Meeting the chemical injection challenge

As offshore operators get into deeper waters and develop more mature oil & gas fields using more complex well architectures, continuous downhole injection of chemicals is increasingly required to manage challenges such as scale formation or asphaltene precipitation within the wellbore. PTC ’s Alan Brodie cautions against allowing chemical injection systems to become weak links in the well integrity chain.

A typical chemical injection system includes a surface pump and pipework to deliver treatment chemicals from storage tanks to the wellhead. At the wellhead, the injection line has to penetrate the well’s secondary containment envelope, effectively becoming part of it. The line runs down the outside of the tubing to an injection valve, which is usually set as deep as possible within the well.

The injection valve controls the flow of treatment chemicals from the injection line. More critically though, since it is installed in the wall of the production tubing which forms part of the well’s primary containment envelope, it also has to reliably act as a well barrier check valve. This means it has to eliminate the potential for hydrocarbon flow from the production tubing to the chemical injection line at any stage in the life of the well.

Historically wellhead chemical injection line penetrations have been poorly protected against potential damage during maintenance operations.

A widely recognised best practice has been developed and adopted by most operating companies in order to reduce the risk of uncontrolled hydrocarbon escape from the wellbore to the atmosphere to a level which is as low as is reasonably practicable (ALARP).

The approach is simply to ensure that all of the components which form part of, or penetrate, the primary and secondary well containment envelopes are accredited to perform at a level which is at least equivalent to that of the other components – such as tubing, packers and wellheads which have been verified as fit-for-purpose.

PTC chemical injection sub rated to 10,000psi and 121°C.

Blind spot

In recent years, the industry has recognised the importance of using well barrier valves and surface annulus safety (SAS) valves in gas lift applications. In this case, the lift gas injection flow path breaches both the primary and secondary containment envelopes at the downhole gas lift valve and where the lift gas enters the annulus at the wellhead respectively. Despite this, although chemical injection systems potentially introduce the same weak links in the primary and secondary well containment envelopes, the industry still has a blind spot when it comes to addressing them in the main. As a result, there are many cases where operating companies are deploying downhole chemical injection valves which are not accredited to the same standards as other safety critical components in the primary containment envelope such as tubing connection and packers or plugs.

Worse still, this weak link in the primary barrier is often compounded by the relatively vulnerable injection line which penetrates the wellhead being unprotected against damage that may occur, particularly while maintenance operations are being carried out, either on the wellhead itself or at the Christmas tree.

PTC has now developed well barrier-accredited chemical injection valves. One family of valves solve the weak link in the downhole primary containment barrier, and another has been engineered to address the wellhead secondary containment barrier issue.

The downhole and wellhead valves borrow heavily from the technology used in PTC’s Safelift series well barrier gas lift valves (GLVs) and M-SAS surface annulus safety valves, both deployed by operators worldwide as a means of ensuring annulus integrity in gas lifted wells.

The downhole valve Safelift CIV is accredited to ISO 17078 part 1 and 2 (E4, Q1, V1, F1) and ISO 14310-V0, while the M SAS CIV wellhead valve is accredited to API 6A/ISO 10423/PSL3G PR2.

The Safelift CIV can either be deployed in a side pocket mandrel and retrieved by wireline and coiled tubing or permanently retrieved during workover or recompletion in a chemical injection sub. In either case, in addition to the well barrier accredited check valve functionality, the Safelift CIV design is such that injection line drainage – the most common cause of malfunction in existing chemical injection systems – is addressed.

Drainage challenge

A common misconception is that if the surface end of the injection line is not open ended, then injection line drainage cannot occur. The reality is that, even if the surface end of the injection line is closed, treatment chemicals will drain from the line if pressure in the injection line, due to the hydrostatic head of the injection chemical and any pump discharge pressure, is greater than that in the tubing. At the same time, the chemical at the surface end of the line vaporises and the liquid vapour interface falls within the injection line, until the pressures across the downhole injection valve equalise.

Old tie-down bolt hydraulic penetration arrangement (above) versus the PTC tie-down bolt integral check valve penetration

In addition to the extra cost of chemicals and the possibility that there will be outages in the treatment regime, the vaporisation of the chemical can often result in a change of the physical properties within the remaining liquid phase. Depending on the chemical type, this can result in gunking or crystallisation and consequent line blockage, rendering the chemical injection system useless. In this scenario an expensive workover operation will be required to replace the line.

Two-part chemical injection line wellhead termination sleeve and check valve.

PTC has addressed this challenge by developing modular valves which incorporate two check valves in series. The downstream valve incorporates the same check valve module successfully employed in Safelift GLVs. These were designed using computational fluid dynamics, to ensure the check valve flow paths and opening dimensions were optimised with regard to erosion by minimising the flow velocity across and the flow stream angle of incidence with respect to the metal/metal seal faces.

This is in stark contrast to traditional gas lift and chemical injection check valve design, where the flow stream usually impinges directly on the check valve seal face. As a result, erosive velocities across the valve seal faces are much lower and the valves have less of a tendency to chatter – significantly improving reliability.

In order to eliminate the potential for injection line drainage, PTC chemical injection valves also include an additional valve module, in series immediately upstream of the check valve. The upstream valve uses the same dart architecture as the check valve but is held closed by a much stronger spring. The spring rating is calculated considering the range of flowing bottom-hole pressure (FBHP) expected through the life of the well and the injection system’s hydraulic parameters. A novel PTC software tool is used, along with client reservoir simulator profiles, to predict the spring settings required to ensure line drainage does not occur at any stage during field life.

Alan Brodie, a mechanical engineer and 30year veteran of the oil & gas industry, is business development advisor at Petroleum Technology Company (PTC). He started out with Britoil as a drilling and petroleum engineer in the North Sea and later became a BP production technologist in the UK and United Arab Emirates. Since joining PTC, he has been instrumental in helping the company to develop its business internationally.

Borrowing from its existing M-SAS gas lift surface annulus safety valve technology, PTC has developed surface safety valves for chemical injection systems. The new system comprises a modular actuated check valve system in which the check valve module is buried within the wellhead penetration conduit. The actuator module is external to the wellhead, and designed to detach in the event it is struck by a dropped object, leaving the check valve in the closed position. This addresses the shortcomings of traditional systems which a dropped object could easily break, causing a breach of the secondary containment envelope.

A variety of surface safety valve architecture options have been developed including some which can even be deployed in a situation where the chemical injection line penetrates the hanger tie-down bolt cavity.

The challenge of annulus pressure management is an area in which PTC continues to innovate, with the wellhead VR profile pressure/temperature sensors among key tools available to operators. While annulus pressure build up can readily be dealt with in dry tree applications, it can often be more challenging in subsea wells.

In this case, a number of clients are putting PTC’s chemical injection valves to new use – to bleed annulus pressure as it builds up into the production tubing string, without a chemical injection line attached. OE