An oil and gas facility in a remote location had operated a membrane type acid gas removal unit for 20+ years to achieve LNG Plant arrival specification. The unit expelled the waste gases as intended, but carried approximately 5 MMSCFD of methane with this rejection product to flare, contributing some 25,000 TPA CO2 emissions whilst burning potential sales gas totaling $15.3m annually. 

As part of a whole-of-asset review, where we made several improvements to ways of working, HSE, production, and OPEX, we identified the potential to better manage wells and achieve gas export specification through feedstock blending without the need to operate the CO2 removal unit at all. 

We remained on site to support a 3-month trial, the result of which was the decommissioning of this polluting and resource heavy unit – saving approximately $400k annually in maintenance and operations costs.

Cost to implement - $0. All internal costs, with technical assurance by client engineers, changes to Operator procedures, and mothballing of unit.

Benefit to client – $15.7m value and 25,000 tonnes CO2 emissions annually

An oil export facility designed to recycle and re-inject all associated gas due to having no sales route was oil export constrained by gas processing limits. 

Whilst supporting the client to create choke models and debottleneck the hardware in the gas system,  we identified through working with the site operators that unbeknownst to them, the company’s engineers, and management, that the asset had failed to subordinate and synchronise the remainder of the production system to this gas compression constraint. The philosophy of operating lowest GoR wells as a priority was not universally understood, and the instructions given to Operators from Production Engineering focused on reservoir management was precise enough that it was never challenged (specific choke positions advised, rather than target top hole and bottom hole pressures).

We addressed this issue by providing simple playbooks and decision support tools that empowered Operators to maximise well delivery and manage production balance between trains autonomously. This had the immediate effect of improving oil export by 27% on the previous week. The client estimates that the philosophy change contributes a demonstrable 10% ongoing average production increase from the previous ways of working dating back at least 6 years. 

Cost to implement - $0. 

Benefit to client - $35m annually in 'cost free' additional production

Having acquired a smaller organisation with significant growth potential, a major Operator in Australia inherited several legacy production facilities which did not align to the company’s standards and operated beyond tolerable Individual Risk Per Annum (IRPA).  The cost of hardware upgrades was going to be substantial, whilst still not delivering company requirements related to equipment adjacency and hazard escalation. To the Operator, delivering tolerable IRPA was a need before entertaining ALARP discussions, and this was a direct threat to continued operation in the medium term.

This extended beyond a Process Safety Engineering exercise, and we solved this challenge through our expertise in bringing all areas of the business together and properly framing the problem. Once agreed, we worked collaboratively with Operations and Maintenance teams, spending time on site to understand their needs, and were ultimately able to deliver an 83% reduction in operator occupancy with zero loss of production reliability.  We transformed the site from one of 24-hour continuous occupation to ‘Not Normally Manned’ status, initially starting with equipment as found but ultimately upgrading minor items, such as oil day-tanks, to eventually deliver a one-in-seven-day Operator visit frequency. To the clients surprise, it also had the effect of improving reliability.

Our solution delivered performance well within the prescribed tolerability threshold, allowing continued operation whilst greater hardware improvements were designed. We would go on to support Operations Readiness, Maintenance, and Commissioning scopes for these projects.

Cost to implement – $50k plus internal costs to deliver one dayshift operator visit per week.

Benefit to client – continued operation in the short to medium term and significant long-term project rationalisation ($ tens of millions)

A gas and associated liquids plant had one gas supply contract and therefor operated on a daily production rate nomination. The LPG and condensate that the facility produced had no market limitations, but production of these products was constrained not by the plant, but by the limited gas sales. Gas was sold on an energy value basis.

Whilst reviewing the whole operation holistically, including the plant limitations, existing operating practices, pipeline specifications, and gas quality standards, we identified an opportunity. 

The facility removed CO2 from the gas stream as part of processing prior to refrigeration. By carefully increasing the percentage of CO2 carried through the system, we led the client to reduce the energy value of the sales gas by volume whilst maintaining specification. This had the effect of needing to produce increased volumes of gas to achieve the same energy nomination. By doing this, the wells were opened further, producing some 10% more LPG and Condensate than had been the case before intervention. 

Cost to implement – $0. All internal costs, with changes to Operator training, and update of procedures.

Benefit to client – approximately $7.2m annually