SIST EN ISO 13500:2006
(Main)Petroleum and natural gas industries - Drilling fluid materials - Specifications and tests (ISO 13500:2006)
Petroleum and natural gas industries - Drilling fluid materials - Specifications and tests (ISO 13500:2006)
This International Standard covers physical properties and test procedures for materials manufactured for use in oil- and gas-well drilling fluids. The materials covered are barite, haematite, bentonite, nontreated bentonite, OCMA grade bentonite, attapulgite, sepiolite, technical grade low-viscosity carboxym ethylcellulose (CMC-LVT), technical grade high-viscosity carboxymethylcellulose (CMC-HVT), and starch. This International Standard is intended for the use of manufacturers of named products.
Erdöl- und Erdgasindustrie - Bohrspülungen - Spezifikationen und Prüfungen (ISO 13500:2006)
Industries du pétrole et du gaz naturel - Produits pour fluides de forage - Spécifications et essais (ISO 13500:2006)
Industrija za predelavo nafte in zemeljskega plina – Materiali za vrtalne tekočine – Specifikacije in preskusi (ISO 13500:2006)
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This document contains requirements for defining the seismic design procedures and criteria for
offshore structures; guidance on the requirements is included in Annex A. The requirements focus on
fixed steel offshore structures and fixed concrete offshore structures. The effects of seismic events on
floating structures and partially buoyant structures are briefly discussed. The site-specific assessment
of jack-ups in elevated condition is only covered in this document to the extent that the requirements
are applicable.
Only earthquake-induced ground motions are addressed in detail. Other geologically induced hazards
such as liquefaction, slope instability, faults, tsunamis, mud volcanoes and shock waves are mentioned
and briefly discussed.
The requirements are intended to reduce risks to persons, the environment, and assets to the lowest
levels that are reasonably practicable. This intent is achieved by using:
a) seismic design procedures which are dependent on the exposure level of the offshore structure and
the expected intensity of seismic events;
b) a two-level seismic design check in which the structure is designed to the ultimate limit state (ULS)
for strength and stiffness and then checked to abnormal environmental events or the abnormal
limit state (ALS) to ensure that it meets reserve strength and energy dissipation requirements.
Procedures and requirements for a site-specific probabilistic seismic hazard analysis (PSHA) are
addressed for offshore structures in high seismic areas and/or with high exposure levels. However, a
thorough explanation of PSHA procedures is not included.
Where a simplified design approach is allowed, worldwide offshore maps, which are included in
Annex B, show the intensity of ground shaking corresponding to a return period of 1 000 years. In
such cases, these maps can be used with corresponding scale factors to determine appropriate seismic
actions for the design of a structure, unless more detailed information is available from local code or
site-specific study.
NOTE For design of fixed steel offshore structures, further specific requirements and recommended values
of design parameters (e.g. partial action and resistance factors) are included in ISO 19902, while those for fixed
concrete offshore structures are contained in ISO 19903. Seismic requirements for floating structures are
contained in ISO 19904, for site-specific assessment of jack-ups and other MOUs in the ISO 19905 series, for arctic
structures in ISO 19906 and for topsides structures in ISO 19901-3.
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This document specifies requirements and recommendations for the site-specific assessment of mobile floating units for use in the petroleum and natural gas industries. It addresses the installed phase, at a specific site, of manned non-evacuated, manned evacuated and unmanned mobile floating units.
This document addresses mobile floating units that are monohull (e.g. ship-shaped vessels or barges); column-stabilized, commonly referred to as semi-submersibles; or other hull forms (e.g. cylindrical/conical shaped). It is not applicable to tension leg platforms. Stationkeeping can be provided by a mooring system, a thruster assisted mooring system, or dynamic positioning. The function of the unit can be broad, including drilling, floatel, tender assist, etc. In situations where hydrocarbons are being produced, there can be additional requirements.
This document does not address all site considerations, and certain specific locations can require additional assessment.
This document is applicable only to mobile floating units that are structurally sound and adequately maintained, which is normally demonstrated through holding a valid RCS classification certificate.
This document does not address design, transportation to and from site, or installation and removal from site.
This document sets out the requirements for site-specific assessments, but generally relies on other documents to supply the details of how the assessments are to be undertaken. In general:
- ISO 19901 7 is referenced for the assessment of the stationkeeping system;
- ISO 19904 1 is referenced to determine the effects of the metocean actions on the unit;
- ISO 19906 is referenced for arctic and cold regions;
- the hull structure and air gap are assessed by use of a comparison between the site-specific metocean conditions and its design conditions, as set out in the RCS approved operations manual;
- ISO 13624 1 and ISO/TR 13624 2[1] are referenced for the assessment of the marine drilling riser of mobile floating drilling units. Equivalent alternative methodologies can be used;
- IMCA M 220 is referenced for developing an activity specific operating guidelines. Agreed alternative methodologies can be used.
NOTE RCS rules and the IMO MODU code[13] provide guidance for design and general operation of mobile floating units.
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This document gives requirements for the design, setting depth and installation of conductors used by the offshore petroleum and natural gas industries. This document covers:
- design of the conductor, i.e. determination of the diameter, wall thickness, and steel grade;
- determination of the setting depth for three installation methods, namely, driving, drilling/cementing, and jetting;
- installation requirements for the installation methods, i.e. selection principles, operating procedures and parameters.
This document is applicable to:
- Platform conductors: installed through a guide hole in the platform drill floor and then through guides attached to the jacket at appropriate intervals through the water column to support the conductor withstand metocean actions and prevent excessive displacements.
- Jack-up supported conductors: a temporary conductor used only during drilling operations, which is installed by a jack-up drilling rig. In some cases, the conductor is tensioned by tensioners attached to the drilling rig.
- Free-standing conductors: a self-supporting caisson in cantilever mode installed in shallow water, typically depths of about 10 m to 20 m. It provides sole support for the well and sometimes supports a small access deck and boat landing.
- Subsea wellhead conductors: a fully submerged conductor extending only a few metres above the seafloor.
This document does not apply to drilling risers.
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This document specifies the requirements for design including shape and dimensions, material as well as strength for pipe support from NPS 2 up to NPS 36 except for U-bolt and U-strap. This document covers topside systems for fixed or floating offshore oil and gas projects. This document applies for design temperature of support within the range between –23 °C up to 200 °C. This document is limited to metallic pipes only.
This document covers such requirements for following pipe supports:
— clamped shoe;
— welded shoe;
— U-bolt;
— U-strap;
— bracing for branch connection;
— trunnion and stanchion;
— guide support(guide, hold-down, guide/hold-down).
This document addresses design requirements of the listed items above, hence the document does not necessarily cover all other types of pipe supports.
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This document specifies requirements and gives recommendations for the performance, dimensional
and functional interchangeability, design, materials, testing, inspection, welding, marking, handling,
storing, shipment, and purchasing of wellhead and tree equipment for use in the petroleum and natural
gas industries.
This document does not apply to field use or field testing.
This document does not apply to repair of wellhead and tree equipment except for weld repair in
conjunction with manufacturing.
This document does not apply to tools used for installation and service (e.g. running tools, test tools,
wash tools, wear bushings, and lubricators).
This document supplements API Spec 6A, 21st edition (2018), the requirements of which are applicable
with the exceptions specified in this document.
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This document provides requirements and guidelines for marine geophysical investigations. It is applicable to operators/end users, contractors and public and regulatory authorities concerned with marine site investigations for offshore structures for petroleum and natural gas industries.
This document provides requirements, specifications, and guidance for:
a) objectives, planning, and quality management;
b) positioning;
c) seafloor mapping, including instrumentation and acquisition parameters, acquisition methods, and deliverables;
d) sub-seafloor mapping, including seismic instrumentation and acquisition parameters, and non-seismic-reflection methods;
e) reporting;
f) data integration, interpretation, and investigation of geohazards.
This document is applicable to investigation of the seafloor and the sub-seafloor, from shallow coastal waters to water depths of 3 000 m and more. It provides guidance for the integration of the results from marine soil investigations and marine geophysical investigations with other relevant datasets.
NOTE 1 The depth of interest for sub-seafloor mapping depends on the objectives of the investigation. For offshore construction, the depths of investigation are typically in the range 1 m below seafloor to 200 m below seafloor. Some methods for sub-seafloor mapping can also achieve much greater investigation depths, for example for assessing geohazards for hydrocarbon well drilling.
There is a fundamental difference between seafloor mapping and sub-seafloor mapping: seafloor signal resolution can be specified, while sub-seafloor signal resolution and penetration cannot. This document therefore contains requirements for the use of certain techniques for certain types of seafloor mapping and sub-seafloor mapping (similarly, requirements are given for certain aspects of data processing). If other techniques can be shown to obtain the same information, with the same or better resolution and accuracy, then those techniques may be used. Mapping of pre-drilling well-site geohazards beneath the seafloor is part of the scope of this document.
NOTE 2 This implies depths of investigation that are typically 200 m below the first pressure-containment casing string or 1 000 m below the seafloor, whichever is greatest. Mapping of pre-drilling well-site geohazards is therefore the deepest type of investigation covered by this document.
In this document, positioning information relates only to the positioning of survey platforms, sources and receivers. The processes used to determine positions of seafloor and sub-seafloor data points are not covered in this document.
Guidance only is given in this document for the use of marine shear waves, marine surface waves, electrical resistivity imaging and electromagnetic imaging.
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This document establishes the principles, specifies the requirements and provides guidance for the development and implementation of an escape, evacuation and rescue (EER) plan. It is applicable to offshore installation design, construction, transportation, installation, offshore production/exploration drilling operation service life inspection/repair, decommissioning and removal activities related to petroleum and natural gas industries in the arctic and cold regions.
Reference to arctic and cold regions in this document is deemed to include both the Arctic and other locations characterized by low ambient temperatures and the presence or possibility of sea ice, icebergs, icing conditions, persistent snow cover and/or permafrost.
This document contains requirements for the design, operation, maintenance, and service-life inspection or repair of new installations and structures, and to modification of existing installations for operation in the offshore Arctic and cold regions, where ice can be present for at least a portion of the year. This includes offshore exploration, production and accommodation units utilized for such activities. To a limited extent, this document also addresses the vessels that support ER, if part of the overall EER plan.
While this document does not apply specifically to mobile offshore drilling units (MODUs, see ISO 19905‑1) many of the EER provisions contained herein are applicable to the assessment of such units in situations when the MODU is operated in arctic and cold regions.
The provisions of this document are intended to be used by stakeholders including designers, operators and duty holders. In some cases, floating platforms (as a type of offshore installations) can be classified as vessels (ships) by national law and the EER for these units are stipulated by international maritime law. However, many of the EER provisions contained in this document are applicable to such floating platforms.
This document applies to mechanical, process and electrical equipment or any specialized process equipment associated with offshore arctic and cold region operations that impacts the performance of the EER system. This includes periodic training and drills, EER system maintenance and precautionary down-manning as well as emergency situations.
EER associated with onshore arctic oil and gas facilities are not addressed in this document, except where relevant to an offshore development.
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This document specifies requirements for managing and controlling the weight and centre of gravity
(CoG) of offshore facilities by means of mass management during all lifecycle phases including;
conceptual design, front end engineering design (FEED), detail engineering, construction and
operations. These can be new facilities (greenfield) or modifications to existing facilities (brownfield).
Weight management is necessary throughout operations, decommissioning and removal to facilitate
structural integrity management (SIM). The provisions of this document are applicable to fixed and
floating facilities of all types.
Weight management only includes items with static mass.
Snow and ice loads are excluded as they are not considered to be part of the facility. Dynamic loads are
addressed in ISO 19904-1, ISO 19901-6 and ISO 19901-7.
This document specifies:
a) requirements for managing and controlling weights and CoGs of assemblies and entire facilities;
b) requirements for managing weight and CoG interfaces;
c) standardized terminology for weight and CoG estimating and reporting;
d) requirements for determining not-to-exceed (NTE) weights and budget weights;
e) requirements for weighing and determination of weight and centre of gravity (CoG) of tagged
equipment, assemblies, modules and facilities;
This document can be used:
f) as a basis for costing, scheduling or determining suitable construction method(s) or location(s) and
installation strategy;
g) as a basis for planning, evaluating and preparing a weight management plan and reporting system;
h) as a contract reference;
i) as a means of refining the structural analysis or model.
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This document specifies the selection criteria and minimum requirements for protective coating systems for field maintenance and repair of risers exposed to conditions in the splash zone.
This document does not cover the selection of techniques and materials used to restore integrity of the risers to be coated.
This document neither covers the selection of additional mechanical protective materials that are not part of the described coating systems included in this document.
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This document illustrates the formulae and templates necessary to calculate the various pipe properties given in International Standards, including
— pipe performance properties, such as axial strength, internal pressure resistance and collapse resistance,
— minimum physical properties,
— product assembly force (torque),
— product test pressures,
— critical product dimensions related to testing criteria,
— critical dimensions of testing equipment, and
— critical dimensions of test samples.
For formulae related to performance properties, extensive background information is also provided regarding their development and use.
Formulae presented here are intended for use with pipe manufactured in accordance with ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L, as applicable. These formulae and templates can be extended to other pipe with due caution. Pipe cold-worked during production is included in the scope of this document (e.g. cold rotary straightened pipe). Pipe modified by cold working after production, such as expandable tubulars and coiled tubing, is beyond the scope of this document.
Application of performance property formulae in this document to line pipe and other pipe is restricted to their use as casing/tubing in a well or laboratory test, and requires due caution to match the heat-treat process, straightening process, yield strength, etc., with the closest appropriate casing/tubing product. Similar caution is exercised when using the performance formulae for drill pipe.
This document and the formulae contained herein relate the input pipe manufacturing parameters in ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L to expected pipe performance. The design formulae in this document are not to be understood as a manufacturing warranty. Manufacturers are typically licensed to produce tubular products in accordance with manufacturing specifications which control the dimensions and physical properties of their product. Design formulae, on the other hand, are a reference point for users to characterize tubular performance and begin their own well design or research of pipe input properties.
This document is not a design code. It only provides formulae and templates for calculating the properties of tubulars intended for use in downhole applications. This document does not provide any guidance about loads that can be encountered by tubulars or about safety margins needed for acceptable design. Users are responsible for defining appropriate design loads and selecting adequate safety factors to develop safe and efficient designs. The design loads and safety factors will likely be selected based on historical practice, local regulatory requirements, and specific well conditions.
All formulae and listed values for performance properties in this document assume a benign environment and material properties conforming to ISO 11960 or API 5CT, ISO 11961 or API 5D and ISO 3183 or API 5L. Other environments can require additional analyses, such as that outlined in Annex D.
Pipe performance properties under dynamic loads and pipe connection sealing resistance are excluded from the scope of this document.
Throughout this document tensile stresses are positive.
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