Reservoir heterogeneity plays a critical role in determining the success of enhanced-oil-recovery (EOR) processes, but its effect rarely has been comprehensively quantified in the laboratory. This work presents the results of an experimental study on the effects of various carbon dioxide (CO2) injection modes on immiscible-flooding performance in heterogeneous-sandstone porous media. Thus, the results of this study can be insightful in overcoming the current challenges in capturing the importance of geological uncertainties in current and future EOR projects.
Coreflooding experiments were conducted for n-decane/synthetic-brine/CO2 systems at a 9.6-MPa backpressure and at 343 K to attain immiscible-flooding conditions [minimum-miscibility pressure (MMP) of CO2 in n-decane is 12.4 MPa]. For this purpose, two sets of heterogeneous-sandstone core samples were assembled with heterogeneity either parallel to (layered samples) or perpendicular to (composite samples) the flow. The results obtained for both composite and layered core samples indicated that heterogeneity tremendously influences the outcome of the CO2 EOR. Oil recovery decreases dramatically with an increase in the heterogeneity level or permeability ratio (PR). In addition, the crossflow in the layered core sample is found to have a noticeable effect on the ultimate oil recovery (increasing oil recovery up to 5%). Also, it is worth noting that for the composite samples, when we arranged the plugs by putting the low-permeability segments closer to the sample outlets, the recovery factor increased. However, regardless of the segment arrangements, the recoveries in composite cores are lower than those obtained from the homogeneous core sample.
This paper presents the results of an experimental study on the effects of various CO2-injection modes on immiscible flooding performance in heterogeneous sandstone porous media.
Core flooding experiments were conducted for
Reservoir heterogeneity plays a critical role in determining the successes of the EOR processes, but its effect has rarely been comprehensively quantified in the laboratory. The limited experimental studies conducted to date seem to suffer from a number of deficiency mainly associated with sample preparation and experimental setup. In the present work, in addition to investigating a number of factors rarely studied experimentally before (e.g. effect of crossflow), attempts have been made to overcome the deficiencies of previous studies. Thus the results of this study can be insightful in overcoming the current challenges in capturing the importance of geological uncertainties in the current and future EOR projects.
The tight gas is one of the main types of the unconventional gas. Typically the tight gas reservoirs consist of highly heterogeneous low permeability reservoir. The economic evaluation for the production from tight gas production is very challenging task because of prevailing uncertainties associated with key reservoir properties, such as porosity, permeability as well as drainage boundary. However one of the important parameters requiring in this economic evaluation is the equivalent drainage area of the well, which relates the actual volume of fluids (e.g gas) produced or withdrawn from the reservoir at a certain moment that changes with time. It is difficult to predict this equivalent drainage area of well in tight gas reservoir as it takes utterly long time for reservoir pressure to reach to the impermeable physical boundary of the reservoir. The effective drainage area, which grows with time during the transient period; and consequently it is much smaller than the physical drainage arear over the transient flow period in case of tight gas reservoir because of the low permeability. Consequently the production forecasting using physical drainage area (as generally considered for conventional reservoir) can results not only significant error in estimation but also mislead the decision making process.
In this paper however, a practical method for predicting the equivalent drainage area of a fractured well in tight gas reservoir is proposed. This method is based upon combined gas material balance equation and decline curve analysis. The developed method is validated against reservoir simulation results, which demonstrates that the proposed method is accurate enough to predict the equivalent drainage area, and may be considered as a practical tool for production forecasting for tight gas reservoir. Sensitivity analyses are carried out to investigate various factors, such as porosity, permeability, facture length on equivalent drainage area for fractured vertical well in tight gas reservoir. Based on the sensitivity study it is observed that the fracture half-length and the porosity have strong impact on the equivalent drainage area, and propagation of equivalent drainage area with time.
Geological sequestration of CO2 is one of the most promising technologies to mitigate the greenhouse effect by decreasing the anthropogenic CO2 emissions into the atmosphere. Deep saline reservoirs are a suitable target for CO2 storage because very often they can be found relatively close to today's large CO2 releasing sources. To investigate the chemical and physical impacts of a CO2-rich brine solution injection to a quartz rich sandstone, we flooded a Berea Sandstone core sample with CO2-saturated synthetic brine at the elevated temperature (60°C) and pressure (20MPa). After flooding, the porosity and permeability of the core were measured and compared to the pre-flooding values. We found that the porosity had increased by 1.8% while the permeability decreased by 5.1%. The decrease in permeability may be attributed to the movement of particles in the pore space of the sample (fines migration) and/or sample's physical compaction under net effective stress. Effluent brine samples were also collected during the core-flood experiment to be analysed for their chemical composition. We found that, on average, the concentration of Ca2+, Mg2+ and Fe2+ in the effluent samples to increase by approximately 100mg/l, 80mg/l and 95mg/l, respectively, with traces of other metals. It is believed that the Ca2+, Mg2+ and Fe2+ were liberated from the dissolution of the carbonate cement in the sample. As revealed by the differential pressure evolution of the experiment, for the quartz-rich sandstone reservoirs, where fines migration is not significant and reactive minerals are scarce, the injectivity may not be affected during the fluid injection process.
The gas material balance equation (MBE) has been widely used as a practical as well as a simple tool to estimate gas initially in place (GIIP), and the ultimate recovery (UR) factor of a gas reservoir. The classical form of the gas material balance equation is developed by considering the reservoir as a simple tank model, in which the relationship between the pressure/gas compressibility factor (
Liu, Yongbing (Southwest Petroleum University) | Jiang, Tongwen (PetroChina Tarim Oilfield Company) | Zhou, Daiyu (PetroChina Tarim Oilfield Company) | Zhao, Ji (PetroChina Tarim Oilfield Company) | Xie, Quan (Ehsan Pooryousefy) | Saeedi, Ali (Curtin University)
This paper presents a systematic assessment of the potential of low salinity water flooding for the Dong-He-Tang reservoir in the Tarim Oilfield, China. This reservoir has a high reservoir temperature of 140 °C, high formation water salinity of 142,431 ppm total dissolved solids and an in-situ oil viscosity of 2.2 cp.
Our laboratory evaluation included contact angle tests, and spontaneous imbibition and core-flooding experiments using representative core samples from the reservoir. Contact angle tests were conducted at various temperatures (60, 100 and 140 °C) and pressures (20, 30, 40 and 50 MPa). Core-flooding experiments were conducted under the reservoir temperature of 140 °C. Formation brine and low salinity water (100 times diluted formation brine) were used in the experiments.
Contact angle and spontaneous imbibition experiments showed that low salinity water shifted the reservoir wettability towards more water-wet. In addition, spontaneous imbibition experiments showed that low salinity water recovered significantly more oil than high salinity water.
Furthermore, corefloods were conducted using low salinity water under tertiary and secondary modes. Experimental results were history matched to derive relative permeability curves and capillary pressure curves while considering the non-uniqueness of such history-matching. Results showed that compared to high salinity water flooding, low salinity water shifted relative permeability curves towards lower residual oil saturation, showing a higher oil relative permeability and lower water relative permeability at the same water saturation.
The parameters derived from laboratory experiments were used as input for reservoir simulation models to investigate the potential of low salinity water flooding in the reservoir using two layered box models. Findings showed that low salinity water accelerated oil production by increasing the oil relative permeability, thus resulting in a higher recovery factor with only a fraction of pore volume of low salinity water injection. Implications of these findings, such as slug size, salinity of injected brine, non-uniqueness of derived relative permeability curves on incremental oil recovery were assessed.
This paper is novel in the following aspects. First, the potential of low salinity water at a high reservoir temperature of 140 °C was systematically investigated. Second, laboratory experiments showed that low salinity water changed the reservoir wettability towards more water-wet, which is consistent with the observed shift in the relative permeability curves derived from core-scale numerical simulation. Third, the potential of the low salinity water in such high temperature environments was assessed using reservoir simulation based on the input from laboratory experiments.
During well drilling, completion, stimulation and fracturing, moisture invasion and phase trapping lead to a drastic permeability reduction, which prevent the tight gas reservoir producing at an economical rate. To eliminate such formation damage, the power of microwave was considered. As an effective heating technique, the application of microwave heating in removing moisture in the near wellbore area is relatively novel and thus lack of experience. This paper simulates effects of microwave heating on the formation damage and gas production rate of a tight gas reservoir in Western Australia and demonstrates its effectiveness. The well information for a tight gas well in Western Australia was obtained to simulate the actual gas production in numerical model. Finite Element Analysis (FEA) software and industry standard reservoir simulation software were coupled to simulate microwave heating at borehole scale. The electrical conductivity was extracted from well logs and the dielectric constant and loss factor of the reservoir rock was calculated using the empirical equations and proven mixing law. Two cases studied are in non-fractured well and fractured well. In each study, same water amounts were injected for 5days followed by a same period of clean-up and gas production, the difference is one model has microwave heater while the other not. The effects of microwave heating on water saturation and relative permeability to gas were made between two scenarios of gas production with heating and without heating. The electric filed and magnetic field distributions and the heat generation rate in the near wellbore area were calculated based on the actual petrophysical properties of the reservoir rock and Maxwell's Equations. Based on the results from FEA, the heat generated by microwave was applied on the well models respectively. After microwave heating started, gas relative permeability increased and water saturation decreased through the heated zone. In all the cases, microwave heating seems to be an effective way to remove moisture and to recover the gas productivity back to a high rate. But in non-fractured reservoir, the gas production rate has achieved the most improvement. The present paper focuses on the interaction of microwave and trapped moisture in the reservoir. By simulating the heating assisted gas production, illustrate how microwave heating was able to increase gas well productivity by reducing water saturation. More factors need to be considered in the future, and the suggestions have been given in this paper.
The present work studied the effects of microwave heating on sandstones with low porosity and permeability based on the comparison of pore size distribution (PSD) using Nuclear Magnetic Resonance (NMR) technique.
Microwave heating can heat the sandstone in a short time and cause physical and chemical change of rock and fluids inside. The heat evaporated water and changed the structure of minerals and pores so that the permeability increased which was measured from the Automated Permeameter. Before microwave heating, all samples are prepared into three different water saturations for NMR measurements: fully saturated using high pressured saturator, partially saturated using centrifuge and dry using conventional lab oven. Then the T2 distributions were measured in three different conditions. Samples were prepared and measured in the same way after heating.
It is found that Scanning Electron Magnetic (SEM), which can be used to compare the structure changes with high-resolution images, was used to support the NMR measurement; while Medical CT played a similar role by imaging full sample with lower resolution. Together they can give an interpretation of the T2 distribution or the pore size distribution.
The permeability increased after heating and the T2 distribution of each sample has changed. Minerals have been changed due to water evaporation and high temperature. It accounts for the change of T2 distribution. Comparing plots and images before and after heating, the heating effects are obviously positive to EGR.
We have had a good understanding of the effects of high temperature on permeability by studying the change of pore size distribution with NMR before and after heating. With the support of SEM and Medical CT, we got visualized evidence for our interpretation of the change of pore size distribution.
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.
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.