- [Geoffrey] So if we compare those two, the fluid volumes from NMR, the fluid volumes from the resistivity-based, in a perfect reservoir, if we've done all our calibrations, corrections, and I'm assuming here that things like the NMR, we've done hydrogen index corrections, then the bound water volume should match the porosity times water saturation from resistivity and the movable fluid volume should match the porosity times the hydrocarbon saturation from resistivity. Now, the difference is, before everybody shouts out, "No, that isn't always the case," that's the whole point of the following slides, looking at what causes these to be different, what sort of things you need to consider when comparing these volumes and what affects them. And hence, what other information on the reservoir you can extract by comparing these two measurements. So that gives us our framework for comparing the water volumes and the porosity times saturation, water volume from resistivity, and our overall comparison of all volumes. The first thing to start to consider maybe is invasion. Are these tools measuring the same thing? NMR has a depth of investigation typically between two and four inches. Both water line and LWD are seeing similar depth of investigation. Water line, may be making the measurement within a few days of drilling the well. LWD, typically, we'll be seeing the data from the NMR tools, maybe a couple of hours after drilling the well because they tend to be placed towards the back of the Boil Assembly. Whereas resistivity can have a depth of investigation of maybe only a few inches for some of the shallow pad-based tools, to many feet. So we need to be careful about what we're comparing with which and what sort of invasion we think we have got. For resistivity data, for water line, again, it's a few days off to the wells drills. LWD may be much closer to the drilling of the well as typically resistivity measurements are very close to the drill bit. The different fluids, heavy oils and tars in particular have some different effects on the NMR data. Heavy oil can move down the two-two spectrum and in fact, can get it into the area which we typically expect to see at abound fluids. With some of the more technological tools like the wireline tools, we can actually still extract those different fluid types using 2D, 3D, NMR-type plots where we're measuring maybe both T1, T2, and diffusivity. Can't be more difficult from LWD data. When you get the very heavy fluids like tars, then certainly they will get down into the barren water range for the capillary bound fluids, even into the clay-bound fluids and below the T2 that is actually measurable, resulting sometimes in a porosity undercall. We'll show example of this in one the slides later on. Resistivity data essentially doesn't see the hydrocarbons at all, in fact, so of course has the same response for all the hydrocarbon types, it's nonconductive so it's the one-minus water saturation fracture, fraction of the porosity. Different mineral types also have different effects on both NMR and resistivity. Magnetic minerals can introduce different relaxations, shortening the T2, giving a required reduction of the T2 cutoff. An example here in this plot, where we've got increasing iron content, where you need a different T2 cutoff. If we're here in this table here, here's a table of iron content, below about 4% here, it was found, cutoff of 30 works quite well, as you increase the iron content, you need to decrease the cutoff in order to see the volumes correctly. Resistivity is also affected by the mineralogy. We can have conductive clays, for instance, which add additional conductivity, needing those more complex resistivity equations. You can also have some very thin layers of some minerals, like mica, pyrite, I believe in Oman there are some reservoirs with a very thin conductive layers, that really reduce the saturation or the apparent saturations that are calculated if that's not taken account of. So both tools can be effective by the mineralogy as well. So bringing in other information, core data, cuttings data, et cetera, knowing what this is helps interpret both of these as well. The wettability of the rock and the surface interaction can effect the NMR data. Essentially, whatever is the wetting fluid will be affected by the surface interaction with the grains, generally causing a reduction in the T2. So normally, we see the effects on the water components and water-wet rock, and the T2 value is related to the pore size. If you start to get an oil-wet rock, the oil then is in contact with the surface and its boat values will be reduced by the T2 or the effect that we see will be reduced by that surface interaction, as visible on the T2 distribution. Resistivity, as well, of course, is affected by wettability. If you increase the oil contact with the rock, you start to have a less continuous water film through the rock, that means that the resistivities will increase. This can manifest itself as a rapid increase in the Archie n exponent, the saturation exponent. An example here of a 1986 paper where we've got the water-wet rock has a typical Archie value of two increasing to a very high oil-wet rock of n factor there up to 25 in this case. So it can affect, wettability can affect both measurements. The NMR, we often see this in oil-based filtrates, that you have to sometimes increase the T2 cutoff when working with oil-based muds because chemicals in the mud light's refractance can change the wettability of the shallow invaded rock, and requiring... Quite often people go up to around 18, 19 millisecond cutoff, instead of the default 33 for sandstones. The answer of course is core data for that.