On-Site Reservoir Fluid Properties Evaluation
Authors: Varotsis Nikos , Guleze Paul 
Published: December 2007

This paper describes a new method, the fluid properties estimation (FPESM), that can be used at the wellsite to provide realistic predictions of PVT andphysical predictions of PVT and physical properties of the reservoir fluidduring properties of the reservoir fluid during testing. Simple and rapidmeasurements of key fluid properties and onsite compositional analysis of theproduced fluid are input data for an produced fluid are input data for anequation-of-state (EOS) -based thermodynamic model. The simulator is tunedprimarily by regression to match the measured data and is subsequently used topredict the phase behavior and PVT properties of fluids produced at reservoir, well, and produced at reservoir, well, and surface conditions. The method, which is currently applicable only to oil reservoirs, has been successfullytested in several areas of the world. Examples given compare on-site FPEpredictions with full PVT studies performed in the laboratory. performed in thelaboratory. Introduction

Reservoir fluid physical property values constitute an integral part of thedata required for a comprehensive study of the reservoir and for optimal designof oil recovery and production schemes. More specifically, PVT datacorresponding to the reservoir fluid are needed to validate the well testproperly and to provide meaningful interpretation. The optimum design of thewell completion and surface facilities is possible only when the type andvolume of the possible only when the type and volume of the fluids flowingthrough the wellbore and produced through the separator are known. In producedthrough the separator are known. In addition, estimation of reservoir reservesand design of the best depletion strategy are feasible only when realistic andreasonably accurate values of the reservoir fluid properties are available.properties are available. Analysis of a representative fluid sample performedin a specialized PVT laboratory performed in a specialized PVT laboratoryoffers solutions. In most cases, however, because of backlogs and expeditionand transportation problems, the laboratory report becomes available to theoperating company several months after the well test. Meanwhile, crucialdecisions concerning planning and management of the reservoir have to be madeon the basis of physical property values. These values are currently derivedfrom empirical correlations, and the accuracy of the predictions depends on howclosely the chemical composition of the fluid being tested approaches that ofthe fluids used to derive the correlations.

The quality of the PVT laboratory results depends entirely on the validityof the sample used for the analysis. The only validity check currentlyperformed on site, if any, compares only the saturation pressure of therecovered sample, measured at ambient temperature and corrected with charts tobottomhole conditions, to the reservoir's static and flowing pressure. Occasionally, the operating companies discover that the sample taken during thewell test is invalid months after the rig has been moved away.

Alternative On-Site Approaches

The PVT and physical property data of a reservoir fluid currently areobtained at the wellsite by prediction with empirical correlations ormeasurement with portable PVT laboratories.

Rapid answers at no cost are the advantages of the first approach. Nevertheless, a considerable risk concerning the accuracy of these predictionsis taken, as the examples presented in Table 1 show. Table 1 comparesestimations for bubblepoint pressure, pb, and FVF, Bo, given by three of thepb, and FVF, Bo, given by three of the best-known correlations (Standing, Glasoand Lasater) with values measured in a PVT laboratory. Each of the five oilsused for this comparison comes from a different continent. Simple calculationsprove that underestimation of the oil FVF by 20% (not unusual when empiricalcorrelations are used) results in an overestimation of the stock-tank oiloriginally in place by the same percentage. In addition, correlations providedata that are limited to certain conditions (e.g., bubblepoint), and becausethe compositional analysis of the fluid is not considered, they fail to predictthe evolution of each property as the main reservoir parameters change duringdepletion. parameters change during depletion. The second approach, although itoffers measurements, involves considerable investment inhigh-pressure/high-temperature equipment and requires the presence ofwelltrained, experienced personnel at the wellsite. Because the PVT studyshould always be performed under perfect equilibrium conditions, several hours, if not days, of rig time are required. In addition, the weight and volumelimitations imposed on equipment transported to the rig dictate that onsite PVTequipment has a considerably reduced volume compared to that used in thelaboratory. The reduction of the sample volume inevitably leads to lessaccurate measurements.

The strategy selected for development of the FPE combines features of bothapproaches. Simple measurements of key physical properties, specially selectedto characterize properties, specially selected to characterize the reservoirfluid, are performed on site with easily operated, portable equipment. Thesemeasurements are used as calibration points to tune an EOS-based simulator thatsubsequently predicts the phase behavior of the fluids at reservoir, phasebehavior of the fluids at reservoir, well, and surface conditions.

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