Curry

This editorial is being written during a short visit to Scotland, just as the last issue’s was. Another business trip to Europe has given me the opportunity to spend a few days with my family while catching up with my SPE duties from my former Aberdeen office. This time, I have been commuting between home and office by car, rather than by train as I was 3 months ago. I am afraid my commitment to environmentally responsible public transportation was severely dented during that last visit, by the cancellation of two of the trains I was to have taken, and by the hour-long waits on chilly Scottish railway platforms. Some things have not changed since then. It is still definitely winter in the north of Scotland and, although the countryside is as beautiful as ever, it has been decorated with a light covering of snow while I have been driving to my office this week. 

When I relocated to Houston last year, I thought snow was something I would not see again. Then, on Christmas Eve, parts of south Texas had their first snowfall in more than 100 years. That rare occurrence reminded me of the 100-year storm and the potentially misleading concept behind it. These storms are not the worst to occur in 100 years, but rather, the severity of storm that has a 1-in-100 probability of occurring. Because its occurrence is random, or a strictly stochastic event, there is no way of predicting when or if it will happen at all. The capricious nature of random events—and of the British climate—was brought home some 20 years ago to the constructors of an experimental electricity-generating windmill, sited on the windy west coast of Wales. Its design specification was to survive the wind strength of a 100-year storm. Unfortunately, less than a year after it was commissioned, the 200-year storm came along and duly proved too much for its structural integrity.

I heard of that incident when I worked for the Central Electricity Generating Board. Their main research laboratory was split between two sites approximately a mile and a half apart. One of the other research scientists took his bicycle to the office, proclaiming his intention to cycle between the sites instead of driving. It escaped no one’s attention that his bicycle stood in the cycle shed for 18 months without moving, while his car was used for each and every one of his frequent between-site journeys. My former colleague was less than amused when contacted by the work office inquiring into the work order that someone had submitted, which stated: “Please take Dr. Lindley’s bicycle for a walk to give it some exercise.”

In my last editorial, I mentioned with the same intent that my new home in Texas is close enough to my office to be able to cycle to work, which offered the opportunity to mitigate the environmental impact of my gas-guzzling car.  So far, that opportunity remains ungrasped. Infrequent weekend cycle rides have not replaced any car journeys, so I cannot claim they have reduced the volume of fossil fuel I burn, nor, to my disappointment, can I claim they have reduced my waistline. But at least my bicycle has been getting some exercise. And so far, I have avoided committing what must be the ultimate in affluent society’s environmental negligence—driving 10 miles to a gym to spend 20 minutes working out on a static exercise bicycle. 

One of the reasons for my latest trip to Europe was to present a paper at this year’s SPE/IADC Drilling Conference. I have to confess, I found the prospect of presenting no less daunting than it was 18 years ago at the first Drilling Conference I attended, and my preparation for the conference had not been ideal. An uncomfortable problem with my teeth the previous week had led, after four near sleepless nights, to my first encounter with the U.S. dental profession. I walked out of the dentist’s office with my jaw and my wallet both distinctly battered. I was left feeling as if I’d volunteered to be mugged and then thanked the mugger. Fortunately, I did survive my presentation, as (I think) did most of the audience.

I had been looking forward to the plenary sessions, which each addressed the conference theme, “Drilling Technology: Back to Basic$?,” from somewhat different angles. One issue that particularly interested me was the barriers to the adoption of new drilling and completion technologies. Through the technological miracle of wireless voting—adopted here for the first time at a major SPE meeting—the audience members clearly indicated their consensus that operator reluctance to take risks was a major barrier to the early introduction of new technology. From various discussions, there seemed to be agreement that the maturing of many nations’ oil reserves increases the drive for new technologies that improve our ability to produce from smaller accumulations and depleting reservoirs. 

Something I had expected to hear discussed, but did not, was the impact of high oil prices on operators’ approaches to new technology. If a good financial return is assured, does the desire to guarantee successful completion of a well promote a conservative approach to its engineering and drive the operator away from the new technologies that might, in other times, be needed to make the project economically viable? Unfortunately, I have to confess that I cannot be certain this point was not discussed. The combination of shortage of sleep, jet lag, relief at having given my presentation, and the low auditorium lighting meant I found myself dozing off and completely unable to concentrate as I would have liked. At least (as far as I know) I did not disgrace myself by snoring, which is more than could be said for one student attending an offshore survival class taught by one of my acquaintances. The sleeping student’s snores were loud enough to disrupt the class. The lecturer asked the student who sat next to the “Rip van Winkle impersonator” to wake him. Back came the reply: “You do it. You’re the one who put him to sleep.”  

I do not think there is any danger of falling asleep while reading this edition’s papers.  Lessons From Integrated Analysis of GOM Drilling Performance deals with a topic that has been close to my heart for the last 8 years—how to improve drilling performance. This describes how the authors applied a 10-step process to improve their company’s drilling performance in the Gulf of Mexico. Previous drilling data for similar wells are reviewed to generate what the authors term the “best composite time,” or BCT, for the region in question. They contend that this parameter, and its closely related companion, the “best composite cost,” or BCC, form achievable and meaningful technical limits for wells similar to those included in the study. Knowing where they should be in terms of drilling performance helped them to identify and address the problems preventing them from achieving their BCT target.

Generations of drillers have used jointed drillpipe as the principal component of the drillstring, allowing the rig to transmit rotary power and drilling fluid to the bit and bottomhole assembly. Many have cursed the need to trip the drillstring out of the hole to run and cement the casing before tripping the string back into the hole for drilling ahead. Throughout the last 5 years or so, equipment and techniques for drilling with casing have been developed.  Initially, these allowed only vertical drilling, or more accurately, they did not provide any directional control. But Directional Drilling With Casing describes specialized equipment and techniques that have been developed to allow just that. It explains the processes used to drill directionally with casing, outlines some of the issues that must be addressed when planning a directional Casing-Drilling operation, and presents some case histories.

Planning issues in directional drilling relates nicely to the next paper. The minimum curvature method uses a set of circular arcs and straight lines to represent a directional well’s trajectory. It is widely used for calculations involved in planning and surveying 3D directional wells and is often used to investigate safety or business-critical issues.  A Compendium of Directional Calculations Based on the Minimum Curvature Method presents a collection of algorithms for directional-well calculations that use the minimum curvature method. As the authors point out, iterative solutions are often adopted for algorithms on the basis of this method. They contend that the stability of explicit solutions makes them preferable to iterative-solution schemes whenever possible and go on to show that explicit solutions are possible for many minimum curvature method calculations. Read this paper to see what you think. If you are involved in directional-well planning or surveying calculations, I’m sure it will be well worth your effort.

For many years, drilling fluids based on invert emulsions of saline water in a continuous-oil phase were the muds of choice for drilling through soft and water-sensitive shales. They consistently enabled higher penetration rates and gave better-quality wellbores than simple water-based muds. Progressively more demanding regulations, framed as the response to environmental concerns, restricted, first, the use of oil-based muds and, then, the use of potassium salts and synthetic-based fluids that were featured in many of the more effective replacement drilling-fluid systems.  Field Verification: Invert-Mud Performance From Water-Based Mud in Gulf of Mexico Shelf describes a water-based drilling-fluid system developed specifically for gumbo-shale applications. Three principal components of this system are designed to control shale hydration, shale dispersion, and what the authors term “shale accretion,” which is the tendency of hydrated-shale cuttings to stick to each other and to the bit and drillstring. Conventional viscosifying and fluid-loss control polymers are also used. The paper compares the drilling performance achieved with this system to that given by synthetic-based fluids through analogous gumbo-shale sections in offset wells.

Many oil and gas wells rely on a cement sheath surrounding the casing that isolates permeable zones behind that casing. If the cement seal fails, there is nothing to stop formation fluids from going where they should not. It is now widely recognized that changes in downhole conditions can cause mechanical damage to the seal that involves fractures in the cement or separation of the cement from the casing or formation (called microannuli). Remedial action, even abandonment, may then be necessary.  Evaluation of Cement Systems for Oil- and Gas-Well Zonal Isolation in a Full-Scale Annular Geometry presents the results of a combined experimental and theoretical study of cement-sheath integrity. The authors used a novel experimental device consisting of an inner cylindrical core that could be mechanically expanded or contracted and cemented inside an outer steel pipe by use of the cement system under evaluation. The central core’s mechanism was operated to impose various casing deformations believed to represent the deformations likely to be experienced downhole. The corresponding gas permeability of the sealed annulus was also measured. Changing the wall thickness of the outer steel pipe enabled the authors to simulate different formation-elastic moduli. A variety of conventional, flexible expanding and foamed systems were tested, and the results were compared with computations made by use of an existing analytical model. You must read the paper to find out how the different systems performed, but I will give away that the mechanical strength of the cement was itself not enough to indicate the seal’s capability to withstand casing deformation.

Even with today’s record oil prices, operators continue to look for ways to reduce the cost of drilling and completing deepwater wells. Most ultradeepwater wells have been drilled to date with a subsea blowout preventer (BOP) with a large (typically 21¼-in.diameter) marine riser connecting the rig to the BOP. This size of riser demands the use of one of the latest-generation (i.e., expensive) drilling vessels built specifically for ultradeepwater operations. Recently, a well was drilled offshore Brazil in nearly 9,500 ft of water with a surface BOP and a smaller (i.e., cheaper) rig rated to only 7,500 ft water depth. One key element to doing this was the use of a subsea isolating device (SID). Drilling the well was the beginning, but it still had to be tested and completed safely.  Surface BOP: Testing and Completing Deepwater Wells Drilled With a Surface-BOP Rig outlines the challenges these operations pose. It describes well testing and completion methodologies developed for deepwater operations with a surface BOP and SID.  The authors present hazard assessments and hazop studies, and they conclude that both testing and completing subsea wells with surface-BOP-moored rigs appears to be feasible. Although they expect completion operations to be of similar duration to those with a subsea-BOP rig, they expect testing to be faster, easier, and safer. I hope it is not too long before we are able to publish a paper describing field experience of these methods.

The next paper also addresses deepwater well-completion operations. In recent years, the process of replacing the drilling mud or suspension fluid with the completion brine has attracted attention as an important aspect of completion operations. As with teenagers’ parties held while parents are away, the goal is to clean up completely. The timing is different, however, because everything needs to be cleaned up before the party starts (i.e., before the brine goes downhole), rather than once the party is all over. But in both cases, failure to clean up properly invariably leads to trouble. Any drilling mud or solids left behind in the well will contaminate the completion fluid, raising the twin spectres of mechanical difficulties with the completion and impaired productivity. Spending more time than needed on cleaning, or having to repeat operations to achieve the desired cleanliness, both involve unnecessary expense. Deepwater wells offshore Equatorial Guinea had been displaced to seawater before, and they suspended awaiting completion with a CaCl2 brine.  Minor Modifications Make Major Differences in Remote Deepwater Brine Displacement Operations shows how detailed engineering of the brine displacement equipment and processes for these wells led to substantial cost reductions.

However much we want to avoid it, sour gas is something that will not go away.  Controlling hydrogen sulfide and its impact on the environment, equipment, and personnel are inevitable facts of life for drilling and completions engineering. The previous issue of SPEDC contained a paper describing a new hydrogen sulfide scavenger for drilling fluids. The last paper in this issue addresses the problems of using carbon steel coiled-tubing strings for workover operations in locations such as western Canada, in which some, but not all, wells present sour-wellbore environments.  Coiled Tubing in Sour Environments: Theory and Practice presents a string-management system developed to minimize the potential for string failure resulting from exposure to sour gas. Key components of the system include an appropriate tubing specification, a process for identifying operations involving elevated risk or consequence of equipment failure, tubing inspection, the use of inhibitors, and fatigue monitoring to retire a string once its estimated probability of failure in service has reached 1 in 1,000. 

And finally, returning briefly to this year’s Drilling Conference, one of the undoubted highlights was SPEDC Review Chairperson Robert Mitchell receiving the 2005 SPE Drilling Engineering Award. Congratulations Robert—a thoroughly deserved award.

As ever, comments are welcome: david.curry@bakerhughes.com.