The composite log produced by Schlumberger Carbonate Advisor integrated evaluation of a Cretaceous Middle Eastern reservoir displays volumetric analysis and fractional flow logs in Tracks 1 and 2, respectively. Measured NMR T2 distributions are in Track 3, and porosity and permeability from the Schlumberger Carbonate Advisor analysis are compared with core and minipermeameter data in Tracks 4 and 5. Despite the relatively simple lithology — predominantly calcite — Schlumberger Carbonate Advisor evaluation reveals that the pore geometry displays a remarkable degree of variability. Zones containing substantial amounts of macroporosity are interspersed with intervals dominated by mesoporosity and lesser amounts of microporosity. Both array induction and array laterolog tools were logged over the entire interval. A full analysis of relative permeability and saturation was performed with each log, and the results were merged according to the validity of the measurements in each interval. The final result is a single optimal evaluation of relative permeability and saturation.

Considering that some of the world’s largest oil fields are located in carbonate reservoirs, these holders of riches don’t seem to be very popular with the petrophysical community. And with good reason — characterizing carbonate reservoirs is an insanely difficult challenge.

Unlike their sandstone cousins, carbonates’ mineralogy can be deceptively simple while exhibiting wildly varying permeability and porosity, even within a relatively small section of the reservoir. Since an understanding of these issues is crucial to completion and production strategies, it’s no wonder that well log analysts lose sleep wondering if their interpretations are at all correct.

To put it in some perspective, Bernard Montaron, carbonates theme director for Schlumberger, said, “In Norway, examples have been published where they have been able to extract 70% of the oil from a sandstone reservoir. At the other end of the scale, there are published examples of carbonate reservoirs where only 2% of the oil has been produced after 20 years.”

Schlumberger has, in fact, placed carbonates as such a high priority that it has a dedicated center in Dhahran, Saudi Arabia, to serve as the hub for carbonate research. While this center and others around the world are examining a host of issues related to carbonates, the main goal, Montaron said, is to find ways to better characterize these challenging reservoirs and to understand recovery mechanisms.

This takes a two-fold approach. The first part is getting the right information from the logging string. A standard triple-combo tool works well in clastic reservoirs, but might miss some key information in carbonates.

To illustrate this, Raghu Ramamoorthy, advisor-petrophysics for Schlumberger, showed an example of a triple-combo log run in carbonates. The gamma ray, resistivity, and density and neutron log tracks all seem to indicate a very uniform zone. According to the triple-combo log, the mineralogy is mostly limestone.

When Ramamoorthy showed results from a nuclear magnetic resonance (NMR) log, everything changed. NMR logs measure pore geometry, and in this case (a Cretaceous carbonate) the pore size distribution changes dramatically from the top of the zone to the bottom.

“I could not have guessed this from any of these other logs,” Ramamoorthy said. “If you have no information on pore geometry, you will not capture this information.” He added that NMR logs, borehole images, and acoustic logs can all provide the pore geometry.

Part of the problem is that pore geometry and mineralogy are very weakly correlated in carbonates, unlike sandstones. They also may contain dispersed anhydrites, which a standard triple-combo log will not pick up. Elemental capture spectroscopy (ECS) logs are helpful in determining this additional mineralogy information.

There are other complications as well. “To evaluate saturation from resistivity, you use Archie’s law,” he said. “Archie requires the exponent ‘m,’ which is the cementation exponent. In carbonates the exponent is not constant. Depending on how vuggy the carbonate is, you can have an elevated value of m. And it varies from depth level to depth level.

“Wettability in carbonate is a function of the saturation history, and it also affects the saturation exponent, ‘n.’ All of this makes it difficult for the basic triple-combo log to get a complete petrophysical evaluation.”

The final step

Having the right tools is the first part of the equation. The second part is a workflow that ties the information together into a useful petrophysical interpretation.

Schlumberger recently launched a service called Carbonate Advisor that integrates disparate sources of data to provide a better reservoir characterization.

Ramamoorthy said that this attention to carbonates is not new. “Some of the best minds in petrophysics have gently hinted that this is how we should be doing things, and this goes back 50 years,” he said. “What we have done is to take that framework and put it into an integrated workflow. It’s taken us more than a decade, and a global team of 22 petrophysics experts, to get to this point.”

The process began in 1950 when Gus Archie published his now-famous paper in the AAPG Bulletin. Archie coined the term “petrophysics” and said it should correlate to petrology — the rock and pore structure — the way geophysics relates to geology. In 1952 he devised a rock typing scheme for carbonates based on pore geometry.

“There’s our father of petrophysics telling us that if we want to perform petrophysics, we need to understand pore geometry,” Ramamoorthy said.

Later work involved linking pore geometry to both the acoustical transform and the electrical transform. Then Ramakrishnan and colleagues published a paper that developed a scheme of pore partitions — micro, macro, and vugs — which could be applied to permeability and saturation estimation.

“These all refer to individual aspects of carbonate petrophysics,” he said. “What we did then was to string all of that together in an integrated workflow.”

Carbonate Advisor sorts the workflow into three steps. Step one is to solve lithology, porosity, and volumes of tar and gas, which can be derived from a density, neutron, NMR, or ECS log. This information is input into the model along with the logging tools used and any core data that might be available.

The second step is to determine the pore geometry. This is obtained by portioning the pore spaces, a task made easier by deploying an NMR logging tool that uses short echo spacing. Data from borehole images or acoustics can also be included. The pore portioning is used to determine permeability and rock types. NMR data also provides drainage capillary pressure.

The final step is to determine saturation. “For saturation we can use the partition information to get a cementation exponent and then use the deep and shallow resistivity to get saturation,” Ramamoorthy said. Yet more logs can be used for this step, either an array induction log or array laterolog. These can solve flow equations by measuring the two-phase flow of the drilling fluid as it invades the formation. This in turn provides a measurement of relative permeability.

“We have completely different measurements that, in the end, show the same information,” he said. “When you put these things together, you start to get a lot of geological insights.”

Why does it matter?

This information has been available for many years, but until now the only truly accurate way to characterize a carbonate reservoir was through core analysis, which can take more than a year. Carbonate Advisor can provide the same information within minutes.

“I have had very positive and heartening responses,” Ramamoorthy said. “In one case a customer had given me the formation layers he had. I determined the effective
relative permeability curve, and when I showed it to him, I had no idea if I was right. The moment he saw it, he dragged me into his office and showed me the relative permeability curves used in his simulator. He was amazed at how closely they matched.”

Added Martin Isaacs, marketing communications manager, wireline, Schlumberger, “We have been listening carefully to our customers regarding their carbonate reservoir challenges. Among those challenges, at the top of the list was the accurate determination of saturation, porosity, and permeability. This was confirmed during the 2006 Carbonate Day event in Dubai. The launch of Carbonate Advisor is an important piece of our response to this need.”

Ramamoorthy commented that, while most customers are comfortable with triple-combo data, adding newer elements like NMR, ECS, or even formation imaging information makes the integration challenge much more daunting. “With Carbonate Advisor we are able to read that data and give our customers some information within a matter of minutes. It’s a quick, comprehensive, and accurate analysis that is done by playing to the strengths of the individual tools. Sometimes even I forget the complexity of the science and the team behind the workflow, but that’s the beauty of a good design — on the surface it seems so simple.”