After a period of dormancy, drilling activity is starting to ramp up. As an operator, you will be looking to take advantage of low rig rates and will ideally be looking for a ‘hot rig’ (i.e. an operational rig), to avoid risk and delay which can occur from contracting nonoperational rigs that require reactivation from a state of warm or cold stacking. Often the timing and current market is such that there are few or no options without delaying the campaign due to a lack of operational rigs. Other contributing factors include commercial demands such as management requesting the lowest day rate. So, what if you can’t get a hot rig? Is the reactivation process such a daunting and risky task? It ultimately depends on how well the rig has been preserved and whether it’s been warm or cold stacked.
Rig market outlook Due to the preceding low level of activity, rig owners will continue to exhibit reluctance in reactivating rigs that have been stacked, until longer commitments are guaranteed. The shorter campaigns, pose a problem for the longer-term supply of rigs. Ideally as an operator, you want a ‘hot’ rig, but in reality are increasingly faced with contracting rigs that are warm or even cold stacked.
Ready, steady, reactivate So what should you do if you can’t get a hot rig? You’ll have to conduct a rig intake process involving a rig that is nonoperational, and requires reactivation. A reactivation process can be extensive and unpredictable. Having an understanding of the technical and regulatory challenges can help you successfully and cost effectively tender, select and accept a non-operational rig onto contract.
1. Develop review of rig status
Gaining an understanding of the status of class, the depth of reactivation required and any remedial or deferred maintenance that is outstanding is key to knowing where future operational or regulatory risk is a threat. The rig tender process does not always give you full visibility of these issues, therefore addressing them early on provides you with a comfort factor as to the status of the rig and if the rig owner can realistically reactivate to meet the intended spud date.
2. Review of jurisdiction compliance
Many rig owners are marketing their rigs internationally, meaning that if successful, some may move from one regulatory regime to another. The regulatory bodies have shown an interest in rigs entering their respective regions, with increased focus on rigs which have been non-operational. Depending on the specific regulatory regime, as an operator you have a duty of care and legal responsibility to ensure that the rig you have selected will enter and operate in the new regulatory region, within compliance. This issue should be recognised as a real risk to the start of drilling operations and an effective review process should be established; monitoring the activity of the rig owner to achieve the level of compliance prior to entering the new region. Consideration should be given to any analysis of the gaps or difference between respective regimes, any region specific documentation (for example the Safety Case) and the project plan that the rig owner has put in place. In some cases a rig owner may have to initiate some modifications to the rig to meet compliance and a shipyard project could be required.
3. Audit and implementation of management systems
Where a rig has been non-operational, and/or is moving regulatory regimes, the completeness and robustness of the management systems (including HSE, Emergency Preparedness and Crew Competence) should be assessed. Typically until a rig owner secures a drilling contract, they may not follow a management system of an operational rig. For example, the rig will not be fully crewed and will not be following the full maintenance management plans. Readopting the various management systems will be a staged and progressive process by the rig owner. This is an area that should be of focus for any operator; it’s key to identify critical issues early on and work together with the rig owner to understand the status of the management systems and plan to readopt them onto the rig. It’s likely that new crew will be recruited who are unfamiliar with the rig and management systems, or that previously employed crew are brought back after a long period of being off the rig. As the spud dates gets closer, the ability of the rig and its crew to demonstrate understanding of the various management systems and verify implementation, will be critical to satisfy operator and regulatory body requirements.
4. Identify and manage risk
It is important to note that regardless of the type and generation of rig, the level of risk depends on the robustness of the rig owners’ method of stacking and how they plan to reinstate operational management systems. Risks can emanate from three main elements, the People, the Systems and the Equipment (PSE):
People • Loss of key rig personnel who have familiarity with the rig from previous well operations. The risk includes different crew members not being familiar with the equipment and systems, where regular crew have undergone specific Original Equipment Manufacturer (OEM) training and are switched out for less expensive qualified alternatives. This can result in reduced knowledge of the rig during the reactivation period and cause delays. • The morale of the remaining rig personnel is a risk to the integrity of the equipment; short cuts are taken, budgets are hard to obtain and personal remuneration has been cut. This can result in the completion of regular maintenance work orders being skipped on a non-operational rig. • Project personnel are brought in too late (including internal Technical Authorities, Project Managers, Project Engineers, Project Buyers, etc.) to manage the reactivation process. Generally they can be disorganised and unfamiliar with the rig, with ineffective planning causing delays. For example, ordering spare parts which have a lead time can generally be attributed to poor planning.
Systems • On a non-operational rig, the Computerised Maintenance Management System (CMMS) will likely be frozen and a non-operational mode will be used. This can lead to poorly structured maintenance routines which are not reflective of the complexity of the equipment. • During the preparation for being non-operational, there is often a lack of detailed records of preservation activities. It is essential to have well-structured and detailed records in order to ensure the reactivation period is successful. Equipment that has been overlooked causes considerable damage and delays during the reactivation phase.
Equipment Depending on the procedures and criteria used to stack the rig equipment, the rig owner will have a procedure to reactivate and bring the equipment and systems back to operational status. The integrity of equipment can be a critical risk to the successful reactivation process. It is important to gain an early understanding of integrity, condition and lead times for bringing in the OEM and ordering replacement parts, including any remedial work to be carried out. On average a reactivation process can last between 30 – 60 days, and depending on the agreed contract between operator and rig owner, there is a risk that the rig can be on the well site, but still not be in a satisfactory condition to operate. It is prudent to get a baseline understanding of the integrity of equipment at the start of the reactivation process and periodically follow progress. Also, having clarification in the contract of how and when the rig is accepted onto contract is important not only for the equipment integrity but to ensure all systems and devices installed for the protection of lives and to avoid discharge to the environment are in place. This can range from functioning life raft to spark arrestors and explosion mitigating devices. More often than not, a period of rig acceptance, including equipment and system endurance testing, is part of the rig intake process and included in the contract. This provision ensures that the integrity and operability of the rig equipment is proven and to the greatest extent possible, ready to start drilling operations and be accepted on to contract. During the non-operational period and the reactivation, the following items are commonly a risk to the integrity of the equipment and readiness to recommence operations: • Equipment that requires recertification is only put to the OEM when a contract is gained, meaning lead times can be narrow for reactivation. • Rotating equipment is not adequately turned, meaning the bearings can flatten and cause equipment to be inoperable or affect reliability during reactivation and the early phases of drilling. • Sensitive equipment is not stored indoors in heated and humidity controlled storage areas, affecting integrity and making it harder to reactivate. Correct storage would stop the ingress of moisture and reduce weather related corrosion. • All in/outlets from units/skids are not plugged/blanked. Flanges not blanked with oil resistant rubber gaskets causing corrosion to the flange surface. • Threaded openings do not have metal plugs of metallurgy equal to the component being capped or plugged. Ingress protection rated equipment is not maintained with plastic plugs for non-hydraulic/pneumatic systems. • Where the crew do not periodically open drains and water traps to reduce water content inside the equipment, internal corrosion can occur during reactivation. • Weathering can increase corrosion if carbon steel piping is not coated with corrosion inhibitor (inside and outside) and fitted with end caps. Corrosion in piping causes delays and contamination of systems, especially in rotating and pumping equipment. • Unpainted and machined surfaces not coated with rust preventive wax, which is a risk to build-up of corrosion. • Acid free Vaseline or equivalents not added to lubricate gaskets on door covers, which would aid the ingress of moisture and corrosion. The risk is failure as they dry out. • Exposed valves spindles are not covered with grease tape, Teflon lubricant and vulcanizing tape or equal. If not regularly operated, corrosion can build up. • No anti-freeze added to equipment or pipe systems where water is used for storage, cleaning or pressure testing. • Lack of investment and planning for well control internal consumables such as internal seals, operating fluid, elastomers, flow line piping, choke and kill manifold piping and valves. • Desiccant is not removed from systems that have a direct contact with metallic surfaces, as desiccate is corrosive when left stagnant for long periods of time. • No preservation labels are fitted showing applicable preservation method and the inspection intervals. • Where specific equipment vents are sealed, signs do not clearly alert the reactivation crew to remove the seals. • Where blanking plates have been used in valves or pipework, no clear indictors are used to alert reactivation crews. • Electrical and electronic equipment suffers corrosion as they have been exposed to humidity where they were not protected with desiccant or vapour corrosion inhibitor. • Air conditioning set up is not sufficient to protect electronics. De-humidification is not the only defensive measure to protect electronics and this can be dependent on the location of lay-up. • Maximum moisture level indicator tags are not fitted throughout the electronic systems. The above highlights that equipment condition alone is not a reference for reliable and safe drilling operations and that the people operating it and the systems supporting it are equally as important.
5. Rig acceptance Whether the rig has been non-operational for a number of months or a number of years, it is important that a series of equipment and systems tests are adopted as part of the acceptance phase of the rig intake process for a non-operational rig. Normally the rig owner will have their own internal testing programme, which can be adopted and enhanced to meet these well performance requirements. Where a testing programme does not exist you should ensure as the operator that a rig specific one is developed in close collaboration with the rig owner. A programme will typically include testing of individual entity equipment, for example mud pumps, mud pits, top drive and shale shakers. It will also test the integrity of the full system, such as running fluids through the mud system, top drive over the shakers as well as checking all alarms and sensors are functioning. Depending on the design of the rig, marine and blow out prevention systems will also be of focus to ensure all safety and operational critical equipment and systems are fully functioning. On today’s sophisticated rigs, the completeness and function of the electronic control systems is of high importance. Conclusion In summary, whilst it’s recognised that a hot rig is the ideal and preferred option due to the historic continued operation and readiness, you can still commence drilling operations swiftly, cost effectively and safely with a rig that needs to be reactivated prior to intake. Granted, success is about ensuring all factors highlighted are considered and taken into account, to ensure there are no significant project delays and unexpected costs. Having an appreciation of the technical and regulatory challenges and requirements will undoubtedly help you successfully and cost effectively tender, select and accept a nonoperational rig onto contract.