Permeability Prediction of Sandstones Based on Mercury Intrusion Method

The use of the mercury intrusion method has been one of the most relevant trends in determining the permeability of porous media in the past decades. In this paper, general knowledge of sandstone reservoir evaluation is delineated including the pore distribution of sandstones and air permeability measurement. Based upon the paradigmatic study conducted by Purcell, a schematic diagram illustrating apparatus used in mercury intrusion is shown and introduced, and the relevant procedure is also outlined. Four significant permeability prediction models are described respectively and compared based on researches focusing on tight rocks. By doing so, this article reveals that the performance of the models is different despite the painstaking analysis and the significance of these studies. The contribution of this present study is providing a general reference of permeability prediction by mercury intrusion method as well as its previous momentous studies, giving a comparison among the given models.

Evaluate Wettability and Production Potential of Tight Reservoirs Through Spontaneous Imbibition Using Time-Lapse NMR and Other Measurements

Several studies have shown that rock-fluid interactions in tight rocks are influenced by the natural wettability behavior of the various pore systems. Studying the water/oil displacement on a smaller scale using core plug imbibition and monitoring with NMR is very insightful in evaluating wettability and distinguishing pore modes and rock types based on their fluid affinity. Extending learnings from plug-scale imbibition process to reservoir production behavior requires understanding of the underlying compositional and/or textural parameters controlling the wettability. This paper presents a systematic study of spontaneous imbibition of oil and water in core plugs procured from several tight and organic-rich reservoirs with varying mineral composition and organic content. The experiment comprised three identical core plugs from the same depth undergoing multiple fluid imbibition cycles with one plug starting in produced brine, the second one in produced crude and the last one in decane. Sample weights were continuously monitored and when stable, a sample which was in brine was moved to crude and the one in crude was moved to brine. This process was repeated for four cycles so that samples that started in brine finally ended up in crude and those that started in crude ended up in brine. The saturation changes and rock-fluid interaction in different fluid types were monitored using a 12 MHz NMR spectrometer. The 12 MHz NMR allowed very accurate partitioning of the oil-filled and water-filled porosity in these tight rocks, which was essential for the wettability analysis. The rate and extent of saturation changes varied significantly from sample to sample. The comparison between the companion plugs imbibing either higher amounts of oil or water revealed the fluid affinity of each sample. We computed the ratio of the net incremental fluid fraction to the total porosity to represent the dominant pore wetting system for rock samples at a given depth. We measured organic content and mineralogy of the samples and analyzed the matrix effect on wettability. We analyzed the post-imbibition NMR relaxation times (T1,T2) of individual fluid types and integrated with matrix properties to evaluate oil and water mobilities. We found predicted fluid mobilities to be consistent with the observed production from wells drilled in the different reservoirs and rock types. We observed most samples attain 100% fluid saturation within two to four cycles and almost all the samples at a given depth took up very similar water volumes irrespective of whether the companion plugs started in brine or crude. The process highlighted that water-wet pores governed the final water saturation, which was strongly correlated with total clay. The amount of organic content and carbonate minerals influenced the oil uptake and its relative mobility. For samples that started in decane, decane was imbibed faster and caused samples to attain higher oil saturation than samples that started in crude.

Work With Chemical Additives Advances Understanding of Relative Permeability Shifts

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201520, “Advances in Understanding Relative Permeability Shifts by Imbibition of Surfactant Solutions Into Tight Plugs,” by Mohammad Yousefi, Lin Yuan, and Hassan Dehghanpour, SPE, University of Alberta, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Various chemical additives have been proposed recently to enhance imbibition oil recovery from tight formations during shut-in periods after hydraulic fracturing operations. In the complete paper, the authors develop and apply a laboratory protocol mimicking leakoff, shut-in, and flowback processes to evaluate the effects of fracturing-fluid additives on oil regained permeability. A conventional coreflooding apparatus is modified to measure oil effective permeability (koeff) before and after the surfactant-imbibition experiments. Methodology Proposed Technique for Measuring Oil Effective Permeability. Despite the simplicity of the steady-state method, measuring permeability of tight rocks with this technique is challenging because of its time-consuming nature and the fact that accurate measurement is necessary of extremely low flow rates corresponding to low injectivity of tight rocks. The authors use a pair of plugs from a well drilled in the Montney formation that is a stratigraphic unit of the Lower Triassic age in the western Canadian sedimentary basin located in British Columbia and Alberta. It is mainly a low-permeability siltstone reservoir. In the modified coreflooding apparatus, the authors reduce the effect of compressibility in order to reduce the duration of the transient period by approximately one order of magnitude. Because monitoring changes in pressure is much easier and more accurate than monitoring flow-rate changes, a constant flow-rate mode is used and pressure is recorded with time. Oil is injected at different constant flow rates (qo), and the inlet pressure is monitored. The stable pressure difference across the plug is recorded for each flow rate. After steady-state conditions are reached based on the pressure profile, the qo is increased. This process is repeated until four stable pressure differences corresponding to four different qo are obtained. After the highest qo is reached, it is decreased in similar steps to check the repeatability of each data point. The permeability is calculated with the Darcy equation and slope of the qo vs. stable pressure difference across the plug.