Twenty-nine core plug samples of a wide range of Uniaxtial Compressive Strength (UCS) values were investigated using a suite of techniques including visual inspection at meso-scale on hand specimens and thin sections, microscopic examination, Scanning Electron Microscopic (SEM) analysis, laser particle analysis and X-ray Diffraction analysis to characterize their compositions, texture and sedimentary properties. An intimate intrinsic link is noticed between sedimentary features observed at meso-scale and that at the micro-scale, both of which can be directly correlated to rock strength. It has been demonstrated that one can empirically predict the rock strength (UCS range) of rocks from an inspection of core plug samples. A Rock Property Index parameter which combines a number of sedimentary parameters is found to be useful in qualifying or ranking the rock strength (UCS) of the samples investigated. A set of criteria of sedimentary characterization is proposed for empirically estimating the rock strength of core samples including the lithological compositions, heterogeneities, cementation, quartz and clay contents, grain contact nature, grain size distribution and visual porosity. This method may be applied to describe cutting samples at rig-site to provide timely information of the strength of the formation rocks while drilling.
Three coreflooding experiments were conducted using sandstone core samples from the Gippsland Basin with contrasting poroperm and heterogeneities. The core samples were initially saturated with formation water and then displaced using N2. Supercritical CO2 was subsequently injected to displace N2 and formation water. The coreflooding experiments were carried out at a temperature of 50 °C, a confining pressure of 30 MPa and an injection and production pressure of 21 MPa. Constant injection rate of 2 cc/min was used for both the N2 and scCO2 injection. The experiments were monitored with a fourth generation medical X-ray CT scanner. A number of phenomena were observed during the coreflooding experiments:
Both the N2 and scCO2 displacement processes under reservoir conditions were captured in all samples at sub-mm resolution.
At a 2 cc/min injection rate, gravity segregation effect for scCO2 displacing N2 was notably observed in the porous and permeable (16%, >250 mD) core, but not in the tight and low permeable (10%, <2 mD) core, nor in the porous but less permeable (18%, 60 mD) core.
The relative porous and permeable core show strong gravity segregation in the core plug during both N2 displacing formation water and scCO2 displacing N2.
For the less permeable core, the pore network appears to be “compartmentalised” as in the case of the strongly cross bedded sandstone. The heterogeneity effect becomes dominant over the gravity effect.
Wei, Xiaofang (State Key laboratory of EOR, Research Institute of Petroleum Exploration & Development, PetroChina) | Yang, Siyu (State Key laboratory of EOR, Research Institute of Petroleum Exploration & Development, PetroChina) | Wang, Bojun (State Key laboratory of EOR, Research Institute of Petroleum Exploration & Development, PetroChina) | Yang, Yongzhi (State Key laboratory of EOR, Research Institute of Petroleum Exploration & Development, PetroChina) | Song, Wenfeng (State Key laboratory of EOR, Research Institute of Petroleum Exploration & Development, PetroChina) | Xu, Ying (State Key laboratory of EOR, Research Institute of Petroleum Exploration & Development, PetroChina) | Zhou, Minghui (State Key laboratory of EOR, Research Institute of Petroleum Exploration & Development, PetroChina) | Liu, Keyu (State Key laboratory of EOR, Research Institute of Petroleum Exploration & Development, PetroChina)
Laboratory simulation experiments of air injection with low temperature (65°C, 17 MPa) for a low permeability (4.5 mD) reservoir was conducted by using crude oil from the Dagang Oilfield, Northern China. The initial oil density and viscosity are 12 API and 74.5 mPa.s, respectively. The physical properties of the crude oil such as viscosity, density in the oxidation zone before and after air injection were measured. Changes of both the saturated hydrocarbons and aromatic fractions were analyzed using GC X GC-FID. The changes of resin, asphaltene and oxygenated products were analyzed using a Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS).
The results indicate that the produced CO, CO2 and the gasified low molecular weight hydrocarbons drive the oil out from the tight reservoir core with an oil recovery of 45 %. The viscosity of the produced oil is reduced slightly by 2.6 %. The in situ viscosity, although not measured directly, should have been reduced significantly due to the thermal effect. The physical properties of the oil in the oxidation zone are deteriorated significantly, with the viscosity being increased by 30 % and the content of Oxygen by 7 %.The oxidization pathways from molecular alterations based the static oxidization of light oil at low temperature are also explored in accordance with the molecular heterogeneities.
Al Shahri, Hamid Ghafram (Petroleum Development Oman) | Liu, Keyu (CSIRO Earth Sciences & Resource Engineering) | Clennell, M.B. (CSIRO Earth Sciences & Resource Engineering) | Liu, Jishan (University of Western Australia) | McKinley, Allan (The University of Western Australia)
Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract This paper describes experimental work to study the impact of longitudinal heterogeneity of porous medium (in terms of permeability) on the efficiency of ASP flooding that has been practiced in Enhance Oil Recovery (EOR). EOR becomes increasingly important as the globally proved crude oil reserves are being depleted. Chemical flooding is one of the tools to increase recovery; however, is still an active area for integrated research as it involves geochemistry, pore structure, microemulsion, fluid flow and chemical transport in porous media. Oil recovery measurements were made based on mass measurements. The results indicate that longitudinal heterogeneities can impact EOR and the flooding of ASP slug from lower-to-higher permeability transition can mitigate the heterogeneity influence on EOR. In this experimental investigation, an enhancement of 5% (Original Oil in Place) was found when the ASP flood goes from lower-to-higher permeability transition as compared to that from higher-to-lower permeability transition. This finding can be of great importance to operators interested in implementing ASP floods. Introduction ASP flooding is one of the applied chemical EOR methods (Sheng, 2010) that has been proven to be more cost effective and simpler compared to the binary injection of chemicals (e.g. The impact of the lateral (transverse with respect to the direction of fluid flow) heterogeneity on the ASP process was studied systematically in only one published paper by Shen et al. (2009), and there is no report in the literature regarding the effect of longitudinal heterogeneity on ASP EOR. The term'longitudinal heterogeneity' used in this paper refers to the variations of permeability in a direction parallel to the direction of the fluid flow in the porous medium.
Fan, Junjia (Research Institute of Petroleum Exploration and Development and Peking University) | Zhou, Haimin (Peking University) | Liu, Shobo (Peking University) | Liu, Keyu (CSIRO Earth Science and Resource Engineering)
Tight sandstone gas as one kind of unconventional resources has taken up a significant part in natural gas resource growth in recent years. Tight sandstone gas originated from the definition of U.S. Gas Policy Act of 1978, that regulated in-situ gas permeability to be equal to or less than 0.1 md for the reservoir to qualify as a tight gas formation Gas flow in tight sandstone behaves as non-Darcy flow has been reached a consensus by scholars; however gas-water flow characterization and the main factors for gas-water flow in tight sandstone remain complicated. Scholars proposed that there is a "Permeability Jail?? for water-gas flowing in tight sandstone reservoirs which means both water and gas cannot flow in "Permeability Jail?? range. This may explain why neither gas nor water produced in tight sandstone reservoir in wells of some tight gas field.
In order to get a better understanding on water-gas flow characteristics and to figure out the major affecting factors for gas-water migration in tight sandstone, we analyses pore structure, bulk and clay mineral constitutes and gas-water two phases flow characteristics of five tight sandstone samples with low permeability (<0.1md) and low porosity from the tight gas fields in Kuqa Depression, Tarim Basin by using of micro CT scanning, XRD analysis and physical simulation experiments.
Experimental results indicate that 1) "Permeability Jail?? does not existed in five tight sandstone samples, but flow ranges for gas-water of five samples are different; 2) pore structures and fractures play significant roles for the gas-water flowing, and fractures can improve the gas-water permeability significantly; 3) for permeability, the pore connectivity is more important than total porosity of rocks; 4) content of clay minerals in tight sandstones affected the gas-water migration, the higher the clay minerals contents are, the lower the permeability of rocks is.
Liu, Keyu (CSIRO Earth Science and Resource Engineering) | Clennell, Michael Benedict (CSIRO Earth Science and Resource Engineering) | Honari, Abdolvahab (University of Western Australia) | Sayem, Taschfeen (University of Western Australia) | Rashid, Abdul (CSIRO Earth Science and Resource Engineering) | Wei, Xiaofang (Research Institute of Petroleum Exploration and Development, PetroChina) | Saeedi, Ali (Curtin University)
A series of laboratory investigation on factors affecting Enhanced Oil and Gas Recovery and CO2 geo-sequestration were conducted. The coreflooding experiments were done using a relatively heavy crude oil (18° API), a number of brines of 0.18%-2.5% NaCl and varieties of cores with a range porosity and permeability from 15% and 17 mD to 19% and 330 mD under some typical reservoir pressure-temperature condition of 1164-3300 psi and 50-83 °C. Factors affecting CO2 enhanced oil and gas recovery including the effects of the petrophysical properties of the reservoir rocks, formation water salinity, reservoir pressure, the Minimum Miscibility Pressure (MMP), total volume (PV) injected and injection rate and gravity segregation.
Excellent recovery factors in the range of 27%-34% Original Oil In Place (OOIP) and almost 100% gas recovery were achieved through immiscible and miscible CO2 flooding. Some of the coreflooding experiments were monitored with a medical CT in real time. The coreflooding experiments have shown that (1) reservoir petrophysical properties with permeability difference of up to an order of magnitude do not affect the CO2 EOR factor; (2) variable EOR can be achieved both at reservoir pressures below or above the CO2-oil MMP; (3) Incremental oil recovery is proportional to the pore volume (PV) of CO2 injected up to 3PV; (4) No significant additional recovery was observed beyond the MMP; (5) CO2-Water alternating gas (WAG) flooding can be quite effective in EOR in terms of the less amount of CO2 injected as compared to that for the single CO2-water flooding to achieve the same EOR; (6) there is no benefit to use low-salinity CO2 WAG flooding; (7) the optimum injection rate in the laboratory is around 1 cc/minute. These finding may provide some useful insight and guide for the field application of CO2 enhanced oil and gas recovery; (8) During enhanced gas recovery using supercritical CO2, gravity segregation may occur in some porous-permeable reservoir with denser supercritical CO2 preferentially enter through the bottom of the reservoir.
The mechanisms of Microbial Enhanced Oil Recovery (MEOR) are generally thought to be through oil biodegradation, production of biosurfactants, biogases, low molecular acids and biopolymers by microbes. The first four processes contribute to Interfacial Tension (IFT) reduction while the final one to plugging high permeability zones. Microbes can produce diverse metabolites thereby modifying the oil-water IFT in an oil reservoir. This study attempts to investigate the effect of microbial metabolites on the oil viscosity and IFT under reservoir P/T conditions.
A reservoir fluid with 20% crude oil and 80% formation water was treated with indigenous microbes for 21 days under anaerobic condition using molasses (5%) as nutrients. The microbially treated and the un-treated oils were analysed geochemically by using Gas Chromatography-Mass Spectrometer (GC-MS). The oil density, viscosity and the oil-water IFT of both the un-treated and bio-treated oils were measured under reservoir P/T conditions.
The analytical results indicated that there were no significant difference in chemical compositions and densities among different oil samples, suggesting little or none microbial biodegradation present. The effect of biogases and low molecular acids was excluded because of the measurement methodology used.
In contrast to the un-treated oil, the IFT of the bio-treated crude oil was found to be reduced from the un-treated 7.2 to 3.7×10-3 mN/m, a 48% reduction. The oil viscosity of the bio-treated crude oil was decreased by 50%. The viscosity and IFT reduction might be primarily due to the microbial metabolites (biosurfactants) produced, which may play a key role in altering the oil-water interface. Macro-micro emulsification was also observed at the oil-water interface. It is concluded that microbial metabolites could potentially reduce the oil viscosity (via emulsification) and improve the crude oil-water IFT under reservoir P/T conditions.
Gui, Lily (Research Inst. of Petroleum Exploration and Development, PetroChina) | Liu, Shaobo (PetroChina Co. Ltd.) | Liu, Keyu (CSIRO Petroleum) | Yi, Zhao (Jijiajing Coal Mining Co., Guodian Younglight Energy Chemical Group Co. Ltd.) | Meng, Qingyang (Research Inst. of Petroleum Exploration and Development, PetroChina) | Hao, Jiaqing (Research Inst. of Petroleum Exploration and Development, PetroChina)
In a series of paper, the characteristics of petroleum inclusions described by ?max from the UV and CH2/CH3 ratio from the FT-IR spectra. On the basis of optical microscopic, microthermometric, fluorescence spectroscopic and FT-IR spectroscopic analyses three types of hydrocarbon inclusions are identified in the study area: namely (1) yellow fluorescencing oil inclusions, (2) blue fluorescencing oil inclusions and (3) gas inclusions, representing two episodes of oil charges and one gas charge possibly related to readjustment of the associated gases down dip. The first episode of oil charge is represented by the predominantly yellow fluorescencing oil inclusions trapped prior to the quartz overgrowth, whereas the second episode is marked by the blue fluorescencing fluid inclusions occurred after the precipitation of dolomite. Both the UV fluorescence and the FT-IR spectra show two distinct oil inclusion groups (yellow and blue) with ?max at 540 nm and 475 nm, respectively and corresponding CH2/CH3 ratios of 1.2 and 2.3, respectively. Microthermometric data indicate that the two groups of oil inclusions have different homogenisation temperatures (Th), corresponding to oil charge around 25 Ma and 10 Ma, respectively for the Gasi and Hongliuquan oilfields, 10 Ma and 5 Ma, respectively for the Yingdong Oilfield, SW Qaidam Basin. The yellow fluorescencing oil inclusions have relatively low maturity and API gravity compared with the blue fluorescencing ones. The current accumulations in the oilfields have maturity and API gravity similar to that of the yellow fluorescencing inclusions. It is concluded that the earlier hydrocarbon charge is thus the predominant contribution to the current accumulations.
Hydrocarbon inclusions are minute petroleum fluids trapped during reservoir diagenesis [1-6]. They provide pristine compositional information of the hydrocarbons present at the time of charge that may offer important clues for understanding hydrocarbon charge history and reservoir fluid evolution. Hydrocarbon inclusions are currently being extensively used to investigate hydrocarbon charge timing and bulk physio-chemical compositions. Due to the minute amount of the fluids within individual inclusions and the complicated extraction procedure, despite of a number of attempts by various authors, so far there is no reported successful case on differentiating the physio-chemical compositions among individual inclusions that may represent different charges using GCMS.
In this paper we report detailed characterisation of individual petroleum inclusions using micro-spectroscopy that recently pioneered by Pradier et al. In a series of paper, the micro-spectroscopic analytical methods include both the UV fluorescence spectroscopy and FT-IR spectroscopy. Parameters derived from the micro-spectroscopy such as ?max from the UV fluorescence spectra and CH2/CH3 ratio from the FT-IR spectra can be used to determine the characteristics of the physio-chemical compositions of individual petroleum inclusions including aromatic content, thermal maturity and API gravities with proper calibrations.The TSF parameter is uesd to describe the feature of oil and hydrocarbon inclusion, the R1 parameter is a ratio between TSF emission intensity at 360nm and 320nm at a Excitation wavelength of 270nm,R has closely related to the API and maturity .
In order to screen various chemical and microbial EOR methods for core-flooding experiments and potential field trials, a laboratory investigation of evaluating the effect of micro-emulsion on the reduction of interfacial tension (IFT) was recently carried out at CSIRO by using commercially available chemical and bio-surfactants. Environment friendly non-ionic, anionic surfactants and a biosurfactant (Bacillus subtilis) were used to create micro-emulsion in an oil-brine system. Stable micro-emulsion (ME) was achieved by proportionally mixing various alcohols with surfactants.
Twenty-four micro-emulsion samples with five different chemical combinations were prepared for screening. All samples were stirred to create a stable ME phase. The volume changes of the ME phase were monitored over two weeks and their density, viscosity, and IFT were measured. The size distribution of ME phases was also characterised using optical microscopy equipped with an UV light source.
The micro-emulsion created by co-surfactants were found to be quite effective in reducing the oil-brine IFT and oil viscosity, and achieved ultra low IFT under reservoir pressure and temperature. There appears to be a linear relationship between the size of micro-emulsion and IFT reduction. ME with small sizes results in more IFT reduction and achieve stable ME at high temperature and pressure. Compared with the IFT reduction from the surfactant or microbial metabolism, the reduction of IFT through stable ME can be several orders of magnitude larger and may thus achieve better enhanced oil recovery in suitable reservoir systems.
This work is a part of a fundamental study investigating the efficiency of the alkaline- surfactant-polymer (ASP) flooding process. While heterogeneity in pore structure is a key concern of our research, it is necessary first to have a clear understanding of the baseline behavior when porosity, permeability and throat size are tightly controlled. This control was achieved by manufacturing a homogenous carbonate-cemented sandstone using the calcite in-situ precipitation system (CIPS). We present the multiphase flow properties of the artificial CIPS rocks, including previously unpublished results on oil/water capillary behavior and relative permeability.
In the core flooding experiments described here we used zero clay content and kept the same throat size and pore size distribution and kept the same chemical composition of the ASP slug. The polymer that was used in the flooding was polyacrylamide (1560 ppm) and the surfactant was alpha olefin sulfonate (1% w/w) and the alkaline was NaOH (0.5% w/w). Along with ASP floods, two surfactant floods were run with concentrations of 1% and 0.1% (w/w). Two identical specially fabricated CIPS carbonate cemented cores were used. The silica grains of both cores are primarily silica cemented by calcite. Both cores have a permeability of 1.8 Darcy and porosity of 19.4%. The only experimental variable was then the oils type and we choose oils such that their viscosities have close values. Australian heavy crude oil (18 API) and highly refined paraffinic oil (Ondina 68) were used in the core flooding study.
Two ASP floods were run, and although all the physical parameters were kept same except oil type, the outcome was significantly different. While recovery of both the refined oil and the crude oil was the same after initial waterflood, the crude oil was mobilized more by the ASP process, through both microemulsion and banking processes. The experiment with the refined paraffinic oil produced less ultimate recovery, and only the microemulsion process was significant.