Abstract

In addition to geological and petrophysical data acquisition during the exploration stage, in-situ fluid analysis provides a wealth of information for the appraisal of new discoveries. A recently introduced wireline sampling tool incorporating a downhole fluid analyzer is capable of analyzing fluid composition in real time at downhole conditions, and of measuring the fluorescence spectra of crude oils. These new measurements provide valuable information necessary for the identification and validation of reservoir structures that define the distribution of fluids in the accumulation. The relevance of high quality fluid data in the early stages of the producing life of the reservoir is widely recognized. We present field results of the application of the new sampling tool in an exploration well, where a composition gradient was detected along a 30m liquid hydrocarbon column grading from a 45API crude on the top to a 33API crude on the bottom. During the sampling of the gas cap, retrograde dew formation was detected identifying the fluid and identifying valid sampling conditions. This new information was used to modify the sampling program. Fluid composition analysis relies on optical absorption methods and is currently capable of providing the mass fraction of three hydrocarbon molecular groups: C1, C2–5 and C6+, and CO2. We perform fluorescence spectroscopy by measuring light emission in the green and red ranges of the spectrum after excitation with blue light. Fluorescence in this range is related to the concentration of polycyclic aromatic hydrocarbons (PAH's) in the crude oil. Using the pump-out module to segregate different fluid phase enhances phase detection with fluorescence.

Introduction

Fluid properties relevant to reservoir evaluation are determined, for the most part, by laboratory analysis of recovered samples, with the laboratory results being only as good as the samples provided. One main issue therefore for reservoir characterization is fluid sample validity/quality. Bottomhole samples are expected to be more representative of the original hydrocarbon since they are acquired and maintained at conditions similar to those in the reservoir. Valid sampling must satisfy two conditions: first, a minimum amount of contamination from foreign agents especially miscible mud filtrate should be present in the sample; and second, that sampling should be conducted under conditions guaranteeing that the fluid has not undergone any phase transitions; different phase have different mobilities yielding acquisition of nonrepresentative samples. Phase transitions may be induced by changes in pressure and/or temperature, the former being the most commonly encountered when sampling with wireline tools. Miscible contamination can also alter phase behavior.

When the saturation pressure of the reservoir is unknown, as is mostly the case, the monitoring of fluid composition and fluorescence will indicate if the sampling pressure has fallen below the saturation pressure of the fluid. The sample will then be collected or not according to criteria based on the stability of the composition, and the minimization of filtrate contamination.

To identify a retrograde condensate, one can steadily drop the sampling pressure below the saturation pressure of the fluid to observe the change in the fluorescence signal that will occurs with dew formation at the dew point pressure. This is a useful test for reservoir development since it identifies the existence of retrograde condensate, provides a real-time estimate of the fluid dew pressure, and gives information about the effects of two-phase flow on production performance. We can also monitor the estimated dew point against oil based mud (OBM) contamination.

This content is only available via PDF.
You can access this article if you purchase or spend a download.