To advise Inspectors of the hazards of hydrocarbon gas releases from gas-lifted oil wells and to identify approaches to their control and mitigation. This SPC replaces SPC/Tech/OSD/01 Version 2 which has been withdrawn.
Gas lift is a means of artificial lift for oil production wells in which the backpressure in the production tubing is reduced by injecting gas into the tubing at some point downhole. The use of gas lift is not limited to wells incapable of natural flow; in many applications offshore on the UK Continental Shelf, gas lift is applied to naturally flowing wells to accelerate production. More than 20 manned installations have one or more gas lifted production wells drilled from the installation.
The use of gas lift requires that there are large inventories of pressurised hydrocarbon gas in both surface lines and in the well production annuli. Release of these inventories is a substantial topsides hazard.
While injection may, on occasion, be through a hole punched in the tubing wall, common practice requires the installation of gas lift valves at a number of points. The setting depths of the valves are chosen to optimise the efficiency of the gas lift. Typical gas lift operations may require the annulus to be filled with hydrocarbon gas at pressures greater than 100 bar to the depth of the lowest operating valve. The mass of gas in the annulus of each gas lifted well can be several tonnes compared to a typical inventory in surface lines of 2 or 3 tonnes. Loss of containment of this inventory, during routine operations, would present a major hazard. This hazard exists in addition to the hazards of loss of containment of oil and gas from blowouts during well intervention activities, such as workovers, wireline or coiled tubing operations.
Gas lift operations may be continuous or intermittent:
Intermittent gas lift is rarely used offshore in the UK but some platforms do use gas lift in this fashion to unload high water cut wells after production shut-ins.
Disruption of the integrity of the annulus will permit the release of this gas with the potential to cause death and serious injuries. This is the main hazard attributable directly to gas lift operations.
The primary purpose of mitigation measures is to prevent injury to persons from the effects of the release of the high pressure gas from the annulus due to some disruption or failure of the wellhead, Xmas tree or surface lines and equipment. These measures can protect against other secondary events, such as environmental damage from reservoir flow through failed gas lift valves, but these are secondary to the main purpose of protecting health and safety.This circular does not address the environmental issues nor does it attempt to review the merits of various other types of artificial lift.
In addition to the general duties imposed on duty holders by Sections 2 and 3 of the Health and Safety at Work etc Act 1974 [HSW Act], and the demonstrations required by the Offshore Installations (Safety Case) Regulations 2005 [SCR] Regulation 12, two other Regulations apply to the use of gas lift. These are the Offshore Installations and Wells (Design and Construction etc) Regulations 1996 [DCR] Regulation 13(1) and the Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations 1995 [PFEER] Regulation 9(1).
SCR Regulation 12 requires that the duty holder demonstrate that risks to persons from major accident hazards have been evaluated and that measures have taken to reduce the risks to persons from these hazards to the lowest level that is reasonably practicable. 'Major' accidents include fires and explosions. Gas releases from the annuli of gas lifted wells, which may ignite, should be considered in this demonstration. The use of Quantified Risk Analysis [QRA] is not mandatory and is discussed in the guidance to the Regulations in paragraphs 180 to 182.
The fact that a risk reduction measure is not included in the demonstration in an accepted Safety Case cannot be used as an argument that the measure need not be subsequently considered.
DCR Regulation 13(1) imposes a duty on well operators to ensure that each 'well is so designed …[and].. equipped… [so that]… so far as is reasonably practicable there can be no unplanned escape of fluids from the well and that risks to the health and safety of persons from it or anything in its contents are as low as is reasonably practicable'. DCR regulation 18(2) requires that the arrangements for the examination by independent and competent persons of the well address these issues.
The duty in DCR Regulation 13(1) includes the prevention or reduction of escapes of hydrocarbon gases from all production annuli and, in particular, where gas lift is installed.
PFEER Regulation 4(1) requires the duty holder for the installation to take 'appropriate' measures to protect persons on the installation from fire and explosion. The Approved Code of Practice [ACOP] states that appropriate measures include designing hazards out, preventing hazardous events and mitigating their consequences.
Since releases of gas from a production annulus are clearly hazardous with the potential to cause fires and explosions, the general duty of regulation 4(1) applies to the control of such releases.
PFEER Regulation 5 imposes a duty to perform an assessment of the events, which could result in fire or explosion on an installation. Regulation 5(2) requires the assessment to include identification of such events as well as an evaluation of their likelihood and their consequences. The regulation also requires the establishment of performance standards and the selection of appropriate measures to protect persons from fire or explosion.
PFEER Regulation 9(1) imposes absolute duties to take appropriate measures to prevent uncontrolled releases of gas and the unnecessary accumulation of flammable substances and atmospheres. The purpose of the regulation is to prevent fire and explosion. The ACOP to this Regulation emphasises that hazards should be first designed out and, if they cannot be designed out, reduced by engineering measures and procedural controls. The Guidance to this Regulation recommends that the hydrocarbon inventory available for release should be limited.
The approach to controlling the hazards is contained in Guidelines for Safe Design, Installation and Operation of Artificially Lifted Oil Wells, published by Oil and Gas UK.
There are main three steps to the approach, all with the aim of minimising risks to persons:
The duty holder must be able to demonstrate the requirement for artificial lift. The duty holder should evaluate all practicable types of artificial lift with a view to eliminating gas lift. The chosen option should be reasonably practicable and pose the lowest risk to persons.
Where gas lift is proposed, the duty holder should demonstrate that the hazards cannot be eliminated by design.
The duty holder must identify hazards and evaluate risks to persons.
The duty holder should review methods to reduce gas inventory in the annulus.
The duty holder should identify foreseeable scenarios for gas release causing risks to persons. The expected frequency of each failure should be estimated using appropriate reliability engineering techniques. Release due to damage to the Xmas tree or wellhead during normal production operations is foreseeable. The frequency of component failure leading to large releases is given in various databases. The resulting release frequencies can be derived using established reliability engineering techniques.
He should be in a position to demonstrate that appropriate methods to prevent or minimise gas releases have been identified and taken. In evaluating controls, it is appropriate to consider the risk to persons arising from repairing or replacing defective equipment.
Selection of effective mitigating measures requires knowledge of the frequency of various failures leading to hydrocarbon releases.
Appropriate measures may include:
Possible mitigation measures to control inventory include completion options such as:
Dual Completions with dual packer set below the mud line. The short string includes a Surface Controlled Sub-Surface Safety Valve (SCSSSV) or check valve, which can be set at any depth above the dual packer and maybe set well above any SCSSSV in the production string. Some operators have used this method.
Annular Safety Valve [ASV]. This must be set below any SCSSSV in the production string. This leaves some annular inventory above the valve.
Each method may be appropriate for some but not all applications. Selection will be a matter of good engineering practice subject to a requirement to control as much inventory as possible. Frequencies of releases due to failures of specific components derived from reliability engineering studies may assist in identifying which approach will be most appropriate.
30 All these methods will be subject to failure of downhole components and will require some form of well intervention for repair. Failure rates can be calculated from reliability data in industry studies.
For further information, please contact the Head of Discipline – Well Engineering & Operations OSD 2.4 (01224 252581)