JIP aligns vision across different sectors of industry to produce step-change technology to be deployed in 2013 in Gulf of Mexico
By Joanne Liou, associate editor
From your point of view, what are some of the most critical issues that the industry is facing?
On the technology side, I’m very focused on deepwater, and specifically dual gradient drilling (DGD). I work in the Gulf of Mexico (GOM), where we are drilling challenging wells, some of the most difficult in the world. Our wells are typically subsalt in 4,000 ft to 8,000 ft of water and range from 25,000 ft to 35,000 ft in depth. We run into extremely heavy casing loads, and seven to nine strings of pipe is the norm.
These wells are characterized by relatively high pore pressure uncertainty. We are frequently trying to navigate really tight fracture and pore pressure windows. Much of that is simply because of the pore pressures involved in the GOM, but the tight clearances that result from so many casing strings also create high equivalent circulating densities (ECDs). That works against us while we’re drilling and while we’re cementing.
So, our battles are largely driven by these pressure challenges, which is why we’ve been working on DGD. In our dual-gradient (DG) world, we look at it as two technologies – one is DG, which is the creation and management of two different density drilling fluids in the wellbore, and the other is managed pressure drilling (MPD), which is the active management of the annular pressure profile.
Do you foresee DGD and MPD playing a more prominent role as industry continues its path to deeper waters?
These two technologies have different, yet complementary, benefits. MPD is a broad category of applications that combined will have a very prominent impact on the industry. We believe that some of the simplest MPD applications will become as common as top drives over the next decade. DG is a highly focused subset of MPD.
DG, where we maintain the two pressure profiles in the wellbore, allows our wells to be designed differently. In fact, they are designed much more like they are onshore wells because we’re able to take away the impact of water depth on well design. The MPD capabilities of the DG system allow us to deal much more effectively with ECD and pressure uncertainty.
With DG, we maintain a seawater density column in the drilling riser next to the seawater in the ocean. We use a higher-than-conventional density mud below the mudline next to sediments. In other words, we’re more in harmony with the pressures created in nature. In conventional drilling, we have to use a mud weight that is in between seawater and the sediment density, and in comparison to DG, we’re significantly overbalanced in the top part of the well.
For example, near the mudline, we actually have much more hydrostatic pressure in the mud column than is needed to control pore pressure. At the TD of that hole interval, we are finally where we want to be. If we can stay more parallel to the pressure that the increase in the load of sediments imposes on us, then we’re comfortably within a pore pressure/fracture pressure window for a much longer hole interval.
The Pacific Santa Ana arrived in the GOM in May and is on a five-year contract to Chevron. What is the status of the DGD project? What are you expecting in 2013?
The Pacific Santa Ana is drilling its first well, but it is not DG. It is expected to finish in early 2013. At that time, we’ll load the DGD equipment on the rig and drill another well that’s not DG. While the second well is being drilled, we will be hooking up and commissioning the equipment. If all goes well, we plan to deploy the DGD equipment on the following well in mid-2013.
We’re using the technology we developed in a joint-industry project (JIP) from 1996 to 2001 called SubSea MudLift. GE Oil & Gas owns the core technology, now called the MaxLift 1800 Pump. In the test well we drilled for that project, we were delighted with the amount of control we had over the pressure profile on the well and our ability to pick up kicks and changes in downhole conditions. Everything we were hoping to see, we saw in that test well, and there’s no reason for us to believe that our future wells in the GOM will be any different.
What objectives do you have with the DGD project?
Our nearest-term objectives are to replicate and exceed what we were able to accomplish in the JIP. We have our own views of how this should evolve, and we’ll take it a step at a time. The first step is to maintain a DG profile between fluids and to get the rig and the crews comfortable with managing two fluid systems. Then, we’re going to be focused on navigating the narrow windows between formation pressure and fracture pressure.
Based on the potential success of this project, what kind of implications will DGD/MPD have for the future of deepwater?
We’ve seen conventional, single-gradient MPD grow very quickly onshore. We’re seeing it start to creep into the offshore world as well with surface rotating control devices (RCDs), but it still hasn’t begun to approach onshore acceptance levels. We’re really just getting started. This is the first subsea MPD/DGD operation. Assuming that it does perform and gives the benefits as we’ve seen onshore, it has the potential to grow quite a bit.
Offshore is a very tough, very high-profile and very expensive environment. Tools that dramatically improve performance are embraced, but it’s a journey. It is not simple, and it takes a long time to get the equipment fully integrated into the rig. It also takes a long time to get your people prepared for it, so it is not a trivial investment at all in either capital or in personnel preparation.
A lot of your work takes place in the GOM. Should the GOM be a standard starting point for the industry to try these new technologies or to establish standards?
That’s the reality for DGD but not necessarily a starting point for other new technologies. We’re the first ones to commercially deploy a DG system, and we know that many are watching us. There are a few other DG efforts out there, but Chevron is the first to actually step up and do it. We’re effectively removing one of the big uncertainties for others, and that is much of the technical risk.
The risks associated with deploying new technologies, such as MPD and DGD, often inhibit or slow the process of moving forward with new technologies. How do you balance risks with the need to try something new?
There’s a lot of natural reluctance to be the first to do something that feels uncomfortable because, as engineers, we’ve become very good at finding creative ways to push the technical solution envelope just a little further. That’s one reason why we have all these customized casing sizes, so we can squeeze in another string of pipe. When you do something like DGD, this isn’t a tweak to what we do anymore. This is a radical change, a step-change in deepwater drilling technology.
Fortunately, we have visionary leadership, and they basically said, “We are a deepwater company. We have deepwater leases all over the world. Eventually, we’re going to run into a technical limit where we just can’t go any further unless we change the game.” We view DGD as the game-changing technology that allows us to safely participate in the deepwater beyond where we can today.
This senior-level support is helping drive DGD forward at Chevron. Is that a discerning condition that industry needs to progress new technologies?
For the step-change, the major technological improvements, you have to have executive leadership that is willing to accept the challenge. We get recognized when we fail, and it’s not good recognition, so someone has to say, “We understand the challenge, but the prize is worth it. We want you to try.”
All of our business partners involved in this project, including Pacific Drilling, GE and AGR Subsea, share that vision. For all of them, it’s the kind of thing that differentiates them from their competitors, and it drives them to succeed. That drive is critical to our success.
The Pacific Santa Ana was specifically tailored to the project. What specifications went into this rig?
The original Pacific Santa Ana design was fairly well established, so there were a number of significant changes that we were able to get in while it was at the shipyard. A number of things have been done since it left the shipyard.
The upgrades were concentrated on the fluid management systems, the power distribution systems and pump-handling systems. In our DG system, we use a positive displacement pump, which sits above the lower marine riser package (LMRP) and the BOP. Above the pump is where we put the subsea-rotating device. The pump is driven by seawater.
From a rig standpoint, we manage three fluids – the riser fluid, the drilling fluid and the seawater. All those systems have to be segregated, so most of the modifications were in segregating the systems.
The Pacific Santa Ana has six high-pressure pumps – three for mud and three for seawater. Those elements lead you to understand more power distribution is important because these are all big mud pumps, and they require the power and the segregation of power sources.
On rig specifications and capability, are the drilling rigs on the market today meeting your needs?
Yes, our wells are 30,000 ft to 35,000 ft, so we use the biggest rigs we can find. Our rig sizes are primarily driven by how much weight we have to pick up, and there are not that many rigs that handle 1.7- to 1.8 million-lb hookloads. For rigs in our market, most of those rigs would be adaptable, with some significant expense and planning, to go bigger.
Working with drilling contractors, do you foresee this equipment becoming standard rather than adapting or adding on to a rig?
Perhaps, with time, it is possible. The pump is currently about 450,000 lbs; that’s about the same size as the BOP. It’s not something you can pick up and throw on the rig. With time, I believe we’ll see the drilling contractors become the ones that buy and install this equipment as opposed to needing an operator to take the role we’ve taken in this particular project.
Although the Santa Ana was especially tailored for the DGD/MPD project, do operators appreciate consistent rig designs offered by drilling contractors?
The Pacific Santa Ana is still built on a fundamental hull class, which is consistent with many other rigs in the global drilling fleet. It’s one element that lowers costs for drilling contractors and can ultimately manifest itself in lower dayrates. It also makes it easier and safer for rig crews to move from rig to rig.
What technical limitations are holding back the goals you have for your drilling programs? In what areas are the gaps the widest?
We, as an industry, are always pursuing something that is either safer, more environmentally sound or more effective at drilling the well and completing the well. The gaps differ around the world. In the deepwater GOM, it’s getting down to weight and pressure because we drill really deep wells there. In the North Sea, the wells are not nearly as deep; they’re getting more focused on costs and managing pressures in depleted fields. It’s a very mature basin. We see a lot of interest in the North Sea for MPD technology, but their drivers are different.
When we originally participated in the JIP in the late 1990s, our thought was this would become a way for us to get smaller rigs into deeper water because it would take a lot of the load out of the drilling riser. Now, most of the smaller rigs have left the North Sea, so we don’t worry about that driver as much. For other areas of the world, that actually may remain a valid driver.
Do you see JIPs as a way to develop and push forward new technologies? What was the significance of this project starting from a JIP?
With these fundamental, game-changing technologies, you have to have industry consensus, or at least a subset of the industry saying this makes sense in order to pursue it. A JIP provides this shared view.
We’re not just developing a technology; we’re developing a segment of the industry that doesn’t exist today. You have to have a market. If Chevron were the only potential customer, there would be no reason to do that. The market needs to have the hope and the vision that this is something that many others will embrace.
For Pacific Drilling, why would you maintain one rig that does this for one customer? It restricts them too much and makes it harder for them to market their rig. You have to work to develop some sort of industry vision for these step-change technologies.
The regulatory framework for DGD is not firmly established, so another key stakeholder in the project is the US Bureau of Safety and Environmental Enforcement. All these things have to come together to make this a longer-term success. Nothing is sustainable if we simply build a system and consider ourselves done.
When you were developing DGD, what challenges did you encounter that could pose as challenges in future projects?
We had operators, drilling contractors, manufacturers and service companies all working together for a common purpose of doing something fundamentally different. We called it the Riserless Drilling JIP, and we thought our goal was to try to get rid of that big drilling riser that seemed to be the thing that kept rigs from getting out to deeper water.
We knew that we needed to establish something managing water over mud. We knew that we needed to develop both the hardware and the procedures to use it. We also knew that we had to develop the basis for sustaining the technology after the JIP was over. So the common vision of where we needed to ultimately go was vital. We had to develop a “complete solution” in order to get there.
Over time, the JIP morphed into something we called SubSea MudLift. We thought the biggest challenges were the hardware; it turned out that equally as challenging was developing the people. DGD is so fundamentally different from conventional drilling that people have to unlearn what they know.
For example, starting on the rig floor, when we say trip out a hole, our crews know exactly what to do. They have done it a thousand times. But when you say trip out of a hole in DG, they’re thinking, I have two trip tanks; one’s for the riser, and one’s for the well. How do I manage that? What does the tripping schedule look like?
It’s not hard, but it’s different. It took a long time to describe what’s different and translate it into procedures that our people can follow. In the JIP, we estimated in the range of 12 to 15 man-years of effort into the procedures, especially into the well control procedures. We’ve probably put in another 12 to 15 man-years of effort since then within this current project.
Again, operators, drilling contractors, manufacturers and service companies all had to work together to make that happen. We became very aware that not one of us could have done this alone; it took all of us.
What implications will subsea MPD/DGD have on well control?
We have the pump on top of the BOP and the LMRP and the RCD right above that, so we are pumping mud into the closed well volume and pumping mud out of it – absolutely in sync with each other.
Since it is closed volume, if anything happens at all – for instance, if we lose circulation or we take a kick – we immediately pick that up as a change in pressure in that volume, and we can immediately react to it. When we were doing the JIP well in 2001, we tried to introduce pseudo-kicks into the well without informing the driller, but we could never get more than about 1.5 bbl to 2 bbl into the well before he would pick it up and respond.
We anticipate similar sensitivity with this newer system. Consequently, kicks should be smaller, lost circulation should be picked up faster, and we will be able to make adjustments in pressure more quickly than with conventional drilling. Events that could potentially become big should become less significant. You can’t avoid kicks and lost circulation, but we’ll be able to detect them and react to them more effectively.
How will this MPD/DGD technology affect the progress of automation?
It’s critical. For instance, our subsea pump is totally automated. It maintains a constant pressure at the mudline while we’re changing mud pump rates on surface. We do not manually control that pump at all because it’s not possible to manually control a pump pumping mud out of the well and manually control a separate pump pumping into the well and keep them totally synchronized.
We’ve gotten comfortable with computers playing a more and more important role in our wells. For us, we’re taking it one step further by automating a pump, but automation is always getting more and more footing in our industry without thinking about it. Computers don’t sleep or get tired. They perform consistently.
Equipment reliability has become an even bigger issue since the Macondo incident. Are you concerned that equipment vendors are not meeting your expectations in reliability?
We do have some areas of concern with regard to reliability, and we never take it for granted. Equipment robustness and reliability have always been tremendously important for operators, drilling contractors and the manufacturers, long before Macondo.
The safety of people and the protection of the environment have always been first boundary conditions of our work. That is what drives most of the assurances that we use to design, manufacture, test and install the equipment. Third-party inspectors and certifying verification agents are used in every step of the process. That establishes a robust design and well-built equipment that meets the needs.
Reliability is further achieved through redundancy. Our goal is to ensure that once the equipment is run, it is able to stay down for the duration of the well, performing at the level needed. You achieve that through a combination of reliable parts that should be able to run the distance, but then you back that up with redundancy, in case one fails. And you back that up with robust contingency operational procedures that provide for failures. Finally, you must have a robust maintenance program in place to maintain that reliability and performance.
As an example, our pump is six chambers, but it will also run as a five-chamber pump, a four- and a three-chamber pump. A lot of things can fail, but we can still pump. That same sort of redundancy is in our computers, the umbilicals and the power system. But if all else still fails, we have operational procedures to ensure that we can maintain the well in a safe condition until equipment is repaired.
Reliability is not just about the equipment though. With DGD/MPD, it’s a tremendous investment, not just in money to buy the equipment and modify the rig but in the people as well. Today, it’s hard for us to envision this being something that’s like an occasional drilling technique, where you’re going back and forth between DG and conventional drilling. It’s just too much effort to get it in place. Once in place, our view is that the Santa Ana will be a DG rig. Not every well benefits as much as other wells from DG, but that’s OK. The technology will almost always add something in terms of benefits.
The people may be able to go back and forth, but it won’t be comfortable for them for a while. If you’re from the US and you drive in the UK, you initially feel uneasy until you make the transition to driving on the left side of the road. When you return to the US, you’re uneasy again, although the transition will be faster. There’s a time period that you need to adapt to whatever it is that you do. Over time people might be able to easily shift back and forth, but initially we want to focus on learning and becoming comfortable with DG.
How are drilling costs affected by new technology, such as DGD?
We always work to find ways to bring down costs without compromising safety or environmental protection. We develop the easy reservoirs first, but eventually the challenges increase, the costs go up, and we can no longer afford to develop the reserves. Technologies such as DGD are essential to successful development of these more challenging reservoirs.
As our leadership said, “We are a deepwater company. This technology is needed to take us where we need to be.”
MaxLift 1800 Pump is a trademark of GE Oil & Gas.