Advanced Fluid Characterization. Hydrocarbon identification and analysis using NMR

Transcription

1 Advanced Fluid Characterization Hydrocarbon identification and analysis using NMR

2 Applications Determination of fluid storage volume based on lithologyindependent total porosity Quantification of pay based on oil, gas and water saturation Oil mobility determination based on in-situ oil viscosity Producibility calculation using hydrocarbon-corrected bound-water volume and permeability Oil viscosity versus depth mapping for perforation and completion design Direct hydrocarbon detection Fresh, unknown or varying formation water resistivities Low-resistivity, low-contrast pay and thin beds Residual oil saturation in water-based muds Residual water saturation in oil-based muds Mobility calibration for MDT* Modular Formation Dynamics Tester Benefits Improved reserves estimates and increased reserves from location of bypassed pay Optimized well completions Worldwide availability using any standard CMR* Combinable Magnetic Resonance tool Real-time answers from automated wellsite inversion Independent analysis without need for resistivity measurements, R w or Archie parameters Features Automated 3-min acquisition integrated with wellsite inversion Constituent Viscosity Model (CVM) based on fundamental physics Measurement without radioactive source What is the MRF method? The MRF* Magnetic Resonance Fluid characterization method is a patented technique for direct identification and analysis of hydrocarbons. The station log measurement can be made using any CMR tool; special tools or modifications are not necessary. A modified CMR-Plus* tool is required for the fast 3-min data acquisition. The MRF technique integrates downhole data acquisition and wellsite inversion with a multifluid response model to determine fluid saturations, fluid volumes and oil viscosities. Lithologyindependent formation porosity and separate T 2 distributions for brine and oil are also extracted. Hydrocarboncorrected bound-water volume and permeability are computed from the T 2 distributions. This real-time analysis improves prediction of the well s producing capability and is vital for completion decisions. Signal amplitude When is an MRF analysis needed? Viscosity, like permeability, greatly influences a well s producing capability. Viscosity can vary by orders of magnitude, and in many parts of the world it determines zonal production rates to a much greater extent than formation permeability. When hydrocarbon viscosity is varying or unknown, the MRF method can provide the answers you need. MRF technology can also provide solutions in fresh or varying formation waters, where Archie resistivity analysis is difficult. Using direct hydrocarbon characterization, pay intervals can be identified even in zones with low resistivity. The MRF method can overcome problems associated with Archie analysis, such as varying cementation exponent; dipping, thin or laminated beds that affect resistivity tools and unknown or varying water resistivity. This method also overcomes incorrect permeability calculations caused by hydrocarbon effects. Figure 1. Example of real-time MRF analysis performed at the wellsite. The direct, user-friendly analysis provides a comprehensive formation evaluation of the near-wellbore region and includes quality control indicators. Water porosity (%): 17.0 Oil porosity (%): 14.3 Gas porosity (%): 0.0 OBMF porosity (%): 0.0 Water saturation (%): 54.3 Oil saturation (%): 45.7 Gas saturation (%): 0.0 OBMF saturation (%): 0.0 Water T 2LM (ms): 48.8 Oil T 2LM (ms): 180 Oil viscosity (cp): 6.6 TCMR porosity (%): 31.3 Free water φ (%): 14.9 Bound water φ (%): 2.1 T 1 /T 2 ratio: Permeability (md): Temperature ( C): 24.6 Water T 2 log mean Water T 2 distribution Oil T 2 log mean Oil T 2 distribution ,000 10,000 T 2 relaxation time (ms)

3 How does the MRF analysis work? Small or light-end hydrocarbon molecules move at rapid rotational and translational velocities as a result of thermally induced Brownian motion. Figure 2 shows this concept at the microscopic level. At the macroscopic level, the long distances small molecules can travel in a given time are observed as a high molecular diffusion coefficient. Fast molecular motions result in low fluid viscosity. As a result of the low viscosity, small molecules have long T 2 decay times. Large molecules have small rotational and translational velocities and therefore move shorter distances through the fluid. This slow molecular motion results in a low diffusion coefficient for the fluid and a high viscosity value. As a result of the high viscosity, large molecules have short T 2 times. A pure fluid composed of a single molecular species has a single diffusion coefficient value, a single viscosity value and a single value for its T 2 decay. The fluid can be represented as a narrow peak in the T 2 and diffusion spectra. A mixture containing both smalland large-molecule fluids exhibits one T 2 value for the small molecules and another for the large molecules. However, individual T 2 values in the mixture differ from those of the constituent pure fluids. The same result occurs with the diffusion rates. Components in the mixture retain their separate identities while their individual properties are modified. Crude oils are a complex mixture of many different hydrocarbon species with a broad range of molecular sizes. The CVM relates the T 2 and diffusion properties of mixtures to molecular composition. Based on fundamental physics, the CVM properly accounts for the broad diffusivity and T 2 spectra of bulk crude oils. The CVM has been empirically validated for both live and dead crude oils. Constituent viscosity is a phenomenological link between the T 2 relaxation and the diffusion coefficient of each molecular species in a hydrocarbon mixture. The bulk viscosity observed with a viscometer reflects the broad distribution of microscopic or constituent viscosities. Figure 2. Small or light-end member molecules move quickly; heavier long-chain molecules move more slowly. Hydrocarbon molecule relaxation rates and diffusion coefficients are related to the molecule size. With their wide range of molecular sizes, crude oils have a broad distribution of nuclear magnetic resonance (NMR) relaxation times and molecular diffusion coefficients. The Constituent Viscosity Model (CVM) relates molecular diffusivity and T 2 relaxation of the individual components to bulk viscosity. Amplitude Large hydrocarbon molecule slow rotation leads to slow diffusion Pure C30 Small hydrocarbon molecule fast rotation leads to fast diffusion Diffusivity (cm 2 /s) Mixture of C6 and C30 Pure C6

4 The CVM predicts an inverse relationship between the geometric mean of the bulk oil T 2 distribution and the bulk oil viscosity. This relationship has long been observed in laboratory data (Fig. 3). Pore size information is available from T 2 distributions measured in water zones. Brine T 2 distributions are broad as a result of the range of pore sizes found in reservoir rocks. In an oil zone, the brine distribution typically overlaps with the broad T 2 distribution of the oil to form the total T 2 distribution seen on a standard log (right side of Fig. 4). This overlap often makes standard T 2 interpretation difficult because the contributions of water and hydrocarbon are indistinguishable. Pore size information is mixed with hydrocarbon viscosity information. Largely because of this overlap of oil and water T 2 distributions, previous hydrocarbon detection techniques have not been reliable. Figure 3. For bulk crude oils, an inverse relationship exists between the geometric mean of the T 2 distribution and the viscosity. T 2 (s) Light oil API: Density ~ g/cc Medium oil API: Density ~ g/cc Heavy oil API: Density ~ g/cc ,000 10, ,000 Viscosity (cp) Figure 4. In a formation with no hydrocarbons, brine-filled porosity produces T 2 distributions representative of pore-size distributions with associated bound and free fluids (left). The broad T 2 distribution of a typical bulk crude is shown in the center. Because the rock is not present, the bulk crude oil T 2 distribution is a function of molecular composition only. In a typical T 2 log, the addition of the two distributions results in a mixed response that can be difficult to interpret (right). Brine T 2 Distributions Oil T 2 Distributions Total Distribution Pore size Constituent viscosity + = Clay-bound water Capillary-bound water Free water Tar Heavy oil Intermediate oil Light oil Tar plus clay-bound water Heavy oil plus capillary bound water Intermediate oil plus free water Light oil plus free water

5 The MRF method incorporates the fundamental physical principles of the CVM and a multifluid inversion algorithm to reliably extract oil and water signals from NMR data. To achieve this separation, the MRF method exploits molecular diffusion in the field gradient generated by the tool magnet. This process leads to an additional NMR decay proportional to the square of the echo spacing and to the diffusion constant of each fluid component governed by the simple equation shown in Fig. 5. Because water molecules are typically smaller and more mobile than the hydrocarbon molecules in crude oils, the water signal decays faster than the oil signal for long-echo spacings. By inverting a specially designed suite of NMR measurements with different echo spacings, the MRF method separates brine and oil signals even when the T 2 distributions completely overlap. After separation, the individual T 2 distributions are used to compute the volumes of water, gas and oil. Oil viscosity and hydrocarboncorrected bound-fluid volume are calculated. In addition to providing direct and resistivity-independent saturations and volumes, the T 2 distribution of reservoir oil derived during the MRF inversion helps in interpreting the CMR depth log. Figure 5. Schematic of the MRF data suite and simultaneous inversion to extract brine and oil volumes, oil viscosity, and T 2 distributions. The equation describes the decay time of measured NMR signals ( T 2D ) caused by molecular diffusion (D) in the tool gradient (G). The diffusion decay increases with increasing echo spacing ( TE). X655 m Molecular Diffusion in Field Gradient Echo spacing = TE 1 1 T 2D D γ G TE 12 = ( ) 2 2 Brine and Oil T 2 Distributions TE 3 45 cp TE 2 Amplitude X700 m 44 cp X708 m 86 cp T 2 (ms) 1000 Water Oil

6 In what range of viscosities will the MRF method work? The MRF method works in viscosities from less than 1 cp to more than 200 cp (Fig. 6). For viscosities below this range, the DMR* Density-Magnetic Resonance method should be used because hydrocarbons that are very light (such as gas and condensate) result in porosity deficits. Above 200 cp there is a lack of diffusion sensitivity. The shape of the T 2 distribution must be analyzed using the CMR-Plus enhanced precision mode (EPM). For the highest viscosities, hydrocarbons become invisible to NMR tools, which measure fluid only. The DMR method can be used to quantify tar content. Has the method been tested? Schlumberger has validated the MRF method in the laboratory using a broad range of live and dead crude oils and rock types. Its reliability and range of applications have been confirmed by extensive worldwide field tests in diverse environments. Where is the MRF method available? Advanced fluid characterization using the MRF method is available worldwide. Any CMR tool can be used for data acquisition; specially equipped tools or modifications are not necessary. To achieve the fast 3-min station log measurement and perform the realtime wellsite inversion, a modified CMR-Plus tool and special software kit are required. Figure 6. The MRF method works within the range of approximately 1 to 200 cp. Outside this range, the indicated method should be used. Low-MRF Sensitivity MRF-Sensitive Regime Low-MRF Sensitivity 0.5 cp 2 cp 1000 cp 100 cp 10 cp ,000 10,000 Transverse relaxation time T 2 (ms) DMR EPM MRF DMR 100,000 10,000 1, Viscosity (cp)

7 CMR-Plus Tool Specifications Physical specifications Length 15.6 ft Weight 413 lbm Measure point 23 in. above bottom of tool Min hole size in. Max hole size No limit Max tension limit 50,000 lbf Max compression limit 50,000 lbf Operational ratings Max pressure 20,000 psi (25,000 psi with modified tools) Max temperature 350 F Mud type and salinity Unlimited Measurement specifications Max logging speed Long T 1 environment 800 ft/hr Short T 1 environment 2700 ft/hr Bound fluid mode 3600 ft/hr Vertical resolution Static 6-in. measurement aperture Dynamic (high-resolution mode) 9 in., three-level averaging Dynamic (standard mode)) 24 in., three-level averaging Min echo spacing 0.2 ms Measurement range Porosity p.u. T 2 distribution 0.3 ms 3.0 s Precision Total CMR porosity 1-p.u. standard deviation, three-level averaging at 75 F CMR free-fluid porosity 0.5-p.u. standard deviation, three-level averaging at 75 F Depth of investigation All hole sizes 0.5-in. blind zone 1.1-in. 50% point 1.5-in. 95% point

8 SMP-5905 September 2002 Schlumberger *Mark of Schlumberger