Molecular differences in sequential extracts obtained by core flooding of the early mature ultra-tight Posidonia Shale

The objective of this paper is to determine the optimum anaerobic-thermophilic bacterium injection (Microbial Enhanced Oil Recovery) parameters using commercial simulator from core flooding experiments. From the previous experiment in the laboratory, Petrotoga sp AR80 microbe and yeast extract has been injected into core sample. The result show that the experiment with the treated microbe flooding has produced more oil than the experiment that treated by brine flooding. Moreover, this microbe classified into anaerobic thermophilic bacterium due to its ability to live in 80 degC and without oxygen. So, to find the optimum parameter that affect this microbe, the simulation experiment has been conducted. The simulator that is used is CMG – STAR 2015.10. There are five scenarios that have been made to forecast the performance of microbial flooding. Each of this scenario focus on the injection rate and shut in periods. In terms of the result, the best scenario on this research can yield an oil recovery up to 55.7%.

Download Full-text

Investigation on degradation mechanism of polymer blockages in unconsolidated sandstone reservoirs

e-Polymers ◽

10.1515/epoly-2020-0006 ◽

2020 ◽

Vol 20 (1) ◽

pp. 55-60

Author(s):

Wenting Dong ◽

Dong Zhang ◽

Keliang Wang ◽

Yue Qiu

Keyword(s):

Oil Recovery ◽

Degradation Mechanism ◽

Injection Pressure ◽

Polymer Flooding ◽

Core Flooding ◽

Reservoir Properties ◽

Thermal Analyzer ◽

Sandstone Reservoirs ◽

Suction Index ◽

Weighing Method

AbstractPolymer flooding technology has shown satisfactorily acceptable performance in improving oil recovery from unconsolidated sandstone reservoirs. The adsorption of the polymer in the pore leads to the increase of injection pressure and the decrease of suction index, which affects the effect of polymer flooding. In this article, the water and oil content of polymer blockages, which are taken from Bohai Oilfield, are measured by weighing method. In addition, the synchronous thermal analyzer and Fourier transform infrared spectroscopy (FTIR) are used to evaluate the composition and functional groups of the blockage, respectively. Then the core flooding experiments are also utilized to assess the effect of polymer plugs on reservoir properties and optimize the best degradant formulation. The results of this investigation show that the polymer adsorption in core after polymer flooding is 0.0068 g, which results in a permeability damage rate of 74.8%. The degradation ability of the agent consisting of 1% oxidizer SA-HB and 10% HCl is the best, the viscosity of the system decreases from 501.7 to 468.5 mPa‧s.

Download Full-text

Photon-magnon response to fluid variability and saturation levels in sandstone reservoirs

Journal of Geophysics and Engineering ◽

10.1093/jge/gxaa064 ◽

2020 ◽

Vol 17 (6) ◽

pp. 1065-1074

Author(s):

Abdullah Musa Ali ◽

Amir Rostami ◽

Noorhana Yahya

Keyword(s):

Oil Recovery ◽

Relative Permittivity ◽

Wave Interaction ◽

Heterogeneous Porous Media ◽

Injection System ◽

Bragg Grating ◽

Fibre Bragg Grating ◽

Core Flooding ◽

Oil Saturation ◽

Fluid Saturation

Abstract The need to recover high viscosity heavy oil from the residual phase of reservoirs has raised interest in the use of electromagnetics (EM) for enhanced oil recovery. However, the transformation of EM wave properties must be taken into consideration with respect to the dynamic interaction between fluid and solid phases. Consequently, this study discretises EM wave interaction with heterogeneous porous media (sandstones) under different fluid saturations (oil and water) to aid the monitoring of fluid mobility and activation of magnetic nanofluid in the reservoir. To achieve this aim, this study defined the various EM responses and signatures for brine and oil saturation and fluid saturation levels. A Nanofluid Electromagnetic Injection System (NES) was deployed for a fluid injection/core-flooding experiment. Inductance, resistance and capacitance (LRC) were recorded as the different fluids were injected into a 1.0-m long Berea core, starting from brine imbibition to oil saturation, brine flooding and eventually magnetite nanofluid flooding. The fluid mobility was monitored using a fibre Bragg grating sensor. The experimental measurements of the relative permittivity of the Berea sandstone core (with embedded detectors) saturated with brine, oil and magnetite nanofluid were given in the frequency band of 200 kHz. The behaviour of relative permittivity and attenuation of the EM wave was observed to be convolutedly dependent on the sandstone saturation history. The fibre Bragg Grating (FBG) sensor was able to detect the interaction of the Fe3O4 nanofluid with the magnetic field, which underpins the fluid mobility fundamentals that resulted in an anomalous response.

Download Full-text

Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Energies ◽

10.3390/en14030626 ◽

2021 ◽

Vol 14 (3) ◽

pp. 626

Author(s):

Jiyuan Zhang ◽

Bin Zhang ◽

Shiqian Xu ◽

Qihong Feng ◽

Xianmin Zhang ◽

...

Keyword(s):

Relative Permeability ◽

Coalbed Methane ◽

History Matching ◽

Water Saturation ◽

Unsteady State ◽

Core Flooding ◽

Rock Interaction ◽

Interaction Mechanisms ◽

True Value ◽

Assisted History Matching

The relative permeability of coal to gas and water exerts a profound influence on fluid transport in coal seams in both primary and enhanced coalbed methane (ECBM) recovery processes where multiphase flow occurs. Unsteady-state core-flooding tests interpreted by the Johnson–Bossler–Naumann (JBN) method are commonly used to obtain the relative permeability of coal. However, the JBN method fails to capture multiple gas–water–coal interaction mechanisms, which inevitably results in inaccurate estimations of relative permeability. This paper proposes an improved assisted history matching framework using the Bayesian adaptive direct search (BADS) algorithm to interpret the relative permeability of coal from unsteady-state flooding test data. The validation results show that the BADS algorithm is significantly faster than previous algorithms in terms of convergence speed. The proposed method can accurately reproduce the true relative permeability curves without a presumption of the endpoint saturations given a small end-effect number of <0.56. As a comparison, the routine JBN method produces abnormal interpretation results (with the estimated connate water saturation ≈33% higher than and the endpoint water/gas relative permeability only ≈0.02 of the true value) under comparable conditions. The proposed framework is a promising computationally effective alternative to the JBN method to accurately derive relative permeability relations for gas–water–coal systems with multiple fluid–rock interaction mechanisms.

Download Full-text

Saturated carbon dioxide nanofluids enhanced oil recovery in carbonate reservoir cores using nuclear magnetic resonance

10.5194/egusphere-egu21-6762 ◽

2021 ◽

Author(s):

Yongsheng Tan ◽

Qi Li ◽

Liang Xu ◽

Xiaoyan Zhang ◽

Tao Yu

Keyword(s):

Carbon Dioxide ◽

Nuclear Magnetic Resonance ◽

Magnetic Resonance ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Carbonate Reservoir ◽

Carbonate Reservoirs ◽

Residual Oil ◽

Core Flooding ◽

Nuclear Magnetic

The wettability, fingering effect and strong heterogeneity of carbonate reservoirs lead to low oil recovery. However, carbon dioxide (CO2) displacement is an effective method to improve oil recovery for carbonate reservoirs. Saturated CO2 nanofluids combines the advantages of CO2 and nanofluids, which can change the reservoir wettability and improve the sweep area to achieve the purpose of enhanced oil recovery (EOR), so it is a promising technique in petroleum industry. In this study, comparative experiments of CO2 flooding and saturated CO2 nanofluids flooding were carried out in carbonate reservoir cores. The nuclear magnetic resonance (NMR) instrument was used to clarify oil distribution during core flooding processes. For the CO2 displacement experiment, the results show that viscous fingering and channeling are obvious during CO2 flooding, the oil is mainly produced from the big pores, and the residual oil is trapped in the small pores. For the saturated CO2 nanofluids displacement experiment, the results show that saturated CO2 nanofluids inhibit CO2 channeling and fingering, the oil is produced from the big pores and small pores, the residual oil is still trapped in the small pores, but the NMR signal intensity of the residual oil is significantly reduced. The final oil recovery of saturated CO2 nanofluids displacement is higher than that of CO2 displacement. This study provides a significant reference for EOR in carbonate reservoirs. Meanwhile, it promotes the application of nanofluids in energy exploitation and CO2 utilization.

Download Full-text

Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

10.2118/207150-ms ◽

2021 ◽

Author(s):

Tinuola Udoh

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Niger Delta ◽

Oil Production ◽

Reservoir Rock ◽

Core Flooding ◽

Core Samples ◽

Recovery Potential ◽

Secondary Formation ◽

Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

Download Full-text

Understanding the interplay of capillary and viscous forces in CO2 core flooding experiments

Journal of Hydrology ◽

10.1016/j.jhydrol.2021.127411 ◽

2021 ◽

pp. 127411

Author(s):

Xiaoqiang Jin ◽

Cong Chao ◽

Katriona Edlmann ◽

Xianfeng Fan

Keyword(s):

Core Flooding ◽

Viscous Forces

Download Full-text

Miscible Flooding for Bitumen Recovery with a Novel Solvent

10.2118/206325-ms ◽

2021 ◽

Author(s):

Tanya Ann Mathews ◽

Alex J.Cortes ◽

Richard Bryant ◽

Berna Hascakir

Keyword(s):

Oil Recovery ◽

Cold Water ◽

Pore Space ◽

Oil Quality ◽

Environmental Concerns ◽

Solvent Recovery ◽

Core Flooding ◽

Recovery Method ◽

Steam Flooding ◽

Oil Emulsions

Abstract Steam injection is an effective heavy oil recovery method, however, poses several environmental concerns. Solvent injection methods are introduced in an attempt to combat these environmental concerns. This paper evaluates the effectiveness of a new solvent (VisRed) in the recovery of a Canadian bitumen and compares its results with toluene. While VisRed is selected due to its high effectiveness as a viscosity reducer even at very low concentrations, toluene is selected due to its high solvent power. Five core flooding experiments were conducted; E1 (Steam flooding), E2 (VisRed flooding), E3 (Toluene flooding), E4 (Steam + Toluene flooding), and E5 (Steam + VisRed flooding). Core samples were prepared by saturating 60% of the pore space with oil samples and 40% with deionized water. The solvents were injected at a 2 ml/min rate, while steam was injected at a 18 ml/min cold water equivalent rate. Produced oil and water samples were collected every 20 min during every experiment. The oil recovery efficiencies of the core flood experiments were analyzed by the emulsion characterization in the produced fluids and the residual oil analysis on the spent rock samples. The best oil recovery of ~30 vol % was obtained for E2 (VisRed) in which VisRed was injected alone. Although similar cumulative recoveries were obtained both for E2 (VisRed) and E3 (Toluene), the amount of VisRed injected [~1 pore volumes (PV)] was half the volume required by toluene (~2 PV). The produced oil quality variations are mainly due to the formation of the water-in-oil emulsions during mainly steam processes (E1, E4, and E5). The increased amount of the polar fractions in the produced oil enhances the formation of the emulsions. These polar fractions are namely asphaltenes and resins. As the amount of the polar fractions in the produce oil increases, more water-in-oil emulsion formation is observed due to the polar-polar interaction between crude oil fractions and water. Consequently, E1 and E5 resulted in more water in oil emulsions. The cost analysis also shows the effectiveness of solvent recovery over steam-solvent recovery processes.

Download Full-text

The Combined Flooding of Dispersed Particle Gel and Surfactant for Conformance Control and EOR: From Experiment to Pilot Test

10.2118/204324-ms ◽

2021 ◽

Author(s):

Xia Yin ◽

Tianyi Zhao ◽

Jie Yi

Keyword(s):

Oil Recovery ◽

Formation Energy ◽

High Salinity ◽

Surfactant Solution ◽

Pilot Test ◽

Control Performance ◽

Core Flooding ◽

Displacement Efficiency ◽

Conformance Control ◽

And Performance

Abstract The water channeling and excess water production led to the decreasing formation energy in the oilfield. Therefore, the combined flooding with dispersed particle gel (DPG) and surfactant was conducted for conformance control and enhanced oil recovery in a high temperature (100-110°C) high salinity (>2.1×105mg/L) channel reservoir of block X in Tahe oilfield. This paper reports the experimental results and pilot test for the combined flooding in a well group of Block X. In the experiment part, the interfacial tension, emulsifying capacity of the surfactant and the particle size during aging of DPG were measured, then, the conformance control and enhanced oil recovery performance of the combined flooding was evaluated by core flooding experiment. In the pilot test, the geological backgrounds and developing history of the block was introduced. Then, an integrated study of EOR and conformance control performance in the block X are analyzed by real-time monitoring and performance after treatment. In addition, the well selection criteria and flooding optimization were clarified. In this combined flooding, DPG is applied as in-depth conformance control agent to increase the sweep efficiency, and surfactant solution slug following is used for improve the displacement efficiency. The long term stability of DPG for 15 days ensures the efficiency of in-depth conformance control and its size can increase from its original 0.543μm to 35.5μm after aging for 7 days in the 2.17×105mg/L reservoir water and at 110°C. In the optimization, it is found that 0.35% NAC-1+ 0.25% NAC-2 surfactant solution with interfacial tension 3.2×10-2mN/m can form a relatively stable emulsion easily with the dehydrated crude oil. In the double core flooding, the conformance control performance is confirmed by the diversion of fluid after combined flooding and EOR increases by 21.3%. After exploitation of Block X for 14 years, the fast decreasing formation energy due to lack of large bottom water and water fingering resulted in a decreasing production rate and increasing watercut. After combined flooding in Y well group with 1 injector and 3 producers, the average dynamic liquid level, daily production, and tracing agent breakthrough time increased, while the watercut and infectivity index decreased. The distribution rate of injected fluid and real-time monitoring also assured the conformance control performance. The oil production of this well group was increased by over 3000 tons. Upon this throughout study of combined flooding from experiment to case study, adjusting the heterogeneity by DPG combined with increasing displacement efficiency of surfactant enhanced the oil recovery synergistically in this high salinity high temperature reservoir. The criteria for the selection and performance of combined flooding also provides practical experiences and principles for combined flooding.

Download Full-text

CO2-brine injectivity tests in high co2 content carbonate field, sarawak basin, offshore east Malaysia

E3S Web of Conferences ◽

10.1051/e3sconf/20198904005 ◽

2019 ◽

Vol 89 ◽

pp. 04005 ◽

Cited By ~ 2

Author(s):

A Giwelli ◽

MZ Kashim ◽

MB Clennell ◽

L Esteban ◽

R Noble ◽

...

Keyword(s):

Packed Column ◽

Core Sample ◽

Chemical Analyses ◽

Core Flooding ◽

Flow Rates ◽

X Ray ◽

The Core ◽

Reservoir Conditions ◽

Post Test ◽

Porosity And Permeability

We conducted relatively long duration core-flooding tests on three representative core samples under reservoir conditions to quantify the potential impact of flow rates on fines production/permeability change. Supercritical CO2 was injected cyclically with incremental increases in flow rate (2─14 ml/min) with live brine until a total of 7 cycles were completed. To avoid unwanted fluid-rock reaction when live brine was injected into the sample, and to mimic the in-situ geochemical conditions of the reservoir, a packed column was installed on the inflow accumulator line to pre-equilibrate the fluid before entering the core sample. The change in the gas porosity and permeability of the tested plug samples due to different mechanisms (dissolution and/or precipitation) that may occur during scCO2/live brine injection was investigated. Nuclear magnetic resonance (NMR) T2 determination, X-ray CT scans and chemical analyses of the produced brine were also conducted. Results of pre- and post-test analyses (poroperm, NMR, X-ray CT) showed no clear evidence of formation damage even after long testing cycles and only minor or no dissolution (after large injected pore volumes (PVs) ~ 200). The critical flow rates (if there is one) were higher than the maximum rates applied. Chemical analyses of the core effluent showed that the rock samples for which a pre-column was installed do not experience carbonate dissolution.

Download Full-text