Estimating Multiphase-Flow Properties From Dual-Packer Formation-Tester Interval Tests and Openhole Array Resistivity Measurement.
- M. Zeybek (Schlumberger Oilfield Services) | T.S. Ramakrishnan (Schlumberger-Doll Research) | S.P. Salamy (Saudi Aramco) | F.J. Kuchuk (Schlumberger Oilfield Services)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- February 2004
- Document Type
- Journal Paper
- 40 - 46
- 2004. Society of Petroleum Engineers
- 3.3 Well & Reservoir Surveillance and Monitoring, 4.3.4 Scale, 5.5.8 History Matching, 5.1 Reservoir Characterisation, 5.8.7 Carbonate Reservoir, 1.11 Drilling Fluids and Materials, 5.6.9 Production Forecasting, 5.2 Reservoir Fluid Dynamics, 5.6.1 Open hole/cased hole log analysis, 5.3.2 Multiphase Flow, 3.3.1 Production Logging, 4.6 Natural Gas, 1.10 Drilling Equipment, 5.8.1 Tight Gas, 4.2 Pipelines, Flowlines and Risers, 5.5 Reservoir Simulation, 4.1.2 Separation and Treating, 6.5.7 Climate Change, 5.3.1 Flow in Porous Media, 5.6.3 Pressure Transient Testing, 5.6.5 Tracers, 5.3.4 Reduction of Residual Oil Saturation, 1.2.3 Rock properties, 5.5.11 Formation Testing (e.g., Wireline, LWD)
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Multiphase flow and production cuts are affected significantly by relative permeabilities under reservoir conditions. However, their in-situ determination is practiced only in isolated instances, and these have used array resistivity logging. Although wireline dual-packer formation testers provide direct flow tests, analysis thus far has been confined to the determination of single-phase permeability and anisotropy. In this paper, we present a methodology to integrate the formation-tester pressure and water-fraction measurements with openhole array resistivity measurements to obtain zonal relative permeabilities of oil and water.
It has been demonstrated previously that the filtrate-invasion process, although uncontrolled, contains quantitative information about fractional flow. The sampling process is similar; it is described by the multiphase/multicomponent flow equations for which the initial condition is set by the invasion process. Geometrically, while the invasion process is largely cylindrical, the sampling process is not. To combine the two, we parameterize the invasion problem in terms of multiphase-flow properties and drilling-fluid loss and carry out a simulation exercise, including generation of resistivity logs. The fractional-flow parameters estimated by matching the observed resistivity logs are then used for modeling fluid sampling with a formation tester. Simultaneous matching of the simulation results with the observed water-cut and pressure data allowed for further refinement of the relative permeability curves. A field example of the application of this methodology will be discussed.
Characterization of permeability and determination of pressure distributions are essential for successful reservoir management. Historically, formation testers in various configurations have been used to obtain zonal horizontal and vertical permeabilities.1-7 The governing interpretation principles use the relevant geology to identify the multizones, but otherwise they are based on the equations of single-phase pressure-transient analysis. A computationally efficient optimization algorithm that allows simultaneous parameter estimation of the unknowns, such as the horizontal and vertical permeabilities, drives the entire estimation procedure. 8,9 For many formations (anisotropic, layered, composite), this procedure has been thought to be adequate. Multiphase-flow issues caused by filtrate movement have received scant attention for modeling the sampling process.
In contrast, in continuous wireline logging, invasion has been the subject of several studies because of its adverse effects in estimating formation properties.10,11 While most studies focused on correcting the effect of invasion on logging measurements, recent methods have exploited the idea that the "contaminated" logs may be used to invert the two-phase-flow properties of the formation.12,13 This inversion is based on a theorem, which states that a single snapshot of radial conductivity variation is sufficient to reconstruct the two-phase flow behavior of the formation.14 Complementing this, in tight gas sands, the signature of invasion on resistivity logs has been used to estimate permeability.15
Independent of the fractional-flow inversion obtained from array resistivity data, formation testers with fluid analyzers are used for sample collection and mobile-fluid identification.16,17 In the estimation of permeability, these sampling data are simply ignored. In this paper, we have made an attempt to maximize the use of such data to improve the openhole fractional-flow and relative permeability estimates from resistivity data. In particular, we have considered the dual-packer configuration.
The dual-packer implementation of the formation tester consists of packers, each of which is approximately 1 m in height and set against the borehole wall to hydraulically isolate the tested section from the rest of the wellbore. Outside of the packed interval, the mudcake isolates the formation from the borehole. The formation fluid is produced through the packed-off interval until the formation fluid is seen by a fluid analyzer. The analyzer is based on transmitted light spectrometry and provides a quantitative fraction of fluids such as water and oil. Under conditions of zero-slip velocity, the holdup fraction of fluids reflects the water cut. Therefore, these data can be used to history match the sampling process through a reservoir simulator to obtain relative permeabilities or, better yet, improve the flow characterization estimated from openhole logs.
For this paper, a commercial numerical reservoir simulator was used to simulate two-phase flow during sampling. We have used actual field data with the formation tester set in a transition zone of a Middle East Cretaceous carbonate formation. Because of the low formation permeability, the dual-packer configuration was preferred to a probe, thus allowing larger flow rates. Before sampling, an array-induction tool was used to obtain resistivity logs with multiple depths of investigation. Initialization of the invasion profile and relative permeabilities for the simulator was obtained from the inversion of the resistivity logs. These relative permeabilities were scaled and refined by matching the observed and simulated water cut and pressure. Currently, our refinement process is sequential (i.e., the improvement to the inversion is not subsequently used to correct the array resistivity inversion for successive refinements). This was made unnecessary in this particular example because of a good agreement between the initial guess and the final answers.
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