Jim Redden, Contributing Editor
Once the bane of offshore exploration, the subsalt has turned the other cheek, albeit grudgingly, and has emerged as one of the most fertile drilling theaters in the world.
Despite announcements of world-class discoveries ostensibly coming one after another, the massive subsalt plays in the deep and ultra deep waters of the Gulf of Mexico, Brazil, and elsewhere remain somewhat enigmatic with a host of technical challenges one British executive likened to “putting somebody on the moon.” Advances in seismic imaging, vibration-resistant downhole assemblies, steerable drilling systems, and other new generation technologies have helped level the playing field to an extent. Nevertheless, in an arena where well depths can exceed 30,000 ft (9,144 m), well-control problems related to imperceptible pressure regimes, the unpredictable incursion of tar that can slam the brakes on a drilling program, and excessive BHA-wrecking vibration are among the difficulties that make subsalt exploration one of the industry’s most technically demanding ventures.
Riaz Israel, Schlumberger senior drilling engineer, Drilling and Measurements, accentuates some of the obstacles operators must overcome before the copious reserves below the salt can go into production.
“One of the most unique and problematic characteristics of salt is its ability to creep or deform. As a result, this introduces major challenges to drillers including managing the creep while drilling, (running) casing, and carrying out post-cement work. Drilling salt also has proven to be a high shock and vibration environment and so the BHA must be designed to survive throughout the drilling. Directional drilling, including maintaining vertical, has proven to be challenging since the natural tendency of the salt is often counter to the desired trajectory requirements, while conventional slide steering has proven inefficient in the salt. Finally, the salt body attenuates seismic waves making imaging the salt difficult, thus introducing large uncertainties regarding the boundaries of the salt body,” he explains.
Even so, operators clearly see the likely rewards as sufficient compensation for the technological hurdles. While the industry has long known that the salt deposits entrapping many deepwater formations are the source of considerable hydrocarbon reserves, as late as the mid-1980s most industry pundits believed the commercial potential in the Lower Tertiary and other zones below the salt was not worth the technical and economic hassles. There even was a time when operators drilling on the shelf attempted to avoid salt by drilling around it. Ironically, the earliest subsalt wells in the deepwater GoM actually were the result of happenstance when operators accidentally penetrated tabular salt while drilling to test anomalous seismic reflectors they believed to be hydrocarbons.
But, the times they are a changing. After sporadic starts and missteps, the industry today has identified enormous oil and gas reserves below the salt in not only the deepwater GoM, but in Brazil, West Africa, the Middle East, the North Sea and, to a lesser extent, offshore Eastern Canada. The deep subsalt discoveries in the outer fringes of the GoM rank among the largest finds in the world. The BP Atlantis, Mad Dog, and Thunder Horse developments in up to 6,000 ft (1,829 m) of water, the Chevron Jack II well drilled to 28,175 ft (8,588 m) TD in 7,000 ft (2,134 m) of water on Walker Ridge, and, more recently, Shell’s record-setting well in its Perdido development in 9,356 ft (2,852 m) of water and others have helped fuel renewed optimism on the potential of the deep and ultra deepwater GoM.
In November 2007, Brazil’s Petrobras generated a nationwide celebration when it announced its Tupi subsalt discovery in Santos basin held recoverable reserves of up to 8 Bbbl, making it the world’s largest find in the deepwater. Tupi was followed in January 2008 with the nearby Carioca subsalt discovery, which the head of the country’s National Petroleum Agency somewhat prematurely proclaimed held recoverable reserves of up to a staggering 33 Bboe – an estimate Petrobras has steadfastly refused to confirm or deny.
Brazil Mines and Energy Minister Edison Lobao has said while drilling the subsalt is expensive, its operators have little worry about absorbing dry-hole costs. “When you drill a well, there is a risk you won’t find oil. In Brazil’s subsalt region, there isn’t this risk,” he was quoted as saying late last year.
Though Brazil’s Petrobras helped pioneer deepwater exploration, the operator has little experience in dealing with the unique challenges of the subsalt, says one service company engineer with extensive experience in the country. “Brazil is a hot spot and it seems they announce a new subsalt discovery practically every month, but unlike in the GoM they do not have a lot experience there (in subsalt). They have a lot of issues.”
Those “issues,” however, are not confined to the less experienced. Operators in the GoM, many of whom are comparatively old hats in subsalt exploration, still must deal with obstacles that can tax even the most technically savvy. One of those is maintaining well control in an environment where the potential hazards unique to the deepwater are compounded with uncertainties in salt and subsalt sections.
Well control at the forefront
“With these projects you not only have deepwater issues with equivalent static density (ESD), low frac gradients, trip gas, and kick circulation, but also the unknowns and kick tolerance challenges of the subsalt. These have really brought well control issues (in the subsalt) to the forefront,” says Fred Ng, manager of well control technical services for Wild Well Control Inc.
Chris Scarborough, well control specialist for Boots & Coots, agrees, saying that a well control event in this environment easily can cost between $5 and $20 million, given spread costs exceeding $750,000/day. While technological advancements have helped mitigate some of the limitations, both he and Ng agree that the key is altering the mindset of drilling practitioners. This is particularly true when it comes to penetration rates, especially when entering and exiting the salt where pressure differentials of more than 2 ppg have been observed from the top to beyond the base of the salt.
“Basically, this is a planning issue,” Scarborough says. “To a lot of people, the philosophy is to turn to the right as quickly as possible. That does not apply here. I liken it to driving a car. If you back into a mailbox at 3 mph you’ll do little damage. You back into it at 80 mph and it is a totally different story.”
“Drilling into the top of salt may present risks of wellbore stability,” adds Israel. “Reducing the ROP and/or weight-on-bit (WOB) when approaching the top of salt allows drillers more time to interpret and react to these potential risks prior to entering salt. A gamma-ray measurement within 10 ft (3 m) of the bit is a useful lithological confirmation that the change in drilling parameters can be correlated to the top of salt.”
Since salt has no intrinsic strength, differential pressures can cause it to move through sediments over time, eventually causing the surrounding rock to fail. Unfortunately, the structure and stratigraphy of salt and subsalt deposits are difficult to interpret from seismic images, which some have compared to a snowy television picture. When operators exit a salt body they all-too-often encounter this weakened underlying basal shear zone, more commonly referred to as the rubble zone. Within this environment of failed rock, the risk of severe lost circulation and stuck pipe are compounded by pressure regimes that are all but impossible to foretell with seismic or offset experience, making controlling ROP a priority.
“With the uncertainties, you don’t want to come screaming out of the salt and hit a low pressure rubble zone or a high pressure sand and have all this salt open. It’s always best to sneak through there (rubble zone) so if you do have losses, you are able to get back into the salt, cut your losses and set pipe. From a well control perspective, it makes it a lot easier to play the game when you don’t have a long open section, whether it’s salt or formation,” Scarborough says.
That’s why Boots & Coots recommends the shoe be installed as close as possible to the base of the salt. “The pressures increase the further you get away from the shoe, so from our perspective, you want the shoe as close to the bottom of the salt as possible. Consequently, when you do encounter rubble zones, pressures, and other challenges below the salt you don’t have a long open-hole section. Instead, you have it contained with steel that has a known burst rating. However, when you have a long open-hole, just because the shoe test read 14 ppg doesn’t mean you won’t drill 600 ft (183 m) and hit 8 ppg or, conversely, 16 ppg,” he says.
Despite improvements in seismic, including 3D prestack depth imaging, today’s technology makes mitigating the drilling risks a difficult proposition. Schlumberger’s Israel says further improvements in subsalt imaging capabilities are on the horizon, driven in large part by complex geology and the emergence of the Lower Tertiary play in ultra deepwater.
“Large uncertainties still exist, due to limitations of the time-depth transforms being used in managing issues with formation anisotropy. New methods are being developed to further refine the subsalt image that will significantly reduce the drilling risks. These improvements will help to improve the pre-drill positional accuracy of salt inclusions, base of salt (and dips), better image rubble zones, and reduce the pore pressure uncertainty below salt,” he says.
In the meantime, operators have limited knowledge about the pressures they will encounter upon both entering and exiting the salt, especially in exploratory and appraisal wells. Beyond the base of the salt, the real risk of loss circulation is a hydrocarbon kick, which often renders a completely unstable wellbore. That multiplied by uncertain pressures that often force prudent operators to err on the side of caution.
“In many spud meetings, operators have to decide what mud weight they’ll use for exiting the salt. That decision is more critical in exploratory and appraisal wells where little offset wells information is available,” says Ian Thomson, GoM deepwater operations applications engineer for Hughes Christensen. “If they go with a higher mud density, losses are likely, but if they go lighter they run the risk of taking a kick. So, they have to decide what would have less impact to the operation and AFE, take a kick or lose fluid. Most of the time they’ll choose the latter. Pressures can not be predicted accurately, so the tendency is to go with a higher mud weight, sometimes as high as 90%-95% overburden gradient, and apply relevant salt exit strategy to minimize or mitigate any potential mud losses problems. On the other hand, if they take a kick, aside from the safety issues and depending on the experience of the rig crew, it could take forever to control.”
Those uncertainties also can provide dubious readings on the rig floor that often causes the crew to react improperly. For example, unlike water-based muds, synthetic-base or invert emulsion drilling fluids compress with depth, meaning the shoe could test pressures of 16-18 ppg while compressibility will bring the actual pressure closer to 21 ppg, Scarborough says.
To lessen the impact of those ambiguities, Wild Well Control employs proprietary modeling software developed by Norway’s Rogaland Research Institute and adapted for well control that provides real-time modeling of the full dynamic behavior of the wellbore and its contents. The complete time transient multi-phase flow simulator, which can be updated as drilling conditions change, simulates kick behavior and “can display 12 hours of circulation in a matter of seconds,” says Wild Well Control’s Ng.
He says the reaction of rig crews to oil versus water-base mud readouts does not come as a surprise. “Most people when they are trained in offshore well control are trained in shallow water with water-based mud.”
Avoiding impact of tar
The drilling and well control problems operators must confront do not go away once they leave the rubble zone. A major culprit is omnipresent bitumen or tar, which like pressures cannot be detected until it is penetrated and once that happens it literally “can plug anything and everything,” says Scarborough.
“Apart from balling the bit and the bottomhole assembly, tar can pretty much ruin your entire drillstring and some of the rig surface equipment,” adds Thomson. “You can get into a very sticky situation with very high torque and friction. That’s the point where you really cannot progress anymore.”
Extremely viscous and often rich in high molecular weight asphaltenes and frequently sufficiently mobile to flow into the wellbore, tar literally can put the brakes on a promising drilling operation. The presence of highly mobile bitumen on BP’s Mad Dog development in the Lower Miocene even led the operator to try “mud coolers” in an attempt to mitigate the impact of tar, which is active under high temperature.
“Operators have tried everything to lessen the impact of tar. The problems are that there is no way to predict exactly where a tar zone is, how thick it may be, how active it is, or even if you will hit it. We do know it usually comes after the rubble zone, but it could be 1,000 ft (305 m) below or, in some cases, 5,000 ft (1,524 m) or more below the base of the salt. Once you realize you have hit tar, the wise thing to do is get out of the hole quickly and set a cement plug,” Thomson advises.
Once the hole is cemented, he says, operators have no choice but to cross their fingers and hope they miss it with a sidetrack. “What they do is sidetrack and hope they can miss it and go on to TD. But, what happens is they sometimes sidetrack and hit the tar zone again. Then, they cement, sidetrack and hit it again. There’s a point where they cannot keep sidetracking.”
Thomson says Hughes Christensen’s patented casing/liner drilling system incorporating a premium liner drilling PDC bit has proven effective in drilling and isolating tar in the deepwater GoM. In one application, a Liner Drilling polycrystalline diamond compact (PDC) bit, which is preferred for subsalt drilling, was run on a 10 ¾-in. liner to drill and isolate a troublesome subsalt tar zone. The tar zone had caused the operator to sidetrack a previous well twice trying to avoid hitting the tar.
“After hitting tar the first time, operators have a pretty good idea where the top of the tar zone is, so they can sidetrack, drill ahead to the top of the tar zone, pull the drilling BHA out of the hole, and then pick up the (liner drilling) system and the liner bit and drill through and isolate the tar zone. Depending on the casing schematic, when you isolate the tar, you are setting an extra string of liner that was not planned, but sometimes that is the only way to do it,” Thomson says.
Ideally, the best alternative is to avoid it altogether, but when that is not possible, getting in and getting out quickly is the preferred option, says Gerry Authement, sales team leader for Baker Hughes Drilling Fluids. “After the tar has been stabilized, drilling of the tar section should be completed as quickly as possible as tar stability may be time-dependent. Typically, tar is not in large sheets, so sidetracking around it should be considered if possible.”
Technologies help mitigate vibration
Then, there is the matter of excessive vibration, which is magnified in the subsalt where operators routinely employ reamers to maintain the programmed hole diameter. “Most of the time, they drill the salt with reamers and we notice a lot of vibration upon the exit. What happens is the bit is in the rubble zone while the reamer is still drilling the salt. This potentially can cause a great deal of vibration, due to weight transfer issues, stabilizer hang off, difference in aggressiveness of bit and reamer, or a combination of all. Most of the time you can drill pretty fast in the salt, but sometimes you have inclusions that might induce severe vibrations, particularly when using reamers,” Thomson says.
Israel adds that while pre-drill vibration modeling is useful in optimizing bit-reamer compatibility and BHA design, it rarely can identify parameters for smooth drilling. “These are better determined through real-time analysis of drilling dynamics data and by adjusting ROP and WOB parameters as dictated by the vibration levels observed.”
Baker Hughes Inteq, Schlumberger, Halliburton, and others have versions of rotary steerable systems (RSS) they claim have lessened dramatically the impact of vibration. “The ability of RSS to rotate 100% across the drilled interval provides a high quality wellbore with smoother build rates, lower dog legs, and fewer ledges. A smoother and less tortuous wellbore is important since experience has shown that ovalized holes are more prone to casing deformation and cementing issues,” Israel says.
Promoting smoother drilling also is paramount in maintaining directional control. While most agree the ideal kick-off point is below the salt, the trajectory design does not always make this possible. “If trajectory design does not allow this, then considerations such as low inclination azimuth control, well collision avoidance, and torque and drag issues need to be factored into deciding the kick-off point. Salt has been shown to impart walk tendencies on directional assemblies and the control of this walk also needs to be considered in selecting the kick-off point,” Israel says.
When it’s all said and done, however, the overriding objective is to keep the bit effectively and safely drilling new formation, Thomson says. “Imagine drilling 26,000 ft (7,925 m) or deeper and having to trip for a bit. You could lose two or three days tripping.”
Perdido opens western GoM lower tertiary play
Shell Oil Co. has ushered in a new era of Lower Tertiary exploration with the record-setting Silvertip field at its Perdido development in the Alaminos Canyon.
Effectively opening up the Lower Tertiary play in the western Gulf of Mexico, Silvertip established a number of records, including the 9,356-ft (2,852-m) water depth that made it the world’s deepest producing subsea well. First production from Perdido is expected around the turn of the decade, with the facility capable of handling 130,000 boe/d. The entire Perdido development will include 35 wells in the Great White, Tobago, and Silvertip fields.
As an oil well, the Perdido record is 35% deeper than the previous oil well record of 6,950 ft (2,118 m), also set by Shell in the GoM’s Fourier field. The Silvertip milestone, however, is expected to be short-lived as Shell intends to drill an even deeper Perdido well at the Tobago field in 9,627 ft (2,934 m) of water.
Shell operates the Perdido development on behalf of partners Chevron and BP.
