TOTAL looks to human factors to enhance well control training, technology value-adds to push the limits on complex, deep reservoirs
By Joanne Liou, associate editor
As vice president, drilling & completion, for TOTAL, what do you see as some of the most critical challenges confronting your operations today? What is being done to offset them?
The first challenge we see is the availability of qualified personnel. TOTAL has established a clear path of training for our personnel, and we have gone beyond industry standards on issues like well control training. We have developed, for instance, a proprietary course in well control called T-BOP that we crafted in association with the French Petroleum Institute (FPI), which is not limited to traditional aspects of well control training – kick detection, control or the well control equipment. It’s oriented toward addressing situational awareness, communication skills, decision making and teamwork during a significant incident.
We also established a competency assessment structure for engineers and our chain of command (COC), and we define COC as the companyman, the drilling superintendent and the drilling manager. Those three members of our COC follow a regular examination by an external entity, which in this case is the FPI.
For our engineers, we have fixed a competency assessment scheme, which consists of tests that our engineers pass after three years of seniority and six years of seniority in order to better establish where we have to put some accent on our training, not on technical training only.
The second challenge that we are seeing is that, in certain countries where we operate, following the Macondo incident, in particular, there has been some legislation that at times is unclear or badly adapted to what we have to do. We’re facing great challenges just to obtain a license to drill.
With the first challenge of the availability of qualified personnel, you stated that TOTAL is going beyond industry standards for training. Do you believe industry needs to raise standards across the board?
Recent incidents have shown that the industry, including ourselves, suffered. A plain calculation on how to control a kick or simple knowledge of well control equipment is not enough. There is a human factor associated with the wrong response to an incident.
In addition to that, your COC goes through regular examinations. How frequently do you reassess or re-examine your crew?
All of our crew must sit for regular well control training and test within validity of two or four years, depending on the position. The new assessment that is being followed by our COC with the FPI is only starting now. We developed it with the FPI in early 2012, and at the moment we are trying to put all our personnel through it. We haven’t fixed a frequency for the assessment yet.
With the industrywide shortage of personnel, how do you balance the time that you invest in somebody for training and assessment with the time you need them to be working on site?
That balance changes through the career of our drillers. A first basic training module, which lasts two years, is literally 100% training. In years three to five, they’re assigned to drilling rigs as night companymen. At the same time, either on their time off or through computer-based training, some complementary training modules are completed so we can say that in years three to five the balance would be half and half between training and operational roles. Starting in year six and on, the balance is more toward operational work than training.
Is that timeline efficient and timely enough to meet your needs?
It is well adapted to the portfolio of activity that TOTAL will allot. We have a large portion of our work that is carried out offshore, and working offshore, we have a large portion that is done in deepwater. We also have a series of complex activities in our portfolio like HPHT or extended-reach drilling, which cannot be learned overnight. The experience and know-how that we developed in HPHT wells in the UK cannot really be learned in one or two months.
Is it a challenge in itself of simply finding the manpower? Where are the majority of new-hires coming from?
We don’t have as many people as we would like to have. Our drilling activity is growing like everybody else’s, and we are struggling to follow this growth. We know that our industry will not have a constant growth; we’ve seen peaks and valleys of activity in the past. Our target is to be able to man, at any given time, 40 of our rigs with staff personnel, staff companymen, staff drilling superintendents, etc.
We have a large population database; around half of our staff personnel have a French employment contract and half have a local contract. We have two distinct populations within these two branches: engineers who are recruited straight out of university and technicians who are recruited out of technical schools, two years after high school.
Given the training time required to have an efficient companyman or a good drilling engineer, we have to cope with our growth with the recruitments we did several years ago. We are actively recruiting today to respond to a substantial growth in activity in the years to come.
TOTAL’s E&P activity spans more than 40 countries, and there are some regions that present requirements or legislation that may not be as practical or clear to follow. How can industry work with these governments to make these regulations more clear and implement and follow them?
It’s based on education. For instance, there are certain countries that now are adopting legislation for treatment of drilling cuttings that is probably outdated and not adapted to the drilling fluids we are using today. We know that if we treat our cuttings by shipping them onshore, all the movement of containers and vessels generates risk that is probably much higher than simply dumping the cuttings to sea because today we are using drilling fluids that are extremely environmentally friendly.
This legislation was adequate when OBM was prepared with diesel, but it’s not reasonable when we’re utilizing OBMs that are prepared with oils that are absolutely environmentally friendly.
Legislation is much stronger in certain countries like Russia or the US or France or Norway. It’s not the case in every country. TOTAL has its own set of standards beyond API standards, and we apply our standards or the standards of the country where we work if they are more stringent than ours.
Are there any limitations that are holding back TOTAL’s goals for its drilling and completion programs?
Yes, in fact, if we look at the main index by which we measure our performance, which is NPT, we’re seeing issues of reliability on well control equipment for subsea drilling, which means we spend a lot of time bringing the BOPs to 100% functional status. Same goes for pipe-handling equipment and systems, top drives – we see a large time spent repairing failures of these equipment.
In which area is the gap the widest, with the most impact on your operations?
By far, subsea BOPs. In 2011, we spent more than 200 days repairing BOPs. Maintainability is part of the issue, but a large part of the problem we have is due to the complexity of the system. Subsea BOPs have become a very sophisticated piece of equipment especially considering the environment in which it is working, and we have reached situations where we had trouble actually finding what was the source of the problem on the BOP. It’s also related to availability of spare parts, frequency of maintenance, training and competence of the personnel who work on the BOP.
What can drilling contractors do specifically for subsea BOPs?
I think a drilling contractor can address the issues that are under his control. That is establishing proper maintenance plans, having required stock of spare parts, training the personnel who do this maintenance. There are some other issues that are up to the manufacturer of the BOP to address. When it comes to the design or the complexity of the tool itself, the drilling contractor is as much a victim as we are.
Are there any other concerns that you have on the equipment side?
Automatic pipe-handling systems was a trend that started in Norway to move people away from the pipe handling in order to improve safety. Now we’ve seen recent presentations comparing safety statistics in Norway and the UK sector of the North Sea, with similar results despite the UK not having such a strict rule on automatic pipe handling as Norway has. We see that not only are these systems not as reliable as we would like but also when they don’t work, it is almost impossible to revert to semi-automatic or manual pipe handling.
As with the BOP, the drilling contractor can ensure that a proper maintenance program is carried out with pipe-handling systems, ensure that it has the required level of spare parts, and its personnel is properly trained to do the maintenance. Again, when it comes to design, it goes back to the manufacturer, and again like the BOP, operator and drilling contractor are in the same boat.
As a global company, you are operating in the North Sea, Africa, the Middle East and elsewhere. Is there a particular region that you see as more promising than others?
Significant investments follow the exploration successes. We will continue making significant investments in West Africa, the North Sea, the Far East and maybe East Africa. Having said this, we are seeing today what our managers told us 10 years ago: Easy oil and gas is not for us anymore. We have been preparing ourselves to explore and develop unconventional resources, gas and oil in deeper waters at higher pressure and temperature.
Irrespective of location, we are better accepted where we can add value, specifically technical value, i.e., when the resources are located in deepwater, when the resources are in HPHT conditions or when we have to do extended-reach drilling to reach these resources. We are also better accepted when the reservoir has lower productivity. We therefore invest great efforts in finding ways to produce the hydrocarbons in unconventional conditions.
As operations shift more toward complex wells, we push the limits in water depth, burial depth, and extreme temperature and pressure conditions, as we have just discussed. Do you see these challenges as something that the industry will be able to meet? How is TOTAL meeting these challenges?
If we have access to exploration plots in deeper and deeper reservoirs or in more challenging conditions, we will find a solution. The industry has been doing that every time. HPHT, in particular, remains a frontier technology, and it makes us review all or many of our standard practices.
We probably don’t understand today everything that relates to the aging of steel, aging of casing under HPHT conditions, especially in a corrosive environment. We have to work with chemicals or, for instance, brines that can be mixed to very high densities and still be non-corrosive or non-toxic.
Taking into consideration these more complex challenges, how is TOTAL working with drilling contractors to help meet these challenges and improve your operations?
There are several aspects where we work together with the drilling contractors, not all necessarily focused on the technique but also focused on the safety. For instance, whenever we start a new HPHT well in the UK, we go through a pre-drilling training of the crews that will be working on our well.
We also have established a compliance monitoring system that we call DrillSafe, by which specialists from our team in headquarters pay visits to each of the rigs that starts to work for us in a particular operation and verify compliance with our “Referential,” or company management system, in particular with regard to well control equipment, well control procedures and all the systems associated with well control.
We occasionally detect problems on the rig or the construction of the rig that are new even to the drilling contractor. Through these inspection visits, for instance, we have found older-generation rigs that had lines that were supposed to go overboard to divert out a gas kick which were, in fact, misrouted, and lined up the drainage of rain water on the rig.
In another example, we found a sixth-generation semisubmersible that had a design problem in the choke manifold by which all the piping was concentrated into a single point that, if failed, we would have completely lost the choke manifold in a single-point failure.
Are the rigs that are available today meeting your needs and expectations?
We have never reached a situation where we couldn’t drill a well because there was not a capable rig available or a rig technically capable of doing the work. If you want to drill a well that has 20 km of horizontal departure, it’s not only the rig that doesn’t exist, it’s the technology. For the portfolio of drilling activities of TOTAL, we have always been able to find in the market a rig that could do the work.
The rigs are available, but are there specific areas or components that need improvement on these rigs?
In certain parts of the world, for instance in the GOM, it would be good to have 25,000-psi working pressure well control systems or BOPs. This is not readily available. It’s probably one of the aspects the industry will have to address if we continue going deeper and deeper.
We have identified other tools that we need or equipment we need. For instance, we know that if we want to expand HPHT or combine HPHT and subsea development wells, we will need a new type of subsea wellhead that gives access to the annular, and we know that it doesn’t exist in the market. However, in this case, we’re referring to a component or a piece of equipment that is not a drilling rig or rig component.
How does TOTAL balance the need for operational integrity within the company against the need to manage costs, particularly in deepwater operations?
Operational integrity and cost management go hand in hand. Within TOTAL, the backbone of operational integrity is our company’s Referential – a set of company rules, specifications and manuals. TOTAL has developed a number of company rules and manuals that document our experience and the industry’s experience. Today we have around 450 or 500 company rules by which our colleague drillers in the field have to abide.
When our engineers are faced with a situation where compliance with a company rule will entail costs that can possibly be saved while keeping risk to an acceptable level, they study the issue and can prepare a formal dispensation file identifying the mitigation measures that are proposed to satisfy safety requirements while not abiding with this particular company rule.
This file is sent to a group of senior specialists who review it and issue a recommendation to myself. I take the final decision to accept or not the requests for dispensation. This system has been in operation for many years in TOTAL drilling operations and has proven to be pretty efficient to minimize costs while taking no compromise on safety objectives.
Are you making use of remote operations centers to manage your drilling/completion operations?
It has never been very attractive to TOTAL. While the cost of remote operation centers is clear, the benefits are not really obvious to us.
TOTAL remains a very decentralized drilling team, and in headquarters, we have a more support role to our operations in the field. We still believe strongly in empowering our COC and engineers on site, and the support we provide from headquarters is ad-hoc support on certain fields of expertise, which could be testing or cementing or rock mechanics. In addition, we have a team of experts in headquarters who are ready to be mobilized should an operation become critical in an affiliate.
In 2013, what are some of the new challenges that you’re encountering when drilling and completing your wells or in well intervention?
What we’re seeing clearly in 2013 is another period of growth with all the associated challenges. We’re seeing a larger proportion of untrained or insufficiently trained personnel. We’re seeing growth in the activity of equipment suppliers, which they’re struggling to respond to. We’re seeing delayed delivery times and a drop in quality.
We’re also seeing opportunistic rates from our drilling contractors. These challenges – personnel, quality of delivery by suppliers and the opportunistic market rates – are symptomatic of a period of large growth.
On the technological side, have there been any innovations you’ve come across in the last year?
From the last three years, the one technology that has had the strongest impact on our capacity to deliver is the MPD system that allows us to safely deliver wells that were not feasible some years ago. Now we can drill through narrow mud weight windows and without the problems we had in the past.
Do you foresee MPD playing a bigger role in the coming year?
Yes, MPD has become or will become an unavoidable tool for any operation on a HPHT well, where we drill very close to the limits. Everybody involved in HPHT drilling will have to use MPD if they want to reach the limit.
It’s a big system. It’s expensive; it’s complex. I suppose like every new technology or technique, it’ll just get simpler, cheaper and smaller.