June 23, 2010 § Leave a comment
On June 21, 2010, coincident with the longest day of the year was the longest page 1 investigative report I have ever seen in the New York Times or any other prominent newspaper for that matter. I refer to the story entitled Regulators Failed to Address Risks in Oil Rig Fail-Safe Device, nearly three pages long and entirely devoted to the esoterica surrounding blow-out preventers. This is good because prior to this I would not have dared post a piece discussing blow-out preventers, not to mention blind rams. It is quite well written relative to the operational detail. But there are minutiae that would leave most fatigued. So, here is the short explanation together with some commentary.
The last line of defense against blow-outs is a system of machinery aptly known as blow-out preventers or BOP’s. Multiple other lines need to be breached prior to these being in play. In keeping with the Times authors, we will not discuss these except to point out that nobody really wants to resort to the last line. Some of the reporting has attributed sentiments to personnel to the effect that “that’s why we have the BOP’s” as an explanation for risk taking. If true this is not usual. To use a soccer World Cup analogy (it is the season), full backs who espouse such a belief with respect to their goalkeepers have short careers.
There are three types of BOP’s. The most benign, and this one is used for pressure testing as well, is the Annular Preventer. This is composed of elastomeric elements that can seal off the pipe on the outside or seal the hole when no pipe is present. This is a fully reversible action and the Preventer with the least deleterious consequences of use. According to the Times, there were two of these on this rig. A 60 Minutes segment had reported a worker observing chunks of “rubber” several days prior to the accident, which he conjectured to imply failure of the Annular Preventer sealing elements. Congressional testimony indicates reports of pressure integrity tests which showed anomalies that appear to have been discounted by the decision makers. These test the competence of the completion. These could not have been conducted if the Annular Preventer was not sealing. So, one of them was likely functioning at least at the time of the tests, which was not long before the event. So, it is plausible that this line of defense was functional close to the time.
The next line is the Casing Shear Ram. These are essentially irreversible if there is pipe in the hole. They are shear devices that can cut through the casing but they are not designed to seal the flow. They are primarily used to permit emergency disconnect of the vessel. No real data are reported on whether the Casing Rams were functional.
Then we have the centerpiece of the Times story, the final line of defense, the Blind Shear Rams (is it not odd that all the words could apply to sightless sheep; memo to animal activists: the rams are not being killed, they are doing the killing). These are the most sophisticated of the three types and are designed to cut through the pipe and seal firmly in place. The well pressure is designed to help augment the closure mechanism and hold it in place. The reporters make much of there being a single point of possible failure of the hydraulic system and the reports of unreliability. I assume they did their homework here, but have no other insight. But very interesting is their observation that this rig had only one of these. This is surprising for a deep water rig. Here’s why. The pipe it is designed to cut through is not a continuous cylinder. At intervals of 40 feet, sometimes 30 feet, there are joints. The blind shear rams cannot penetrate the joints. So if by bad luck a joint is in its path, the mechanism will not succeed. This is why a second one is important to have, and at a distance no less than 4 feet from the first, but not much further such that there is no likelihood of another joint being encountered.
The story also noted that gamma ray testing had shown that at least one side of the blind shear ram had deployed (the other side could not be imaged) but stopped short of cutting. The evidence shows that at least one of the Annular Preventers was functional at the start. We know nothing conclusive about the Casing Shear Rams. Somehow, these lines of defense crumbled. Unfortunately, the key data indicating hydraulic and other health of these devices did not survive the explosion. Apparently these data are not shipped to shore. Virtually all data related to drilling and completions are streamed to shore. So, where do we go from here?
In keeping with past disasters, such as that of the Space Shuttle Challenger, one can expect a careful examination of each failure point and the production of engineered solutions and associated management of human behavior to minimize the probability of each of the events. The list of suggested remedies should include certain legislation and increased enforcement authority. Certainly on that list ought to be:
- Requirement for two or more Blind Shear Rams on every deepwater rig
- Requirement for an expert level of shore support for all key well control decisions, including involvement of the appropriate federal agency, which should be staffed at an expert level. Through the use of real time support centers covering a number of wells each, the federal agency cost need not be high.
- All key data upon which well control decisions are made should be stored in a Black Box. Ideally, they are already on shore and stored as part of the expert review process mentioned above.
Finally, taking measures such as those above will achieve important results such as avoiding costly near misses, but in the end likely will not avoid the occasional blow-out, in part because other factors may come into play. But, we can be in a state of readiness to dramatically reduce the collateral damage to the environment by minimizing the size of the spill. We urge a joint industry action to study the best form of defense beyond BOP’s. This should be clean page look at all alternatives and should be led by a non-aligned person. Then the industry should agree collectively to have such a system built and ready for deployment at the shortest possible notice.
January 25, 2010 § Leave a comment
The cost of completions in deep water has progressively increased to the point where it can represent over sixty percent of the total well cost. We are already to the point where this is impacting the economic prospectivity of reservoirs. While this trend is manifest in conventional deep water, it is exacerbated in deep water combined with deeply buried reservoirs such as the Paleogene, variously referred to as the Lower Tertiary. The recent exit of Devon from the sector is a signal, even though it was undoubtedly driven by a host of factors. This in one of the most critical issues facing the industry today, in part because deep water activity has to date been relatively immune to the economic travail faced by the industry. The rig count in floaters in fact went up in 2009 compared to the prior year, and some are forecasting ultra deep (defined as water depths in excess of 7000 feet) rigs to more than double in three years. The industry can ill afford a hiccup in this bastion of stable growth. We will enunciate the issues, describe the underlying factors and discuss the viability of innovations to ameliorate the problem.
Sand Management: For conventional deep water prospects this is the single most critical issue. Deep water sediments are almost always young in age, typically less than 10 million years old, and therefore relatively poorly compacted. The majority of the prolific reservoirs are in a class known as turbidites. The unusual manner in which they were formed caused each layer to have relatively uniform particles. When particles of like size are packed together it allows for good pore communication. As a result these reservoirs have high permeability, often in excess of a Darcy. However, the associated high production rates put a strain on the sand body, inducing the production of sand due to the low sand to sand grain adhesion caused by the youth of the rock. Dealing with this is the principal component in the high cost of deep water completions.
The uniform approach to handling sand production is to screen it out. Screens of varying sophistication are used to suit the occasion, but the workhorse method in deep water is a layer of gravel followed by a mesh screen, known as gravel packing. This has been the standard because by and large it performs. However, it is rig time intensive and the increasing rates for deep water rigs have contributed to the ever increasing costs of the completion. Also, the need for remediation at some point is almost certain, and for a period prior to that production rates will be impaired. Another shortcoming is that the testing methodology for determining the need for sand control is imprecise, and the resulting uncertainty causes virtually all deep water reservoirs to be gravel packed, a conservative approach that adds to the cost for the sector. We will be discussing this issue in some detail and drawing attention to a technique that improves the certainty of the measurement, thus allowing for an approach that we refer to as informed aggressiveness. Finally, we note that currently we are responding to the symptom of sand production and ameliorating it through preventing ingress. We will advocate instead treating the underlying cause of sand production with the expectation that in so doing we would be able to make do with simple screen devices, thus reducing complexity and cost. Additionally, there would be an expectation of extended production before remediation, and this too, if needed, may be accomplished with a lower cost method.
Testing for Sanding Propensity:
Cohesion of sand grains is the property that determines whether or not one could expect sand production. This property has proven elusive to estimate. Current methods utilize compressive stress/strain measurement on core, using a technique known as Mohr Circle Analysis. This has two shortcomings. First it assumes elastic behavior of the rock and we know that to be a bad assumption for young deep water rock, which has plastic and visco-plastic tendencies. Second, in rock mechanics cohesion is defined as the stress required to separate individual sand grains, and this is clearly a tensile property. Consequently, therefore, we are using a compressive test to assess a tensile property. All of this causes sufficient uncertainty in the measurement as to force the decision to gravel pack wells when this may not be required. Finally, cohesion can also change with fluid saturation; therefore any completion design should consider the effects of such events as water break through later in the life of the well. Conventional sand prediction tools do not allow for this to be included. This is largely because we cannot predict how increased water saturation will affect cohesion in the formation. All of the foregoing suggests that a new test is needed; one that more precisely assesses sand grain adhesion and one that allows for experimentally determining the effect of fluid saturation.
One such technique is shown in Figure 1. The core is subjected to internal fluid stresses designed to fail the sample in tension. This test cell allows the core samples to be exposed to downhole pressure conditions. As pressure is released from the sealed ends of the core sample, the sample is stressed in tension. In this manner, internal pressure generates the tensile force and induces the cohesive failure of the sample. The fluid properties can be changed to model expected changes in saturation later in life of the well.
Treating the Cause Not the Symptom: As discussed earlier, current methods deal with sand production as inevitable and deal with it by treating the symptom: minimizing entry into the producing bore hole with screening methods. Over time the screens clog and remediation is required, often an expensive side track of the well. A more elegant approach would be to treat the sand to improve grain to grain adhesion without compromising permeability. This has been attempted for decades using the approach of improving the bulk compressive strength to withstand fracture. This has had limited success in part due to high chemical loading, impairment of retained permeability and cost. Only recently has the thrust changed to primarily address cohesive strength, with much less emphasis on increasing
compressive strength. Part of the reasoning here is that we now believe that the primary cause of sand production is not rock fracture per se, but the detachment of individual grains from each other. The low chemical loading and the specificity of the resin in primarily gravitating to the grain to grain interface, results in the pore spaces being relatively unaffected, thus minimally impairing fluid flow characteristics. Figure 2 shows an electron micrograph demonstrating this effect. (Editing note: the figure legend will describe this more fully)
Importantly, the efficacy of the treatment can simply be tested using the new testing method, and the treatment can be optimized for various anticipated conditions of saturations, draw down and flow rates. The foregoing offers the promise of fewer wells being treated for sand control, combined with lower cost completions for those that need it. Formation strengthening, if successful, will allow for far simpler screening complements. In the limit gravel packing could be eliminated. Simplification is particularly of interest in horizontal and multi-lateral wells, both of which have advantages relative to formation exposure and reduced draw down for same production rates. When the Troll Field oil leg was drilled with Level 5 multi-laterals, the lower draw down contributed to the sand production being delayed. Such wells are very difficult to gravel pack reliably and reproducibly.
Obviously, aggressive means such as those advocated require a high degree of certainty. The testing method is a key to selecting the best treatment and assessing likely efficacy. Also, piloting in cheaper wells and in remediation of wells with plugged screens would be prudent first steps. We describe this approach as Informed Aggressiveness. Drilling programs have long used this, as for example in the handling of pore pressure/fracture gradient variability. Real time pore pressure measurement and associated modeling allows the more aggressive operator to drill closer to balance, thus vastly improving rates of penetration and minimizing formation invasion, while largely avoiding kicks and blow outs.
Dealing with Salt: The majority of the important deep water tracts in the world are overlaid by salt diapirs. These are sheets of salt, which can be from a few hundred to few thousand feet thick. When these are outcrops on land, they are often mined to produce table salt labeled rock salt. The sheets in deep water present immense difficulties to seismic exploration due to the relative imperviousness to penetration of sound waves. Here we concentrate on the effect on drilling and completion. As these layers extruded out millions of years ago, the rock below was often reduced to rubble, presenting a zone of uncertain character as the drill bit left the salt. The completion is more directly affected by the nature of the salt itself. In a sense the salt is still “live”. A hole drilled in it is subject to the mechanical phenomenon known as creep, a sustained relatively low stress, but one which could buckle the casing. Accordingly, the casings have to be unusually robust, adding to the cost.
The difficulty of imaging below the salt makes for greater positional uncertainty regarding the location of the highly productive intervals. This can lead to tortuosity, with attendant completion difficulties. The foregoing notwithstanding, the techniques to address these are relatively well understood, with technology in active development and deployment.
The Challenge of the Paleogene: Also known as the Lower Tertiary, this represents a new frontier that many believe to be promising. The primary distinguishing features of these reservoirs from the standpoint of completions are their age and deep burial. These rocks are in excess of 25 million years old, compared to normal deep water formation in the mid single digits. The deep burial combined with the age cause these to be very tight. The required fracturing to enable production is a first for the deep water, where the conventional rock has high permeability, as mentioned earlier. Hydraulic fracturing at ambient pressures in excess of 15000 psi, and often greater than 20000 psi is a challenge. Most surface equipment associated is not rated at over 15000 psi, and even that level is hard to come by. The pumping equipment is itself in short supply at these levels of pressure. Finally, many of these prospects are in ultra deep water. Industry is in fact addressing this problem and one solution on offer is an interesting departure from current practice. Fracture fluids are typically water based, and therefore with specific gravity close to 1.0. The innovation is to use a higher gravity fluid, thus using the hydrostatic head to advantage as additive to the pump pressure at the surface. These fluids, with specific gravities up to 1.49, can allow reductions in surface pressure of 3000 psi and higher. The ability to tolerate lower pressures at the surface has significant advantages in safety and cost. This would have application to land operations as well, allowing the use of less costly and more easily available equipment (pumps and surface handling) for deeper higher pressure jobs.
Intervention: For most wells intervention is essentially unavoidable. For deep water the high costs are occasioned by the need to use floaters. Approaches such as smart wells will delay, but not usually eliminate intervention. Two approaches are suggested to address this issue. One would be intervention friendly completions. These are defined as completions that provide all the needed functionality and yet their design is inherently more amenable to intervention tooling and operations. One example would be the use of expandable casing to produce a mono-diameter well. Aside from the advantages of a single bore, the design would allow for a relatively large diameter at the reservoir. In this context the mono-diameter feature need only commence at the intermediate casing, and not necessarily go all the way to the surface. Another example would be the use of formation consolidation discussed above. In the cases when gravel packing is eliminated, one would pick up a hole size, maybe two, and the associated screen would also occupy less annular space. In general, though, the industry should be encouraged to devise intervention friendly completions. The second approach addresses the issue of the vessel. Over the years the industry has taken stabs at purpose designed light vessels which would be cheaper to operate. The likely reason these did not take hold is the unpredictability of the need for intervention and hence the difficulty of forecasting utilization. There is need for an innovative business model. One such might be utilization by subscription: operators buy take or pay time on the vessel and a system is instituted for planning and timely access. This would be somewhat akin to a time share vacation rental home but hopefully with a higher degree of sophistication such as preferential rights to access.