Within laminated sands, bound fluid is associated with shale laminations, and aggregate free-fluid volume is associated with sand laminations. Diffusion data can provide fluid properties when sufficient quantities are available in the reservoir rocks. Although the depth of investigation is deeper than that of imaging tools, NMR measurements are still quite shallow. A recently introduced third method of evalu - ating laminated sand-shale sequences incorporates high-resolution porosity informa tion and induction tool data, such as those from the Rt Scanner triaxial induction service.21
This tool measures
horizontal, Rh, and vertical, Rv, resistivities. In laminated sands, the hydrocarbon-bearing sand laminations exhibit electrical anisotropy, indi - cated by a high Rv/Rh ratio, whereas water- bearing sand-shale sequences have low ratios. Reservoir evaluation based on the electrical anisotropy alone is not sufficient to prove the presence of hydrocarbon. Anisotropic shales exhibit high Rv/Rh ratios even in the absence of hydrocarbon-bearing sand layers because of formation compaction.
In an even newer technique, MR Scanner fluid measurements are combined with the Rt Scanner Rv /Rh method to provide critical information for properly analyzing complex sand- shale reservoirs. This method yields sand fraction (net-to-gross), sand porosity, sand resistivity and hydrocarbon saturation. The key to maximizing the value of the information is integration of the data from the various sources. This complementary integra tion technique was recently demonstrated in a west Africa reservoir. Characterized as having a thin sand- shale sequence, the well in this case study was evaluated with MR Scanner data, Rt Scanner information and high-resolution porosity data from formation density and neutron logs. Once thin beds with hydrocarbon potential had been identified from image data, the petrophysicist followed an established workflow to interpret them: • Compute the sand fraction, Fsand, from the porosity data.
• Derive sand resistivity, Rsand, from Rv and Rh data.
• Compute an NMR Fsand from the T2 distributions. • Derive a new Rsand. • Compute the porosity of the sand layers, Phisand, from both the density-neutron data and the NMR T2 distributions.
• Compare water saturations computed with inputs from the NMR data with those derived from the Rt Scanner and high-resolution porosity data.
With this workflow, the data analysis for this well began with identifying laminations from the image log of the OBMI oil-base microimager (previous page). Rv values are greater than Rh values, indicating electrical anisotropy. But, the Rv/Rh ratio is high in clean shales as well as in laminated sand-shale sections.
Shales have only bound fluids and thus a
unimodal T2 distribution. Sand-shale sequences exhibit a bimodal distribution, indicative of movable fluids in sand laminations. Thus, the sand fraction, Fsand, can be derived from the free- fluid portion of the NMR T2 data. This value is then compared with the Fsand value derived from the density-neutron data. Rsand values are computed from the triaxial induction tool data for both Fsand inputs. The NMR fluid analysis of data from the 2.7-in. shell indicates native oil and OBM filtrate.
Three analysis methods for water saturation are used to calculate the hydrocarbon volume: Archie’s water saturation equation, the Rv and Rh method using triaxial induction tool data, and NMR fluid saturations. Rv and Rh crossplots are presented using a Schlumberger modified Klein plot technique.22
The selected points from the
crossplot are transposed on the log, identifying quality reservoir intervals. Anisotropic shales plot in the nonpay region and may be ignored. With this technique, the log analyst quickly assesses the reservoir and identifies potential pay zones. This integrated approach resulted in an 80% increase in calculated net-to-gross values as compared with classical resistivity-porosity methods. An increase of 18 net hydrocarbon feet [5.5 m] is derived from the NMR-based satura - tions, and there is an increase of 15 net feet [4.6 m] using the triaxial induction technique without NMR data. The conclusion from the log evalua - tion is that NMR data enhance the calculation for hydro carbons in place, while corroborating the results of triaxial induction-based laminated- sand analysis. The technique offers the petro physicist the ability to identify quality reservoir intervals and eliminate nonproductive anisotropic shale intervals from evaluation.
Mapping the Future of Magnetic Resonance Magnetic resonance logging has transcended its niche market status and attained a high level of acceptability within the petrophysical com - munity. It will never supplant resistivity and nuclear porosity measurements; nor should it. NMR data offer the oil and gas industry an alternative source for certain measurements, including porosity and fluid saturations, yet there are limitations inherent in the physics—as there are in all petrophysical measurements.
Winter 2008/2009
New enhancements to the software for making 2D maps of reservoir fluids create static snapshots that can then be added to 2D logs. In addition, the software has the capability to present saturations and fluid properties in a video format, allowing visualization of the changes that take place laterally along the wellbore and horizontally into the formation. Laboratory-based NMR fluid measurements have been and will continue to be transferred to the downhole environment. Obtaining the proper - ties of sampled fluids while tools are still downhole offers the closest approximation to in situ measurements available. An NMR oil classification system exists based on molecular properties, and applying that classi fication to downhole fluids will aid in proper reservoir development.23 But one of the unique aspects of NMR measurements is that they offer the only technique that can see and distinguish different fluids in situ, without flowing them. Even downhole samples may not provide true fluid properties because of changes to the fluids during flow. Sampled fluids do not reflect the true distri bution of fluids in the reservoir, only those that are mobile. As NMR techniques are applied, and fluid variations within reservoirs are identified, the complicated nature of oil and gas production is better understood. With reservoir under standing come informed production practices, greater efficiencies and higher recovery rates.
Viable options exist for future development. Researchers continue to develop NMR-based carbonate answers. Deeper measurements are a goal, but tools to acquire them are years away. Although there may never be an NMR measurement from the virgin reservoir, fluid properties from LWD tools offer a glimpse into the reservoir fluids unaffected by mud filtrate. Such a solution would overcome the problem identified in the Saudi Aramco HRLC wells. Other challenges await further research and development. It took 30 years to develop a workable magnetic resonance tool for downhole environ - ments. NMR measurements have continued to evolve along with the tools used to acquire the data. The most recent developments put a colorful visualization technique in the hands of the petrophysicist. The art and science of NMR applications have been combined to provide an alternative to static 2D logs of the past. These new dimensions in NMR logging have ushered in a powerful tool for reservoir analysis. But the best may be yet to come.
—TS
23
Page 1 |
Page 2 |
Page 3 |
Page 4 |
Page 5 |
Page 6 |
Page 7 |
Page 8 |
Page 9 |
Page 10 |
Page 11 |
Page 12 |
Page 13 |
Page 14 |
Page 15 |
Page 16 |
Page 17 |
Page 18 |
Page 19 |
Page 20 |
Page 21 |
Page 22 |
Page 23 |
Page 24 |
Page 25 |
Page 26 |
Page 27 |
Page 28 |
Page 29 |
Page 30 |
Page 31 |
Page 32 |
Page 33 |
Page 34 |
Page 35 |
Page 36 |
Page 37 |
Page 38 |
Page 39 |
Page 40 |
Page 41 |
Page 42 |
Page 43 |
Page 44 |
Page 45 |
Page 46 |
Page 47 |
Page 48 |
Page 49 |
Page 50 |
Page 51 |
Page 52 |
Page 53 |
Page 54 |
Page 55 |
Page 56 |
Page 57 |
Page 58 |
Page 59 |
Page 60 |
Page 61 |
Page 62 |
Page 63 |
Page 64 |
Page 65 |
Page 66 |
Page 67 |
Page 68 |
Page 69 |
Page 70 |
Page 71 |
Page 72