14 ester or C8 esters) on wet cuttings;
    4. Hg: max 1 mg/kg dry weight in stock barite
    5. Cd: max 3 mg/kg dry weight in stock barite
    6. Discharge via a caisson (at least 15 m below surface is recommended whenever applicable; in any case, a good dispersion of the solids on the seabed should be demonstrated)
Drilling Fluids and Cuttings – WBDF
    • WBDF: Reinject or ship-to-shore, no discharge to sea except:
      1. • In compliance with 96 hr. LC-50 of Suspended Particulate Phase (SPP)-3% vol. toxicity test first for drilling fluids or alternatively testing based on standard toxicity assessment speciese (preferably site-specific species)
    • WBDF cuttings: Reinject or ship-to-shore, no discharge to sea except:
      • Facilities located beyond 3 miles (4.8 km) from shore;
      • Hg: 1 mg/kg dry weight in stock barite
      • Cd: 3 mg/kg dry weight in stock barite
      •  Maximum chloride concentration must be less than four times the ambient concentration of fresh or brackish receiving water
      • Discharge via a caisson (at least 15 m below sea surface is recommended whenever applicable; in any case, a good dispersion of the solids on the seabed should be demonstrated)
Produced Water Reinject. Discharge to sea is allowed if oil and grease content does not exceed 42 mg/l daily maximum; 29 mg/L monthly average
Flow-Back Water Reinject or reuse. Discharge to sea is allowed if oil and grease content does not exceed 42 mg/L daily maximum; 29 mg/L monthly average. An environmental risk assessment to determine the maximum site-specific allowable concentrations should be conducted for all other chemicals
Completion and Well Work-Over Fluids Ship-to-shore or reinject. No discharge to sea except:

  • • Oil and grease content does not exceed 42 mg/L daily maximum; 29 mg/L monthly average
  • • Neutralize to attain a pH of 5 or more
  • • In compliance with 96 hr. LC-50 of SPP-3% vol. toxicity test first for drilling fluidse or alternatively testing based on standard toxicity assessment species (preferably site-specific species)
Produced Sand Ship-to-shore or reinject: No discharge to sea except when oil concentration lower than 1% by weight on dry sand
Hydrotest Water
  • • Send to shore for treatment and disposal.
  • • Discharge offshore following environmental risk analysis, careful selection of chemical
  • • Reduce use of chemicals.
Cooling Water The effluent should result in a temperature increase of no more than 3°C at edge of the zone where initial mixing and dilution take place. Where the zone is not defined, use 100 m from point of discharge.
Desalination Brine Mix with other discharge waste streams, if feasible.
Sewage Compliance with MARPOL 73/78h
Food Waste Compliance with MARPOL 73/78h
Storage Displacement Water Compliance with MARPOL 73/78h
Bilgewater Compliance with MARPOL 73/78h
Deck Drainage Compliance with MARPOL 73/78h

Pollution prevention and control measures to consider prior to the discharge of spent drilling fluids and drilled cuttings should include the following guidelines:

  • Minimize environmental hazards related to residual chemical additives on discharged cuttings by careful selection of the fluid system. WBDFs should be selected whenever appropriate.
  • Carefully select drilling fluid additives, taking into account their concentration, toxicity, bioavailability, and bioaccumulation potential.
  • Use high-efficiency solids control equipment to reduce the need for fluid change out.
  • Use high-efficiency solids removal and treatment equipment to reduce and minimize the amount of residual fluid contained in drilled cuttings.
  • Use directional drilling (horizontal and extended reach) techniques to avoid sensitive surface areas and to gain access to the reservoir from less sensitive surface areas.
  • Use slim-hole multilateral wells and coiled tubing drilling techniques, when feasible, to reduce the amount of fluids and cuttings.

Drilling fluids to be discharged to sea (including as residual material on drilled cuttings) are subject to tests for toxicity, barite contamination, and oil content provided in Table 1. Barite contamination by mercury (Hg) and cadmium (Cd) must be checked to ensure compliance with the discharge limits provided in Table 1. Suppliers should be asked to guarantee that barite quality meets this standard with pre-treatment, if necessary.

WBDF and treated drilled cuttings discharge should be made via a caisson submerged at an appropriate depth to ensure suitable dispersion of the effluent (i.e., a dispersion study demonstrates that the relevant impact is acceptable).

Sand produced from the reservoir is separated from the formation fluids during hydrocarbon processing. The produced sand can contain hydrocarbons, and the hydrocarbon content can vary substantially, depending on location, depth, and reservoir characteristics. Well completion should aim to reduce the production of sand at source using effective downhole sand control measures.

Whenever practical, produced sand removed from process equipment should be transported to shore for treatment and disposal, or routed to an offshore injection disposal well if available. Direct discharge to sea is not good practice. If discharge to sea is the only demonstrably feasible option, then the discharge should meet the guideline values in Table 1.

Any oily water generated from the treatment of produced sand should be recovered and treated to meet the guideline values for produced water in Table 1.

Drilling&HSE

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