Australian operators band together to create audit tool for well operations, plan mutual assistance in case of loss of well containment
By Joanne Liou, associate editor
Following the Montara and Macondo incidents, the Australian Petroleum Production & Exploration Association (APPEA) formed a Montara Response Taskforce. This taskforce established two steering committees – the Australian Drilling Steering Committee (DSC) and the Emergency Management Committee – to focus on the region’s response. From your perspective as chairman of the DSC, which is now known as the Australian Drilling Managers’ Committee, what progress has been made to help industry enhance operational integrity?
The steering committees provided a forum to share expertise, experience and actions taken by APPEA’s members and identified a number of tasks. For the DSC, this included the development of a self-audit tool – Management of Well Operations, a draft mutual aid memorandum of understanding (MOU) and the Australian Industry Capping solution.
The self-audit tool was developed and issued as a voluntary checklist to highlight areas of critical bridging between organizations and is useful for auditing internal systems and processes relating to management of well operations. In developing the tool, we referenced the existing regulatory regime of safety case and WOMPs (well operation management plans) and sought to further clarify the respective roles and responsibilities of the licensee, rig operator and third-party service providers. The tool covers critical areas in well planning, preparation, execution and operations.
The mutual aid MOU was developed to facilitate the arrangement of mutual assistance in drilling relief wells required for a loss of well containment incident. Most operators in Australia have committed to the MOU to quickly mobilize local drilling rigs and support in emergencies.
The Australian Industry Capping Solution was developed, working closely with OGP and the international industry, to identify the best local option. It was determined that a package of equipment allowing immediate response to a loss of well containment incident needed to be available in Australia. This includes equipment to allow assessment of the damage on the sea floor, emergency override and operation of blowout preventers (BOPs), preparation of the wellhead for a capping device and the subsea injection of dispersant.
This collection of equipment, the Subsea First Response Toolkit (SFRT), will become operationally available in Australia in early 2014. Deployment of the SFRT provides adequate time for an individual operator to activate its own plans for mobilization of equipment for subsequent operations – for example, a capping stack – from outside Australia.
In the Gulf of Mexico, industry deployed a capping stack as part of a containment exercise in 2012. Do you foresee any similar drills taking place in Australia?
Industry participants have performed exercises of oil response capabilities, such a boom deployment. As far as running a capping stack, we are still exploring the possibility.
What is the DSC working on now?
The DSC remains an effective management-level interface group targeting common industry challenges on well integrity and process safety. Process safety in wells is about keeping full control over the hydrocarbons in the well.
We share the learnings from our operations and incidents. This includes reviewing well control events, like kicks, that occur locally or internationally. However, we also want to be able to measure and track our leading process safety performance and are exploring ways to commonly define indicators and share this information.
What are some examples of leading process safety indicators that the committee is considering?
Leading process safety indicators are measures of performance in maintaining robust controls – a proactive approach. These measures include the effectiveness of “hard” technical controls, including loss of a single barrier that does not lead to an influx, and “soft” controls like training and competence, including audits of well control certification. You can start measuring those things to understand where your gaps are and how you’re performing.
Post-Montara/Macondo, how were operations in Australia impacted?
Since Macondo, industry terms like BOP have become more familiar to the community. I don’t think we could have said that before Macondo. The public’s concerns about the risk of offshore drilling has certainly changed the way industry communicates what are often complex technical matters. Oil and gas operators tend to now engage to a far greater extent with the community at large on the operations that they are undertaking.
The Australian oil and gas industry remains committed to demonstrating its capacity to prevent, intervene and respond to any major offshore loss of containment. However, many offshore operators have been challenged by an increasing regulatory load since Macondo and Montara. Much of this has focused on environmental compliance associated with a heavy administrative component, but industry is working with the regulators and APPEA to ensure this compliance activity does not detract from the real objective, which is achieving genuine environmental outcomes.
The recent announcement by the Australian government that it is committed to establishing a one-stop shop to reduce duplication and unnecessary regulatory burden for the offshore oil and gas industry will help to increase certainty and, thereby, investment.
What regulations were the results of Montara/Macondo, specifically regarding the environment?
Since Montara/Macondo, our environment plans have become more analogous to a safety-case approach demonstrating we have identified, evaluated and reduced environmental impacts and risks associated with a specific drilling activity to as low as reasonably practicable. We also have to show we are doing what we said we would do through a systematic and continuous improvement process. We have to provide extensive evidence of our decision-making process and the justification for those decisions. In particular, the requirements to demonstrate our oil spill planning and response capabilities are far more onerous, which is a step in the right direction.
As drilling prospects become more complex, how does Apache balance the need for operational integrity against the need to manage costs?
Safety and operational integrity are often portrayed as competing objectives to cost and production efficiency. However, world-class companies attain the best safety performance with the best production performance. The way you achieve both are the same – you need great people who are given clear accountabilities within an organization with a strong HSE culture and a clear strategic direction.
In October 2013, Apache’s CEO rolled out an operational excellence (OE) initiative. This is a companywide effort to improve performance in the areas that have the greatest impact on our success. OE is defined as optimizing operations while minimizing cost, adapting to dynamic business conditions, maintaining safe and environmentally compliant operations and ensuring asset integrity and reliability. It’s a model that guides us in what our responsibilities are and what our behaviors should be in each of these important areas.
We have to measure how we’re doing in each area and have plans for further improvement. This is one way we find the balance between achieving both operational integrity and business performance.
How is technology helping to manage the pressure of escalating costs?
Technology is an enabler, and we are using it to unlock resources in a cost-effective way. We are working with our service providers and partners more collaboratively than ever before to get an economic solution.
Successful technology implementations require careful candidate selection and detailed planning. You need to spend time with all the various disciplines to understand how you can add the most value. The key is getting as much information upfront as possible and having the time to plan that in a multidisciplinary way.
What progress has industry made in terms of gathering and interpreting information?
Apache uses the latest seismic technology to ensure prospects have the best chance of success for our exploration wells and obtain the best recovery rates from the fields that we develop. In conjunction with the seismic, we are using advanced LWD technology and multilateral techniques to assist in achieving the maximum amount of quality reservoir in our production wells. We are also using pore pressure sampling LWD and pore pressure prediction technologies to help us drill challenging exploration wells.
Are there any specific gaps in technology that the industry needs to improve?
Further advancements in liner- and casing-while-drilling technology would certainly add value to our operations. We’re using drilling with casing to allow us to drill through unstable zones and into the reservoirs to reduce costs in problematic areas; that’s been successful for us.
Advancements in solid expandable technologies and managed pressure drilling (MPD) are also areas of progress, but we think there’s more to be developed. I also believe we need to get better at optimizing the entire drilling system, getting the best out of all the components we design and utilize. I foresee where we will have closed-loop feedback systems that allow the information from downhole tools to be immediately integrated into the operation of the surface drilling package.
How has Apache incorporated MPD into its operations so far?
It hasn’t been utilized offshore Australia, to date. There are applications for it, not just for drilling efficiency but also from an operational and safety point of view. It can offer benefits in areas where you see overpressure formations, wellbore instability and lost-circulation zones. Some operators are looking at it, and I think it could benefit the industry here. I’m hoping to see it introduced in the next two to three years.
What advancements have been made in casing while drilling? What kind of impact has it had, and what effects do you hope to see in the future?
One of the important advancements is being able to directionally steer the drilling with casing assembly. I also envisage this technology improving drilling performance – being able to reduce the amount of time we spend tripping and running casing.
How long has Apache been using casing while drilling?
We have been using casing while drilling for more than two years. On our most recent Stag-44 infill oil well, we directionally drilled more than 1,800 meters (5,900 ft) with 9 5/8-in. casing. A retrievable rotary steerable system was used to build inclination from 27° to 90° and hold angle for more than 1,000 meters (3,280 ft). We were able to actively steer the assembly to avoid unstable regions and wellbore collision risks. This is a world record interval for this size of casing and is extending the life of our assets by developing parts of the reservoir that had been previously unattainable.
What are some of the main technologies that will enhance well control?
MPD can enhance well control by being able to accurately measure small reservoir inflows and react to them. I also see advancements in pore pressure prediction during the planning process and in real time being very beneficial.
NPT remains a constant issue. How can industry address it?
It starts with front-end loading the well planning process. We must identify, understand and manage our risks before we get to the execution phase. In the execution phase, it is about understanding the root causes of NPT or inefficiencies and being able to embed the learnings quickly into our operations. The issue of addressing NPT is not just technical but also organizational.
How does Apache measure NPT or track improvement?
We measure the time taken to perform each individual activity. Anytime we deviate from our expected time or the best time we’ve done before, we ask questions to understand why.
This process often takes the form of an after-action review (AAR), where we gather everyone involved in the operation to analyze performance and provide recommendations to improve.
What are the prospects of increasing deepwater production, specifically in Australia?
The deepest-water production offshore Australia is about 800 meters (2,625 ft), but it wouldn’t really count as deepwater given the definition today. Deepwater exploration continues with the challenge of being able to make the high-capital cost developments economically feasible.
Are the rigs available today in this region meeting your requirements and expectations?
Australia is a unique market, and our remoteness has a large impact on our business. There is a high cost of entry into the market due to large mobilization and relatively high operating costs. Therefore, once a rig is in Australian waters, it has a significant competitive advantage and remains in the area. We do have a number of the older units; however, some of the larger drilling commitments have secured newer units in the past few years.
Has the aging fleet affected your operations? What can drilling contractors do to help improve its rigs?
We’re able to work, but as far as their operational capability, we are pushing them to the limit. There are 30-year-old rigs drilling long step-out wells and running subsea developments, and now you have more people involved in your operations with more equipment. Deck and bed capacity needs to be carefully managed. A healthy collaboration between operators and drilling contractors ensures we are able to perform, but it requires planning.
One issue hindering our operations is infrastructure bottlenecks at our ports in the north of western Australia. It’s a very remote and isolated part of the country, more than 1,500 km (1,000 miles) from Perth, the corporate center of Australia’s offshore E&P industry. With all the development occurring at present in the oil and gas and mining industry, there’s a lot of pressure on the existing port facilities for our supply vessels.
Do you foresee infrastructure improvements? What is being done to increase capacity?
Some small steps have been made to improve port access; however, I believe it will remain an issue for the next two to three years until the high activity subsides.
How will the growing LNG markets affect the drilling market in Australia?
There are a lot of LNG developments being executed in Australia, so we’re right in the middle of a lot of development activity. On the east coast, three LNG plants are being built and more than 10,000 onshore wells are being drilled to supply these plants. This puts huge pressure on people and equipment availability.
The major challenge for continued growth in Australia is remaining competitive in the global market. With the rise of North American shale gas and the huge potential of East Africa, Australia has a lot of work to do to remain competitive. How successful we are with this challenge will determine our future drilling demands.