H2S Losses in Reservoir Fluid Sample Chambers – A Case Study

Abstract

Abstract To ensure proper selection of reservoir completion, subsea and topside production materials of construction and production chemicals, it is imperative to accurately assess the Hydrogen Sulfide (H2S) concentration in produced reservoir fluids. At high reservoir pressures (>10,000 psi), H2S concentration as low as 50 ppm (mole) or less must be quantified. If an offshore production well test cannot be performed, these assessments must be made based on the analysis of open-hole formation testing samples. Open-hole sampling with formation testing equipment only allows for the production of a relatively small amount of reservoir fluid and exposes the reservoir fluid to potential sites for H2S adsorption/reaction during the sampling process. Sites for potential H2S loss include the contact of the reservoir fluid with oil or water based drilling fluids, the formation tester flowline, and within the formation tester sample chamber after isolation downhole. This work focuses on evaluating the order of magnitude of the H2S loss that may occur in downhole sampling chambers and laboratory storage chambers and the impact of uncertainty in these measurements on the ability to draw conclusions. A number of reservoir fluid sample chambers were filled with standard gases containing H2S concentration levels ranging from 25-100 ppm at 2,000 and 15,000 psia and 100°C. The H2S concentration of the gas in the sample chamber was measured at regular frequencies for a time period of 5 days to evaluate the rate of H2S loss within the chambers. In addition to assessing the impact of the type of sample chamber, chamber coatings, balance gas composition, test pressure and temperature, and sample chamber service cycles were varied to identify key factors affecting H2S loss rates. In addition, two different methods of H2S quantication, stain tubes and Sulfur Chemiluminescence Detector (SCD) were evaluated. Initial measurements indicated that the H2S loss rate over a range of operating conditions was between 0.5 and 25 ppm over a 5 day period and results were reasonably consistent across measurement methods. However, some inconsistencies in the data led to an investigation of the experimental procedure for extracting samples from the sample chambers. This investigation identified a step in the procedure involving isolation of the sample that contributed to an enhanced uncertainty in the measurement. A review of the experimental methodology and a resulting change in test measurement procedure to mitigate the isolation step contribution produced more consistent and repeatable results. Based on the results of the study, it was concluded that it may not be possible to retain sufficient vapor phase H2S in sample chambers to accurately quantify fluid H2S concentration of less than 10 ppm-mole other than via on-site analysis within the first 24 hours of being captured. Furthermore, a zero H2S concentration measurement on a sample withdrawn from one of these chambers after 5 days may be a false negative. Correspondingly, a positive H2S measurement at any level confirms that H2S is present. With regard to evaluation of the analysis methods, it was noted that both methods gave reliable results within the constraints of their respective measurement principles and could be used to reliably quantify ppm H2S concentrations provided the proper procedure is followed. Finally, it is noted that there remain a number of variables that could impact the H2S loss rate that were not evaluated in the study including the effect of reservoir fluid type (oil or gas) to name one. Further study will be required to fully assess the performance of these and other sample chambers over a full range of typical operating conditions.