Tools for the High-Tech Roughneck
Working under 10,000 ft of seawater
By Robert B. Aronson
The US "oil patch," which has been in decline for several years, is now booming, and there is a frantic search for more petroleum and ways to recover it. There are three main sources of additional oil: find new reserves, use advanced technology to get oil from old fields, and drill deep-water wells. The deep-sea wells, those bringing up oil from more than 10,000' (3048 m) are the most promising source.
One of the centers of deep-well activity is the "Lower Tertiary," a geological section extending about 150 miles (241 km) from the Gulf shore between Florida and Texas. Early indications are that there can be anywhere from 3 to 15 billion barrels of oil in that section's rocks.
Lower Tertiary milestones:
- Serious interest began with the successful drilling of a "wildcat" well in 2001. Since then, there has been a rush by the major producers to lease tracts in that area.
- Recently, a major oil company had a record-setting winning bid of $2.9 billion for a promising undersea tract.
- In the last two years, companies have ordered over $2 billion in deep-sea oil rigs.
- The longest drill string today is over 27,000' (8229 m). Of this, 7000' (2133 m) is the distance from the rig to the sea bottom and 20,000' (6096 m) is under the seabed in horizontal and vertical segments.
The Lower Tertiary discovery has triggered a massive need for the special equipment necessary to work in the deep-sea environment
According to Vik Rao, Senior Vice President and Chief Technology Officer of Halliburton (Houston), "Recent reports of large accumulations in the Lower Tertiary underline the move towards higher pressures and, to a degree, higher temperatures as well. Higher pressures typically dictate thicker walls on the compartments housing electronics, and this requirement is best addressed with lower-profile electronics. Miniaturization in general accrues this benefit, together with other improvements such as lower power draws and increasing computer power per unit area. Higher temperatures will also require significant electronic modification, with the degree of difficulty increasing dramatically with each extra 5°C over 200°C."
Extended-reach drilling is putting much greater emphasis on tool reliability. Beyond a certain reach, sliding friction limitations on mud motors force the use of rotary steerable devices. These are still in the relatively early days of use, compared to mud motors, and so increasing reliability in this sector is essential, largely dictated by the demands of rotary seal mechanisms.
One of the most significant issues faced by suppliers of drilling equipment is the shortage of specialized machining capacity. "For some of the more demanding downhole applications, some unit operations can be performed by only a few outfits, causing capacity constraints that result in inordinately long lead times," says Rao. "On occasion, new development tools have to be ordered in quantity before they have been fully tested, putting great pressure on the development engineers, and on the need for close coordination with manufacturing at every step. Layered on this is the extreme runup in steel cost, and in particular, alloy steels containing nickel."
Where to drill is a multimillion dollar decision, particularly with offshore wells. And one of the key research tools in making that decision is software. Mercury Computer Systems (Chemsford, MA), one of the leading suppliers of software to the petroleum industry, offers a system that helps evaluate seismic data to give the best possible chance of hitting an oil reserve.
"We supply visualization software to the industry," says Mike Heck, Technical Director, Visualization Sciences Group. "With exploratory oil wells costing at least one million dollars, it is important to have as much information as possible for that decision."
In determining where to drill, or whether an area up for lease is worth going after, the main source of information is seismic data. High powered sound sources, for example air guns, send vibrations through the seabed and the returning waves are recorded. "These returns are full of noise and must be extensively processed before the data are useful," says Heck. "Then our software can be used to create an interactive 3-D picture of the undersea formations. With this information, the geologist has a better chance of locating formations that might contain oil."
And the data volume is enormous. A medical CT (computed tomography) scan may deliver from 200 MB to 1 GB The seismic test delivers over 100 GB that may take days, or even weeks, to process.
The main information of interest is the time it takes for the signals to return. Signals travel at different speeds through different types of rock, so the time difference can give critical information on the type of rock formation that is underground or under the sea.
Other key information comes from visualization. The data are used to make a 3-D picture of the test area. The program can actually generate visual slices of the test area. Once a model of the test area is made, the geologists take over and work to identify formations that are likely to contain oil. For example, there are humps or traps of folded rock where oil is likely to accumulate. And they are also interested in the potential quantity of oil that might be available.
"Currently, the software is ahead of the drilling technology," Heck explains. "That is, we can see deeper than we can drill."
The company's big push now is to wring more useful information from the data. There are frequency shifts and phase changes that can tell what kind of rock is down there and how much oil it may contain. Or, what is often very important, there is information on a boundary between different types of rock. It has been a major achievement to get the data return, the visualization images, and the rock physics in real time, in one test.
These analyses are important for predrilling policy. New tracts of seabed are opened periodically, and various companies bid on the rights to drill. It is therefore very critical to know what that area might be worth, to help decide what kind of bid to make.
"All the oil companies start out with the same basic data before they drill," says Heck. "The most profitable operations are those that are most clever in analyzing the data. Plus, they always need a lot of luck."
Getting oil out of the ground is a complex process. The trail of manufactured parts and products needed to drill an oil well reaches far back to the basic elements, many with unique manufacturing requirements. For example, safety is a major issue, particularly when dealing with the very large, very heavy pieces of equipment common in the petroleum industry. The pipes needed for well drilling are an example. A single section might be 22 in (559 mm) in diameter and 40-ft (12-m) long. Each end must be machined to accurately handle the critical threading that joins the pipe sections. Schunk Inc. (Morrisville, NC) has been making specialized chucks to facilitate this operation for some time. One of the first modifications was to redesign the chuck actuation system. It normally consists of a hydraulic cylinder that causes an actuator to close the chuck. The actuation system initially interfered with pipe handling and had to be removed. According to Ron Wright, Schunk Product Manager, "We eliminated the drawbar and made the chuck self-contained."
Another safety issue was ensuring that the air pressure activating the chuck was at the necessary level. Schunk offered two solutions. One has a sensor that monitors line pressure and automatically shuts down the lathe if pressure drops. In another design, the pneumatic actuator was replaced by spring pressure. Air pressure opens the chuck, then the springs apply the holding force.
GageMaker (Houston, TX), a company that specializes in thread gages for the oil industry, reports good business, with orders coming in from both Russia and China.
Most of the instruments they offer are for well pipe, which has threads that are critical because they have to hold together the pipe string. That string may be made of 40' (12-m) sections and be more than 30,000' (9144-m) long.
"We offer two types of thread gages," says Vice President John Wolfe. "The first is made to measure API standard threads and is used by most of the industry. The second is used to measure premium threads, which we specialize in. Premium threads are normally a proprietary design developed by one of the major companies. It can take high loads and resist the corrosion of acids and sulfur in the drilling water. The method of sealing is a major difference between the two. API uses a doping material, and Premium uses a thread with an interference fit and relies on metal-to-metal contact for sealing. These threads also have sealing elements at the beginning and end of the thread that become part of the sealing system. The thread and seal have to be particularly strong on those pipe sections that will be bent."
The pipe material varies with the type of well. For the greatest strength, stainless steel is used. Chromium steel is the preference when the well may hit a corrosive gas. Those pipes that will be bent for horizontal drilling have to be slightly malleable, yet retain their strength. The drill line going to 30,000' (13,608 kg) will weigh 2 or 3 million pounds (900,000–1,400,000 kg).
When starting a well, the established technique is to start with a hole diameter as large as 22". Sections of the well are drilled, cased and cemented in place (set casing) before drilling subsequent sections of the well. The decision to set casing is determined by geological conditions in the well. Each time casing is set there is a reduction in the well's inside diameter as smaller diameter casing is suspended inside the previous string of casing. This process continues, reducing the diameter of the well as each string of casing is set. Because well cost is roughly proportional to the size of the wellbore operators try to drill the smallest diameter well that will not restrict production from the wellbore. The choice of initial wellbore size is important, as it imposes a limit on the the number of times casing can be set without restricting production from the well.
"To get around this, the monobore well has been developed and is growing in popularity," explains Gary Flaharty, Director of Investor Relations for Baker Hughes, (Houston, TX).
In its operating sequence, well drilling begins with the diameter dictated by conditions in the producing zone. When geological conditions dictate the need to set casing, a pipe with a diameter smaller than the entry bore is lowered and positioned or "hung" from the last conventional pipe section. To enlarge the pipe, a swage is driven through it, expanding its inside diameter to that of the initial bore. The expanded string is cemented in place, and drilling continues. This place-andexpand sequence continues until the oil reservoir is reached. "The well is therefore of a single diameter, reducing the cost of drilling the wellbore without restricting production," says Flaharty.
"Developing the pipes for the monobore process was a major metallurgical problem. A pipe section has to be malleable enough to be enlarged, yet able to retain the necessary strength for long-term operation," he explains. "A particular issue was developing a design that allowed the thread joint between the pipes to be expanded without cracking, and maintaining a thread seal as the pipe bends."
One of the major changes in oil recovery has been the development of the ability to drill wellbores with complex paths with multiple laterals. Wellbores start vertical, change azimuth and inclination, and are drilled horizontally through the producing zone, exposing thousands of feet of wellbore to the formation. From this one central well companies can drill other wells or laterals in spider-like paths away from the main well. Planning for wells that radiate out requires careful analysis to avoid hitting other pipes and minimize costly drilling in very hard rock.
Steerable drilling developed in several steps. The first attempts in the middle of the 20th century involved a simple biasing of the cutting head. Next, a positive displacement hydraulic motor was added to the drill head. This greatly improved directional control. The steerable drilling motor was next. With this system, the drill stem remains stationary and the tip of the drill was aimed. This further improved performance, but the stationary drill stem sometimes has stick/slip problems. The latest version is a more rugged drilling system, with greater control of position through the use of sensor data. In this version, the drill stem continues to rotate, eliminating the stick/slip problem.
Research on steerable drilling continues, with particular emphasis on sensor type and performance, as well as more complex software controls.
Most wells today are not vertical, but horizontal. The drill stem is steered by either changing the direction the pipe is moving or biasing the position of the drillhead cutting motor. With a 4.5" (114-mm) pipe, it's possible to turn 90° in about 1000' (305 m). At a depth of 2 miles (3.2 km), the head is positioned with an accuracy of 3' (0.9 km).
A big advantage of this type of drilling is the amount of wellbore that can be exposed to the formation, increasing the amount of oil or gas that can be recovered from a single wellbore. Additional laterals increase the amount of reservoir that can be drained from a single wellbore.
Placement of the wellbore is of critical importance. "To aid in the search, the tools in the bottom hole assembly include instruments that investigate the geophysical properties of the rock formation we are drilling through," says Flaharty. "For example, sensors on the bottom hole assembly check the resistivity of the rock. Oil or gas-impregnated rock has a characteristic resistivity different from water-impregnated rock.
"Usually the reservoir is sandstone with oil impregnated in it. We need to know if there is space between the sand particles and how well-connected the spaces are The space determines the amount of oil and gas that could be in the formation and the connections between the spaces are important to understanding how much of the oil or gas will be produced. We also need to know," says Flaherty, "if we have hit oil, gas, or water. There are instruments in the bottom hole assembly that can give us that information. It's a kind of traveling assay office. That's why the bottom hole assembly alone can cost $1 million or more."
Only recently has the technology been available to send electronic signals up the pipeline. Problems with pressure, bending, and multiple connections made conventional wire lines impractical. Instead, signals were passed by a unique system called "mud-pulse telemetry." A poppet valve near the drill head oscillates in response to head sensor input. These impulses travel through the mud to the surface, where another sensor converts the mud oscillations to readable signals. The mud system "transmits" 6–20 bits/sec.
Once the oil or gas is out of the ground, the next major step is sending it through transmission lines to a processing facility. These are generally low-temperature, low-pressure applications. Higher temperatures and pressures are found in process piping, found inside the facilities.
Pipe welding, both transmission and process piping, is considered to be one of the more difficult welding tasks because, when the pipe is fixed, it requires the welder to weld in all positions: flat, vertical and overhead.
A transmission pipeline is usually welded by several teams. First, pipefitters align and tack together the pipe edges, preheating the pipe when necessary. A second crew follows, and makes the important root pass weld. Because this closes the gap between the pipes, it is the most difficult pass to make, and is usually performed by the more skilled welders. Subsequent crews add fill passes until the final crew adds a cap or cover pass. By making one pass per crew, steady production is maintained. Generally the Stick (SMAW) process is used for all passes.
With its higher temperatures and pressures found in process piping, the root pass is generally performed using TIG (GTAW) followed by Stick to fill and cap the pipe. Here, one or two welders usually perform all of the passes.
When MIG or flux cored processes can be used instead of TIG or Stick it greatly increases productivity. TIG is perhaps the slowest process and requires the most skill. Stick is a bit quicker, but still requires the operator to replace the electrode every few inches. But MIG, with its continuous wire feed, allows for continuous welding.
A modified short circuit MIG process, such as RMD (Regulated Metal Deposition) from Miller Electric Mfg. Co. (Appleton, WI) can be used, explains the company's Mike Roth. Another, found in its PipePro welding system, is specifically designed for use in the critical root pass. Because of its higher deposition rates, ease of use, reduced spatter, lower heat input and high tolerance to changes in tip to work distances, it is increasingly impacting the industry.
"RMD offers better control of the weld droplet, resulting in a higher quality weld for the root pass," says Roth. "A big plus is that it is easier to master, so training is not as long, especially when compared to Stick or TIG training. In some cases, it eliminates the need to back-purge on stainless steels and chrome-moly piping, saving both time and the cost of the backing gasses."
Service Industry Challenges Offer Opportunities for Growth
There are many challenges currently facing the service industry and these provide opportunities for Schlumberger to grow. The first of these is the trend towards exploration which we believe will continue to accelerate. The economics of sustained higher oil prices are making exploration plays—that would have seemed impossible only three years ago—very attractive. This will affect the types of technology required as well as overall technology uptake. Exploration services are more intense than services used for development activities. Among these, advanced seismic and new electromagnetic imaging technologies help reduce uncertainty and mitigate technical risk in complex areas where better imaging of the subsurface below salt and below basalt is essential. New methods for sampling and analyzing complex reservoir fluids in situ enable faster and better understanding. Better dynamic testing of the reservoir ensures economic viability. And new workflows that integrate surface and downhole measurements provide superior reservoir characterization.
Second, technology is required to improve the performance of the existing production base, where 70% of the fields have been producing for more than 30 years. Combating decline is crucial to this, and technology intensity will only accelerate. Here, we see the need for faster drilling and well construction where the integration of completion and stimulation can bring significant operating efficiency. New ways of delivering services will also add value.
Third, the age of easy oil is clearly over and there will be a growing shift to more and more unconventional hydrocarbon resources. The greater service intensity required to produce unconventional natural gas in North America is growing, although this is just one example of the challenge of unconventional hydrocarbons. The move to heavier oil production in Canada and Venezuela is another.
Lastly, the industry will continue to struggle with the lack of trained professionals. As a result, systems for more effective use of the core of specialists that exists will become more and more prevalent. While this will begin with their recruiting and initial training, it will need to continue in such a way that the new workforce is brought rapidly to levels of competence that permit autonomous decision-making earlier than before.
Schlumberger has an enviable position in the technologies in which we participate. In the last three years we have made major technology introductions in geophysical services with Q marine and land seismic systems, in directional drilling and logging-while-drilling with the PowerDrive and Scope families of services, in Wireline with the Scanner technologies, and in petrotechnical software with the Petrel integrated model-based seismic-to-simulation suite. And we are now beginning to roll out significant new products and services in pressure pumping and completions with the Contact family of stimulation technologies.
Based on a presentation by Andrew Gould, Chairman and CEO, Schlumberger, Houston, TX.
This article was first published in the February 2008 edition of Manufacturing Engineering magazine.