MRI Logging Takes the Next Step

Data Comes in Real Time

Nuclear magnetic resonance (NMR) imaging technology for well logging rather quickly morphed from a kind of esoteric novelty to a mainstream oil patch application. Indeed, since its debut in the early 1990s, this innovative approach to logging and reservoir evaluation has come to be de rigueur for operators both large and small.

"The cost is about proportional to what a triple combo would be, so this is not just for the major operating companies," said Ron Cherry, product manager NMR services at Halliburton Energy Services.

"We do a lot of jobs for the smaller companies, and East Texas is a particularly busy area right now," he noted, "and the technology is used a lot offshore where the cost relationship to the triple combo measurment suite is the same."

Although not the lone wolf in the NMR logging applications arena — industry veteran Schlumberger also has a dedicated focus on the technology (see related story, page 18) — Halliburton has a lengthy track record of tool development and application of the technology. This comes via its ownership of NUMAR, which pioneered the use of NMR in the oil patch with its Magnetic Resonance Imaging Logging (MRIL®) tool.

For those operators unfamiliar with what NMR technology brings to the table, it's designed to provide some vital information:

  • Identify bound vs. moveable fluid.
  • Obtain effective porosity.
  • Determine permeability.
  • Obtain accurate measurement and quantification of reservoir fluids — oil, gas, and water — via Direct Hydrocarbon Typing (DHT®).

Perhaps the best approach for an operator debating the pros and cons of a magnetic resonance imaging (MRI) application would be to review a check-list of questions that the technology can help answer:

  • Is the rock porous and, if so, how porous?
  • Does it contain moveable/producible fluids?
  • In what fractions will the gas, oil and water produce?
  • How are the fluid columns separated, what is the height of each column, and where are the transition zones?
  • Are there any specific obstacles to production, such as pore-clogging clays, tar layers and such?
  • What are the properties of each producible fluid, and what is the gas/oil ratio in the hydrocarbon phase? How viscous is the oil?

Solving the Mystery

A quick look at the basics — a kind of NMR 101 — might help to remove some of the mystique surrounding the technology, making it appear less daunting to someone contemplating its usage.

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Nuclear magnetic resonance (NMR) imaging technology for well logging rather quickly morphed from a kind of esoteric novelty to a mainstream oil patch application. Indeed, since its debut in the early 1990s, this innovative approach to logging and reservoir evaluation has come to be de rigueur for operators both large and small.

"The cost is about proportional to what a triple combo would be, so this is not just for the major operating companies," said Ron Cherry, product manager NMR services at Halliburton Energy Services.

"We do a lot of jobs for the smaller companies, and East Texas is a particularly busy area right now," he noted, "and the technology is used a lot offshore where the cost relationship to the triple combo measurment suite is the same."

Although not the lone wolf in the NMR logging applications arena — industry veteran Schlumberger also has a dedicated focus on the technology (see related story, page 18) — Halliburton has a lengthy track record of tool development and application of the technology. This comes via its ownership of NUMAR, which pioneered the use of NMR in the oil patch with its Magnetic Resonance Imaging Logging (MRIL®) tool.

For those operators unfamiliar with what NMR technology brings to the table, it's designed to provide some vital information:

  • Identify bound vs. moveable fluid.
  • Obtain effective porosity.
  • Determine permeability.
  • Obtain accurate measurement and quantification of reservoir fluids — oil, gas, and water — via Direct Hydrocarbon Typing (DHT®).

Perhaps the best approach for an operator debating the pros and cons of a magnetic resonance imaging (MRI) application would be to review a check-list of questions that the technology can help answer:

  • Is the rock porous and, if so, how porous?
  • Does it contain moveable/producible fluids?
  • In what fractions will the gas, oil and water produce?
  • How are the fluid columns separated, what is the height of each column, and where are the transition zones?
  • Are there any specific obstacles to production, such as pore-clogging clays, tar layers and such?
  • What are the properties of each producible fluid, and what is the gas/oil ratio in the hydrocarbon phase? How viscous is the oil?

Solving the Mystery

A quick look at the basics — a kind of NMR 101 — might help to remove some of the mystique surrounding the technology, making it appear less daunting to someone contemplating its usage.

Magnetic resonance imaging technology initially was used for chemical analysis and is now employed routinely for medical evaluations, where the equipment uses large magnets to surround the subject being examined. In the quest to render MRI suitable for use in the oil and gas industry, NUMAR miniaturized the magnets, shrinking and redefining them to fit into a small diameter borehole to allow NMR measurements of material surrounding the MRIL tool.

In stark contrast to conventional logging, NMR measurements are mineralogy-independent. The MRIL tool responds only to the hydrogen protons in the fluid of the rock's pore spaces, receiving no signal from the rocks per se.

The hydrogen protons align with the permanent magnetic field created by the MRIL magnet probe. The tool then emits a radio frequency (RF) pulse that "tips" the protons at a 90-degree angle, and subsequent 180-degree pulses are applied.

The magnitude of the ensuing NMR signal, which is created by the RF pulse, is directly proportional to the amount of hydrogen present in the volume probed by the tool and provides a measure of liquid-filled porosity.

The hydrogen protons associated with the hydrated clays and clay-bound water relax, or realign quickly. Clay porosity is directly measured by the MRIL tool.

Both pore texture and size impact the decay rate of the NMR signal. Measurement of this signal provides an estimate of the rock's internal surface-to-volume ratio, which is closely related to bulk-volume-irreducible water, and in turn provides an estimate of grain size distribution. The difference between the MRIL-derived porosity and irreducible water is the moveable fluid volume.

Relaxation data and porosity data are used to compute permeability straight from the MRIL tool.

Because the MRIL tool responds to matrix fluid, NMR technology is not applicable to hard rock reservoirs with fracture production.

One of the NMR applications that captured the fancy of operators early on is the now-commonplace DHT. It allows the accurate measurement and quantification of water, light oil and gas in the near-wellbore region investigated by the tool.

"Direct Hydrocarbon Typing has become so fundamental, it's now like bread and butter," Cherry said. "Almost every log we run is a hydrocarbon typing log."

New Tools Continue

As one tool becomes "old hat", others invariably come along to keep the cutting-edge sharpened, such as the new Magnetic Resonance Imaging Logging-While Drilling (MRIL® -WD™) system, which was introduced last summer.

It is now being used commercially in the Gulf of Mexico and the North Sea.

"It's like the MRIL logging tool in that it provides information about fluid, irreducibles, permeability and other applications you get from the logging tool," Cherry noted, "but you can do it in real-time while drilling."

Another tool now being field-tested is a magnetic resonance module called MRILab® that goes with Halliburton's Reservoir Description Tool (RDT®) — a formation tester-type tool.

The MRILab downhole fluids analyzer module takes MRI measurements of fluids as they flow directly from the reservoir into the RDT tool through the RDT pads, allowing the evaluation team to measure parameters that give indications of the viscosity of the fluid, according to Cherry. It addresses the difficult problem of differentiating oil base mud filtrate from connate hydrocarbons.

"When you start sampling a formation, you want to know what's the native fluid, not the filtrate," said Charles Siess, global MRIL product manager at Halliburton. "With an oil-based mud instead of a water-based mud in an oil zone, trying to figure if you went from oil-based filtrate to native crude is tough.

"In measuring the magnetic resonance parameters of reservoir fluids as they flow through the MRILab, what we see is there is a difference in signature between the filtrate and the native crude."

The MRILab module provides in-situ fluid characteristics at reservoir PVT conditions. By taking measurements downhole, the samples are not altered as they are when sent to a lab for analysis, where the lab must try to reconstruct reservoir conditions.

"We think it's important to get these measurements in-situ," Cherry said. "By measuring fluids directly you get the raw fluid measurement and get the exact parameters you need for use in log interpretation of either the LWD or the wireline tool.

"In other words, if you have fluid measurement from MRILab, you know exactly what the fluid properties are," he said, "and this enhances interpretation accuracy of the well log."

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