More Data on the Way

NMR Advancing Toward Simplicity

By KATHY SHIRLEY
EXPLORER Correspondent

NMR (first) 'Rocked' in the '60s

The potential of NMR measurements to provide information on formation pore fluids and pore structure was first identified in the 1950s. The first NMR log was run in 1960, measuring the signal from protons precessing in Earth's magnetic field.

These early NMR logging tools required doping the drilling mud with magnetite to kill the borehole signal.

Advances in NMR interpretation occurred in the 1960s, including a relationship between relaxation time and permeability in sandstones, the concept of free fluid index and the relationship between pore size, fluid and matrix properties.

A new version of the tool was developed in the late 1970s and remained the only widely available NMR tool until the advent of the pulsed NMR tools in the late 1980s. This new generation tool had a T2 (the amount of time it takes for the magnetization component to deteriorate) sensitivity limit of about 30 milliseconds and measured only the bulk or movable fluid in the formation pores.

It did not measure the T2 distribution of the pore fluid.

The first commercial pulse-echo logging tool was introduced in 1990, and Schlumberger introduced its first commercial tool in 1994. Schlumberger's Combinable Magnetic Resonance, or CMR, tool was first proposed in the late 1980s and a prototype was field tested in 1992.

In 1994 the commercial CMR tool had a T2 sensitivity limit of three milliseconds. It couldn't routinely measure T2 signals below three milliseconds, such as those from clay-bound water or water trapped in small pores.

Schlumberger improved the technology with its CMR-200 and Total CMR (TCMR) porosity processing -- enhancing the T2 sensitivity limit by an order of magnitude to 0.3 milliseconds. The TCMR porosity processing software was optimized to make full use of the hardware improvements in the determination of total porosity. TCMR logs demonstrated that in most formations the tool is capable of measuring total porosity.

NMR data can be used directly to infer formation properties -- and comparing NMR with other measurements can expand on this information. For example, comparisons with density porosity can be used to quantify gas or light hydrocarbons in shaly sand and other difficult environments.

For years nuclear magnetic resonance logging technology has been touted as the best new tool for downhole geology, providing geologists with a wealth of information that's simply not attainable with any other tool. And, in fact, commercial NMR logging tools today usually deliver on all those promises.

Unfortunately, geologists sometimes are not equipped to unravel the complicated data derived from the method -- and often must enlist the help of the nearest physicist.

James Kovats, NMR product champion for Schlumberger, acknowledges that service companies must continue to educate clients on the value of NMR and exactly how the technology works.

"There is a growing number of people in the industry who understand this new technology, but we still have quite a lot of education to do," he said.

"Many people think NMR measurements are extremely complicated, but it's a very rich dataset with a great deal of valuable information -- and it's up to us to help clients understand how to best leverage all that information to better understand the reservoir."

Speed has always been the major stumbling block for NMR technology, Kovats said, but Schlumberger's newest generation NMR logging tool, called CMR Plus (for Combinable Magnetic Resonance), has increased the logging speed to match that of other tools in the logging suite.

"Now, when a petrophysicist says he's interested in getting NMR data he doesn't have to put his career on the block and convince management to spend extra rig time to acquire NMR data," he added.

Kovats said the tool is three to five times faster than earlier tools.

"The previous generation tools logged on the order of 100 to 200 feet per hour in a slow environment, and 600 feet an hour in optimum conditions," he said. "The new tool can log 700 to 800 feet per hour at an absolute minimum and can go as high as 3,600 feet per hour, depending on the downhole environment.

"This increase in logging speed makes the tool more cost effective," he continued. "Also, with the speed increases... we can log larger intervals and gather significantly more data on zones that might otherwise not have been tested."

That, he concluded, can translate to finding additional productive reservoirs that might not have looked promising on other types of data.

A User-Friendly Approach

Scientists recently have turned their attention to another important stumbling block to the widespread use of NMR technology: Making the method more user friendly for oil company personnel.

"NMR technology has advanced to the point where we are coming full circle and can get back to simple outputs," Kovats said. "Saturation, viscosity, porosity. That's what people are interested in ... They want to know how much oil there is, how much storage capacity there is and will the oil flow."

He said that NMR can provide all that data with a new magnetic resonance fluid characterization method currently being developed.

"We can provide that information without having to educate the client about the technical intricacies of NMR logging," Kovats said.

The advent of this magnetic resonance fluid characterization method is enhancing NMR as a tool for multi-disciplines.

"Previously it was geared primarily to petrophysicists who knew how to glean the information," Kovats said. "Now geologists as well as reservoir engineers can benefit greatly from the information -- without requiring a degree in physics."

The magnetic resonance fluid (MRF) characterization method -- currently undergoing worldwide experimental field testing and expected to be available commerically by next year -- provides a detailed formation evaluation of the near- wellbore region investigated by modern NMR logging tools.

It gives quantitatively accurate estimates of formation properties, including total porosities, fluid saturations and oil viscosities.

These are obtained by inversion of suites of NMR data using a new multifluid relaxation model, according to a paper presented at the recent Society of Petroleum Engineers annual meeting by R. Freedman with Schlumberger.

NMR's value for providing formation evaluation information is well documented -- and foremost among the many physical properties probed by NMR is molecular diffusion. Since water molecules typically diffuse much faster than oil molecules and much slower than gas molecules, NMR diffusion measurements provide a means for detection and differentiation of reservoir fluids.

This capability has generated much excitement in the oil industry since the introduction of modern pulsed NMR logging tools. However, despite the considerable efforts of service companies and oil companies, the development of an accurate and reliable NMR fluid-typing method has been limited by the lack of a detailed understanding of molecular diffusion and NMR relaxation in hydrocarbon mixtures.

That's where the MRF method comes in -- it uses suites of spin-echo measurements acquired from NMR logging tools, and the data suites consist of spin-echo measurements with different echo spacings, polarization times, applied magnetic field gradients and numbers of echoes.

These measurements, sensitive to the viscosities and molecular diffusion coefficients of the fluids, provide information needed for fluid characterization. The MRF method is based on the inversion of a general multifluid relaxation model that describes the decay of the transverse magnetization in porous rocks containing reservoir fluids.

What does that mean to oil companies?

"It is well known ... that oil-bearing reservoirs can be misinterpreted or even missed altogether by conventional resistivity-based interpretation," Freedman wrote. "One difficulty is the fact that many oil-bearing reservoirs exhibit anomalously low values of resistivity, which results in spuriously high water saturation estimates."

Other difficulties in the interpretation of resistivity logs, according to his paper, can be traced to fresh formation waters or waters with unknown or variable salinity. Problems also occur in formations with complex lithologies that can result in totally erroneous water saturation estimates.

The MRF characterization method, centered around a new multifluid relaxational mode, overcomes problems inherent in resistivity interpretation by providing formation evaluation information that is not possible with other well logging techniques.

"Hydrocarbon detection and viscosity estimates using NMR logging tools have been tried via various methods in the past," Kovats said, "but those methods were based on assumptions that were not always true, so they weren't very reliable or robust."

The Multi-Disciplinary Tool

The MRF method provides a wide range of information. It gives scientists:

• Flushed-zone fluid saturations and volumes.
• Total NMR porosities.
• Bulk volumes of irreducible water.
• Crude oil viscosities.
• Brine T2 distributions and T1/T2 ratios.
• Crude oil T2 and diffusion coefficient distributions.
• Hydrocarbon-corrected permeabilities.

All of these outputs are computed by simultaneous inversion of a simple suite of NMR data using the MRF multifluid relaxation method.

The most important capabilities of the MRF method, according to Kovats, is its ability to accurately determine flushed zone water saturations and oil viscosities.

"So many techniques concentrate on permeability, but viscosity can be equally important," Kovats said. "We have a lot of customers with reservoirs where producibility of hydrocarbons is largely controlled not by permeability but by the viscosity of the oil. They have to be able to differentiate between lighter oils that will flow from heavier, more viscous oils that won't produce. This technology allows us to provide that information."

The addition of the MRF method to NMR logging will expand the use of NMR data, Kovats said.

"If the reservoir engineer has a clear picture of the oil's viscosity, he can make better decisions about optimum completion techniques, artificial lift needs and the necessary surface facilities," he said. "This makes NMR logging a truly multi-disciplinary tool."