The oil and gas industry owes its very existence to technological innovations. Here are a few of the advances in drilling, imaging, fiber optics and water treatment and disposal that are making a difference in operations today.

To take the pulse of the earth, MicroSeismic Inc. crews lay an array of sophisticated stethoscope-like devices in a star pattern on the ground and listen. Thousands of feet below the surface, they hear the rush of fluid, pumping and the breaking of rock. The stethoscopes are called geophones, a precision sensor that detects the sound waves produced from subterranean fracing. As Peter Duncan, founder, chief executive and president of the company, has said, “We listen for the snap, crackle and pop of what's going on underground.”

Such technologies are impressive. But today, the oil and gas industry looks at innovation not only for an edge, but also to keep from being left behind. Companies such as MicroSeismic, Halliburton's Pinnacle, Cambridge Consultants and others are tailoring their products for an industry whose very existence is based on technological breakthroughs.

The technologies they are developing are a mix of ingenuity, skill and marvel.

Rigs, for example, have changed rapidly in a matter of years. Top-drive technologies have made the transition from offshore to onshore and are so essential that without one, “you aren't going to work,” says Jeff Weis, executive vice president and partner of Orion Drilling Co.

“We continuously update old equipment,” he says. “If you went and looked at someone's backyard, you always can get an idea. These guys are quick to recognize when someone is doing something better.”

Mapping

In the world of imaging, MicroSeismic's technology provides its customers with a picture and data of how the rock was fractured, a service called hydraulic fracture mapping. “Not only can we tell you where the rock broke thousands of feet below the surface, but also how it broke,” says Sarah Groen, senior director of strategic marketing.

Traditional microseismic results ("dots in a box") depicting a fault are shown on the left, and the resulting discrete fracture network is shown on the right. From the discrete fracture network, MicroSeismic determines the productive rock volume and displays it in 3-D.

But MicroSeismic has expanded its traditional microseismic technology beyond simply providing a fracture network to a client. Its newest offering is completion-evaluation services.

“We're actually now combining geophysics and microseismic data with engineering principles and information from our customers to help answer questions like, 'where did the proppant go?' ” Groen says.

In the past, the company would deliver what it nicknamed “dots in a box,” where each fracture was represented around the wellbore with dots colored differently for each stage. These results mapped the fractures and helped to identify faults that were missed by traditional 3-D seismic. Now the company can take the fracture map, identify where within the fractures the proppant went, and therefore calculate the volume of rock that should be productive. In theory, the rock containing the proppant will be the only parts of the reservoir to produce in the long term.

More important, knowing where the prop-pant went can help operators determine how far apart to space their wells. “The value for the customer is in optimizing production,” Groen says. “If the customer spaces wells too close together, they could be overstimulating and overspending. And if they space their wells too far apart, they're leaving hydrocarbons in between those wells.”

Such techniques also enable the company to make recommendations on stage lengths. One operator in the Marcellus learned from the technology that longer stages in the same length of lateral “would have yielded the same production and potentially could have saved one stage per well,” Groen says. “Stage costs vary, but at $200,000 per stage across a dozen wells—that's a lot of money to be saved.”

Through the looking glass

At Halliburton's Pinnacle, the company's fiber optics technology is capable of deciphering the movement of fluids 15,000 feet below the surface. Since fiber optics systems are also less prone to risks faced by traditional electronic monitoring, Pinnacle is taking its technology deeper, to hotter temperatures and higher pressures than before. The company's fiber optics and software can now detect how fast a well's cement cures, or the distribution of fluids flowing inside the well during stimulation and production.

And Pinnacle is pushing for more. Observing the scatter of light reflected back from the fiber optic's glass can tell the temperature of the glass and the strain being put on it.

“All of the expensive things that can break are up on the surface, and then downhole all you have is metal and glass, which is kind of the opposite of what you would have with electronic systems,” says Glenn McColpin, director of reservoir monitoring for Pinnacle.

Halliburton's Pinnacle deployed a dual-array microseismic monitoring solution as well as a permanent fiber optic line on the outside of production casing for a Barnett shale operator. The StimWatch service monitored the points of the fluid entry into the reservoir in real time and microseismic was used to compare those results to the hydraulic fracture geometry. The process helped the operator understand completion effectiveness at the near-wellbore, and how that would affect fracture extension into the reservoir.

Fiber can also withstand very high temperatures. Whereas equipment such as electronic pressure gauges are typically limited to temperatures of up to 175 C (347 F) to 200 C (392 F), fiber systems can withstand up to 300 C (572 F). And, fiber fits in a tight package inside a quarter-inch line the size of the standard oilfield control line, McColpin says. The line measures temperatures, pressure, acoustics and strain forces.

The line also collects a great deal of data, using Distributed Temperature Sensing (DTS). The technology gives measurement points typically every meter or so along the fiber. “The fiber itself is a sensor rather than attaching a sensor to the end of the line, which is what you have in traditional monitoring,” McColpin says. In a 10,000-foot well, DTS could have thousands of measurement points along the fiber optic cable. A traditional method using a thermocouple sensor “might have only six or eight measurement points.”

Historically, DTS was the primary measurement taken. However, the past five years have added new technologies such as strain sensing and, more recently, acoustic sensing. “You effectively turn that glass into thousands of microphones,” McColpin says.

The fiber optics are so sensitive that installing Pinnacle's cables into an office building could allow someone to listen to conversations in every office and discern individual conversations. “This is kind of like NSA (National Security Agency)-type stuff,” McColpin says.

More practically, inside a well, the equipment can listen to everything that's going on downhole, such as leaks, equipment issues and fluid movement. “Some of the shale completion systems will drop balls to actuate valves and you can actually listen to the ball bounce down the well and land in the seat,” McColpin says.

In the past, permanent monitoring technologies couldn't be distributed, so permanently monitoring the entire well wasn't possible. Instead, a logging sweep or some kind of conventional tool would be used to map and collect information, says Priyesh Ranjan, manager of global business development and marketing for Pinnacle.

“It was snapshots in time, it would lead to you shutting down your production and going and taking that snapshot to get that distributed measurement,” Ranjan says. “Whereas now, it's basically real time until the well is abandoned.”

Fiber optic technology also allows monitoring of cement curing in real time. Within each well stage, Pinnacle can monitor many clusters to determine how fluid is being distributed into the reservoir. In a case where only 20% of clusters are taking fluid, operators can pump diverters or use other methods to force fracture initiation at another location in the reservoir.

Today, fiber optic installations are being used in unconventional reservoirs in a way that is not limited to a single event or phase. Most of the life cycle of a well is covered, including monitoring cement, completion, controlling stimulation, evaluating production and, finally, identifying and monitoring re-stimulation candidates.

Analysis then allows Pinnacle to ask questions about each phase of the process, such as the extent of production interference across wells and stages, calibration of frac and reservoir models, and how to optimize the process for the next well-spacing strategy and pad.

For the future, Pinnacle is working on technologies in chemical, seismic, microdeformation and electromagnetic sensing as well as drilling solutions.

“The whole thought is you put one line in the well and you've got a life-of-well monitoring system that eliminates the need for doing any intervention logging,” McColpin says. “You'll be able to collect a myriad of different data types…and really have no reason to go back into the well to collect data.”

Water in real time

As with monitoring techniques, many companies are also working to enhance water technology.

Cambridge Consultants has developed a particle detection technology for the oil and gas industry that measures in real time droplets of oil or particles of sand and wax in produced fluids at offshore and remote production sites. The technology has the potential to allow produced water to be safely reinjected into a well or disposed of overboard.

Modern oil wells produce as many as 10 barrels of water for each barrel of oil. Treating and disposing of this water is a major expense and, in some cases, production is limited by how much water can be handled.

“There is a general need to be able to check for the levels of sand, oil and additives in produced water that is to be reinjected into the well,” says Frances Metcalfe, associate director, oil and gas, at Cambridge Consultants.

“If a well exceeds certain limits, for example due to a failure in processing equipment, particulates can block pores in the rock, causing production to stop—and even render the well beyond economic use. There is therefore a real need to be able to analyze very tiny droplets and particles in a pipeline in real time in order to speed up reaction time to correct potential issues.”

Cambridge Consultants' technology works by analyzing a cloud of droplets or particles with light of varying colors that can also be polarized. In essence, the process is like pausing a video of an explosion and rewinding frame-by-frame to find the origin.

In Cambridge Consultants' process, the cloud is hit with light and creates a scatter pattern. “By measuring that pattern, you can work backwards to establish what the properties of the cloud are and what size distribution of droplets created that pattern,” Metcalfe says.

The technique is derived from medical technology that is used to determine the size of drug particles in nebulizers.

While the technology has been used in some applications, such as hydraulic lines, Metcalfe said the system is still in the laboratory. “We're proving that the technology can work in particular situations. What we're really interested in is the wider applications where it might be of value,” she says.

Some needs are obvious. Produced water quality is usually assessed by taking a sample and sending it to a laboratory for analysis. By the time an issue has been identified, the well may already be irreversibly damaged.

“One of the worries for the operators is they need to make sure the quality of the produced water is meeting the quality they need to prevent blockage of the well,” she says. “That may be something that accumulates over time. Obviously, the sooner you know you have an issue like that, the sooner you can take remedial action.”