Differentiating Between Oil-Base Mud Filtrate and Multiphase Formation Fluids Using Wireline Formation Testing Techniques: Case Studies from Saudi Arabia
Authors: Al-Harthi Muhammad , Kelly Francis , Alenezi Faisal N , Soleiman Wael 
Published: March 2015

In wireline formation testing and sampling, a difficult and long standing challenge is the differentiation between mud filtrate and formation fluids, especially in oil-based mud (OBM) (diesel/water mixture) and multiphase formation fluids (oil/formation water) environments. This challenge can cause ambiguities during the interpretation of downhole fluid properties and determination of the contamination levels before sampling.

Often, during the sampling process, fluid mixing increases fluid property sensor noise and causes difficulties with accurate fluid identification and contamination levels. Consequently, noisy sensor readings are attributed to the transitional phase of sampling and pertinent information is ignored.

This paper presents several examples where fluid mixing has occurred. A high-resolution volumetric densitometer is used to accurately identify fluid properties. It monitors the change of frequency of a vibrating tube immersed in the fluid sample.

Because of the high accuracy of this technique, it is also possible to determine additional fluid properties, such as density, water salinity, and fluid compressibility. Furthermore, new processing methods are illustrated, which provide a clearer understanding of flow behavior and allow more accurate estimates of fluid contamination. The examples are verified using fluid volumetrically maintained at the reservoir pressure and temperature (PVT) lab results comparing the downhole real-time fluid property measurements and interpretation with the actual fluid samples recovered.

Introduction

In many cases, when sampling with a pumpout wireline formation testing (PWFT), multiphase flow conditions are encountered and are very difficult to interpret. This normally occurs in most cases when sampling oil in water-based mud (WBM) or water in OBM; yet, the most challenging case involves sampling in a transition zone (formation oil/water) in an OBM environment where the invading mud filtrate fluid varies in mixture between the diesel base and water base ratio in the OBM system used.

Depending on the fluid identification sensor type of measurement and other parameters such as sensor sensitivity, nature of the measurement, sensor sampling rate, and the volume of fluid that the sensor detects, multi-phase fluid flow can be characterized from the beginning of the cleanout process till clean representative formation fluid samples can be captured. Fluid identification sensors by themselves cannot solve the complexity of multiphase formation fluid in OBM environments. Invasion modeling and contamination prediction models must be used along the downhole fluid identification (ID) sensors to assess the process of the cleanout from the filtrate to the clean native formation fluids (Eyuboglu et al. 2011). Moreover, the probe type to be used during sampling also has great implication regarding the nature of the flow regime and can be used for solving fluid typing during the pumpout process, knowing the flow regime it follows and or using phase segregation to identify clean fluids and ratios.