After winning an Alexander von Humboldt fellowship by Dr. Sadeghnejad, the collaboration of PermLab with the Institut für Geowissenschaften at the Johannes Gutenberg University of Mainz (JGU), Germany has been finally started in early 2020.
The idea of this research collaboration is to define several joint MSc and Ph.D. theses and dissertations on Digital Core Analysis and Deep Learning applications in petroleum engineering and publishing joint papers. One cosupervisor/advisor will be assigned to theses and dissertations from both sides and PermLab’s members will access the HPC infrastructure of JGU during this period.
Dr. Amir Farasat (alumni PhD. student at TMU) and Mr. Hossein Younesian-Farid (alumni Msc. student) from PermLab could publish their fundings on PPG flooding into mature waterflooded reservoirs in JPSE. Congrats to both of them for their great effort in finalizing this paper.
Conformance control study of preformed particle gels (PPGs) in mature waterflooded reservoirs: numerical and experimental investigations
In this study, a new mathematical transport model of PPG injection in mature waterflooded reservoirs is developed. The model is based on the experimental results of PPG swelling ratio and entrapment analyses in a carbonate rock sample. The entrapment is considered a function of the PPG-to-pore size ratio, fluid velocity, temperature, salinity, PPG concentration, and swelling ratio. The formulations of the resistance factor (RF) and residual resistance factor (RRF) are obtained from the injection experiment results at various fluid velocity and PPG concentrations. The entrapment model is coupled with the transport equations of the MATLAB Reservoir Simulation Toolbox (MRST). The model is validated by predicting the pressure drop changes during the 1D PPG injection experiments at three different flow rates. The validated model is then used to predict PPG transport behavior in several 3D field-scale scenarios.
Abolfazl Moslemipour could publish his findings from the MSc. thesis in Advance in Water Resources Journal. Many congrats to Abolfazl for this great achievement. The title of this paper is “Dual-Scale Pore Network Reconstruction of Vugular Carbonates using Multi-Scale Imaging Techniques“.
In this study, a dual-scale PNM was implemented to reconstruct the behavior of a vuggy carbonate sample. The rock sample was CT scanned at two different scales. At the macro-scale (i.e., vugular-network), a medical-CT scanner was used to image the rock sample at the resolution of 100 μm. The rock was also imaged by a micro-CT scanner at the resolution of 0.75 μm to extract the micro-scale properties (i.e., micro-network).
A stochastically equivalent network based on the extracted micro-network properties was generated with a larger field of view (FOV). Then, vugs were randomly added to the reconstructed micro-network based on the properties of the macro-scale CT images. The result was a dual-scale unstructured irregular PNM. The results show that the reconstructed dual-scale PNM has very close properties to the laboratory measurement data of the real rock sample.
Nader Faramarzi could defend his MSc thesis with a successful grade. Also, he could recently publish his findings in the “Journal of Natural gas Science & Engineering“. Congrats Nader for his achievements and wish him the best.
The response of gas condensate reservoirs is directly influenced by heterogeneity. In such reservoirs, condensate is created around wellbore areas, when the reservoir pressure falls below the dew point pressure. Consequently, the distribution of this condensate bank makes fluid flow in the reservoir even more complicated by changing rock-fluid properties (e.g., relative permeability). This alteration can be assumed as a new heterogeneity, called fluid heterogeneity.
The separation of fluid heterogeneity from rock heterogeneity is a challenging task. The main idea of this study was to investigate the transient pressure responses of a gas condensate reservoir to separate rock and fluid heterogeneities. Different homogeneous and heterogeneous reservoir models of a reservoir were constructed by the geostatistical approach. A commercial reservoir simulator was used to simulate the behavior of different drawdown and buildup scenarios. The fluid was a lean gas condensate selected from one of the Middle East formations. The wavelet transform (WT) approach was implemented to characterize the behavior of condensate banks for both homogeneous and heterogeneous models.
Analyzing the wavelet approximate and detail coefficients of the pressure-transient responses enabled us to distinguish the rock and fluid heterogeneities. The results showed that the wavelet detail coefficient could be a good indicator of reservoir heterogeneity. Moreover, the WT could be successfully used to distinguish different regions of a condensate bank inside the reservoir under study.
Alireza Teimory during his MSc. thesis could design and manufacture a transparent micro model to study reactive flow in porous media. Congrats Alireza for his success. The cell of this study has two characteristics. First, it enables us to work on a real rock sample to investigate geochemical reactions by incorporating actual rocks. Second, it provides a visual observation capability to monitor the behavior of fluid injection into rocks. The transparent cell consists of two transparent Plexiglass plates. A square pocket was precisely machined at the center of the bottom plate to provide a holder for a slabbed rock to be installed in the cell. Bolts and nuts were used to stitch both plates together. An opaque silicon rubber O-ring was used between the plates to prevent any fluid leakage during the experiments. The designed cell was hydraulically tested up to 120 psi before the main experiments.
In the first application, we implemented the manufactured setup to investigate weak acid injection on fracture opening in calcite and dolomite reservoirs. The results were published in the “Petroleum Research” Journal.
In the second study, we investigated acid pre-flushing and pH-sensitive microgel injection in fractured carbonate rocks for conformance control purposes. First, the dependency of fracture aperture changes to the acid pre-flush flow rate was examined. Then, we investigated the effect of pH-sensitive microgel concentration on its resistance to block fractures during post-water flooding by studying the gel failure mechanisms (e.g., adhesive separation, cohesive failure). Finally, the effect of an initial aperture of fracture was examined on microgel washout when water injection is resumed. The results showed that both decreasing the acid flow rate and lowering the initial aperture could increase the rate of aperture changes. Moreover, the microgel solution with a concentration of 1 wt.% showed the highest resistance (98.2 psi/ft) against post-water injection. Additionally, this microgel concentration had the highest permeability reduction factor. Meanwhile, the smaller initial aperture of fracture contributed to a higher microgel resistance. The results were published in “Oil & Gas Science and Technology – Rev. IFP Energies Nouvelles“.
Permlab wishes Alireza the best in the next phase of his life.
Hossein Younesian-Farid published his 2nd paper in the JPSE. In this study, the interaction of citric acid, as a weak acid, with a sandstone core containing ankerite cement was investigated during matrix acidizing. The model, developed in Python, implemented a global implicit numerical approach to consider acid-rock geochemical interactions. The effect of multi-step dissociation of citric acid on lowering rock pH was investigated. The sugar-lump approach was used to estimate the behavior of the ions concentration originated from the variation of the reactive surface area (RSA). Moreover, the model outputs were validated against matrix sandstone acidizing experiments from the literature.
Pouya Soltani has published his first paper at PermLab in the SPE Reservoir Evaluation & Engineering Journal. The main idea of this paper is to introduce a methodology of measuring the cleaning time that can be implemented as a routine screening tool in RCAL projects to nominate the proper solvent, which can reduce the Soxhlet cleaning time.
The process of running core analysis experiments (in both RCAL and SCAL) is very time-consuming. As all plug samples should be cleaned during the RCAL phase; therefore, finding of a solvent that can speed-up this process is necessary. The cleanliness of a core sample during Soxhlet extraction is usually determined by monitoring the color of solvents, qualitatively. The main contribution of this study was to propose a methodology during RCAL to nominate the best solvent during the Soxhlet cleaning experiments. By introducing a state-of-the-art quantitative method, the cleaning time of different solvents (i.e., tetrachloroethene, acetone, toluene, chloroform, xylene, and n-hexane) was investigated. This quantitative method is based on turbidity measurement of the solvent that siphons periodically from the Soxhlet extractor. Moreover, the wettability alteration of the implemented solvents was monitored by contact angle measurements.
Designed Soxhlet setup. a) Heater, b) Round-bottom flask, c) Two-neck extractor, d) Condenser, e) Sampling Syringe. The solvent samples are taken from part e by a needle syringe.
Recently, a new joint paper was accepted in theSPE Journal and we hope for more new outputs from this collaboration in the next future. This paper deals with reconstruction of vuggy carbonates by pore network modeling and image-based technique. The source code of this code can be downloaded from here.
Shahab Farhoodi, did great and published a very good paper (here) in Journal of Natural Gas Science & Engineering (JNGSE). We in this study payed attention to the analysis of the combined effect of geological heterogeneity and condensate drop out in condensate reservcoirs. A geostatistical approach was used to build reservoir models with different amount of heterogeneity. These models were simulated by a compositional reservoir simulator to generate pseudo-pressure data versus time of these heterogeneous models.
It was revealed that the intensity of the condensate formation around the wellbore is a strong function of the reservoir heterogeneity. The results showed that increasing of the model heterogeneity can entirely complicate the well-test responses when condensate drops near the wellbore region.
Congrates Zahra Azimi for her first publication in PermLab team. Zahra investigated cross-linked polymer gels as a temporary plugging agent to control the leakage of fluid during drilling, completion, and workover operations. In this study, various concentrations and size of silica nanoparticles are introduced into the sulfonated polyacrylamide (SPAM)/chromium (III) acetate system to produce a nanocomposite with enhanced mechanical properties. First, the rheological behavior of gelant and viscoelastic properties of synthesized nanocomposites are investigated. Then, the surface chemistry and morphology of the synthesized gels is evaluated by Fourier transform infrared (FTIR) spectroscopy and field emission scanning electron microscopy (FESEM), respectively. Finally, the maximum sealing differential pressure for gels for temporary plugging of a wellbore is measured by applying differential pressure across the nanocomposite gel in a designed set-up. The results showed that the precrosslinking reaction and the gelant viscosity are directly related to the size and concentration of the silica nanoparticles as well as the wellbore temperature. Moreover, it is demonstrated that nanocomposites containing 20-30 nm sized particles have a higher mechanical strength and plugging capability in comparison to composites containing silica particles with sizes of 7-10 nm and 60-70 nm.