Resistance Method to Determine Oil Saturation Factors Research

2013 ◽  
Vol 807-809 ◽  
pp. 2503-2507
Author(s):  
Jie Nan Dong ◽  
Xu Su ◽  
Lian Feng Liu ◽  
Hong Zhan Wei ◽  
Cheng Long Ning
Keyword(s):  
Oil Recovery ◽  
Measurement Techniques ◽  
Saturation Curve ◽  
Oil Saturation ◽  
Standard Curve ◽  
Oil Distribution ◽  
Remaining Oil ◽  
Measurement Experiment ◽  
The Difference ◽  
Crucial Part

Studying the distribution of the remaining oil is a crucial part in the process of developing oilfield. This study provides the further improvement of oil recovery rate with strong guarantee, and is a necessary method of developing further water controlling of individual reservoir oilfield. Saturation measurement techniques for remaining oil distribution research are particularly important. This paper describes the research of ways of measuring saturation in the resistance measurement experiment, the standard resistance - saturation curve and the factors influencing it. The results show that for different electrode installation, standard curve is mainly affected by the electrode distance. Standard curve is also greatly affected by water salinity, temperature and the difference in corespermeability.

scholarly journals Experimental Investigation on the Characteristic Mobilization and Remaining Oil Distribution under CO2 Huff-n-Puff of Chang 7 Continental Shale Oil

Energies ◽  
2021 ◽  
Vol 14 (10) ◽  
pp. 2782
Author(s):  
Jianhong Zhu ◽  
Junbin Chen ◽  
Xiaoming Wang ◽  
Lingyi Fan ◽  
Xiangrong Nie
Keyword(s):  
Oil Recovery ◽  
Physical Simulation ◽  
Shale Oil ◽  
Economic Cycle ◽  
Cycle Number ◽  
Oil Distribution ◽  
Remaining Oil ◽  
The Difference ◽  
Enhance Oil Recovery ◽  
Very High

The Chang 7 continental shale oil reservoir is tight. The recovery factor is extremely low, the remaining oil is very high, and injecting water to improve oil recovery effectiveness is too hard. Therefore, in this paper, physical simulation experiments of CO2 huff-n-puff shale oil and NMR tests were conducted to study the cycle numbers and permeability on the recovery degree, as well as the characteristics of shale oil mobilization and the remaining oil micro distribution. The results showed that the cumulative oil recovery factors (ORFs) gradually increased in the natural logarithmic form, the single cycle ORFs decreased rapidly in exponential form with the huff-n-puff cycle number, and the biggest economic cycle numbers were between approximately 3 and 5. Furthermore, the higher the permeability, the higher the ORF, but the difference of ORF decreased between the two experimental samples with the cycles. In addition, the gap of production and recovery degree was large between the different scale pores, the ORF of macropores was 6–8 times that of micropores, and the final remaining oil was mainly distributed in the micropores, accounting for 82.29% of the total amount; meanwhile, the macropores comprised less than 0.5%. In the process of huff-n-puff, CO2 flowed into macropores, mesopores, and smallpores under the pressure differential effect, but a small amount of CO2 slowly diffused into micropores, resulting in the ORF of the former with more free oil being higher and the ORF of micropores with more adsorbed oil being lower. Therefore, promoting a better contact and reaction between CO2 and shale oil of micropores is one of the key ways to effectively develop the Chang 7 continental shale oil and enhance oil recovery.

The Research of Flood Pattern Completeness in the Thin and Poor Oil Layers of South West II Area

2012 ◽  
Vol 594-597 ◽  
pp. 2541-2544
Author(s):  
Xiao Hui Wu ◽  
Kao Ping Song ◽  
Chi Dong ◽  
Ji Cheng Zhang ◽  
Jing Fu Deng
Keyword(s):  
Oil Recovery ◽  
Water Flooding ◽  
South West ◽  
Oil Distribution ◽  
Well Pattern ◽  
Remaining Oil ◽  
Tertiary Oil Recovery ◽  
Well Pattern Optimization ◽  
Numerical Simulation Technique

As line well pattern is the main development technique in the thin and poor oil layers of Daqing Oilfield South West Ⅱ PⅠ group, the layers have been idle and the degree of reserve recovery is far less than the region level. In response to these problems, we analyzed the balanced flood performance of various layers and the remaining oil distribution through numerical simulation technique. It shows that, the main remaining oil type of intended layers is caused by voidage-injection imperfection. Considering the needs of the follow-up infill well pattern and tertiary oil recovery, we decided to keep the well network independent and integrated without disturbing the pattern configuration and main mining object of various sets of well pattern. Finally we confirmed to perforate-adding the first infill wells of intended layers to consummate the water flooding regime. Through analyzing the production target of different well pattern optimization programs relatively, it shows that the best program has regular well pattern and large drilled thickness.

scholarly journals Impact of Brine Composition and Concentration on Capillary Pressure and Residual Oil Saturation in Limestone Core Samples

2019 ◽  
Vol 89 ◽  
pp. 02006
Author(s):  
F. Feldmann ◽  
A. M. AlSumaiti ◽  
S. K. Masalmeh ◽  
W. S. AlAmeri ◽  
S. Oedai
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Spontaneous Imbibition ◽  
Oil Saturation ◽  
Salinity Effect ◽  
Connate Water ◽  
Low Salinity ◽  
Remaining Oil ◽  
The Impact ◽  
Secondary Mode

Low salinity water flooding (LSF) is a relatively simple and cheap EOR technique in which the salinit y of the injected water is optimized (by desalination and/or modification) to improve oil recovery over conventional waterflooding. Extensive laboratory experiments investigating the effect of LSF are available in the literature. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. For the first time in literature, this paper presents a comprehensive study of the centrifuge technique to investigate low salinity effect in carbonate samples. The study is divided into three parts. At first, a comprehensive screening was performed on the impact of different connate water and imbibition brine compositions/combinations on the spontaneous imbibition behavior. Second, the subsequent forced imbibition of the samples using the centrifuge method to investigate the impact of brine compositions on residual saturations and capillary pressure. Finally, three unsteady-state (USS) core floodings were conducted in order to examine the potential of the different brines to increase oil recovery in secondary mode (brine injection at connate water saturation) and tertiary mode (exchange of injection brine at mature recovery stage). The experiments were performed using Indiana limestone outcrops. The main conclusions of the study are spontaneous imbibition experiments only showed oil recovery in case the salinity of the imbibing water (IW) is lower than the salinity of the connate water (CW). No oil production was observed when the imbibing water had a higher salinity than the connate water or the salinity of the connate water and imbibing brine were identical. Moreover, the spontaneous imbibition experiments indicated that diluting the salinity of the imbibing water has a larger potential to spontaneously recover oil than the introduction of sulfate-rich sea water. The centrifuge experiments confirmed a connection between the overall salinity and oil recovery. As the salinity of the imbibing brines decreases, the capillary imbibition pressure curves showed an increasing water-wetting tendency and simultaneous reduction of the remaining oil saturation. The lowest remaining oil saturation was obtained for diluted sea water as CW and IW. The core flooding experiments reflected the results of the spontaneous imbibition and centrifuge experiments. Injecting brine at a rate of 0.05 cc/min, sea water and especially diluted sea water resulted in a significant higher oil recovery compared to formation brine. Moreover, when comparing secondary mode experiments, the remaining oil saturation after flooding by diluted sea water, sea water and formation water was 30.6 %, 35.5 % and 37.4 %, respectively. In tertiary injection mode, sea water did not lead to extra oil recovery while diluted sea water led to an additional oil recovery of 5.6 % in one out of two tertiary injection applications.

scholarly journals Microscopic Determination of Remaining Oil Distribution in Sandstones With Different Permeability Scales Using Computed Tomography Scanning

2019 ◽  
Vol 141 (9) ◽  
Author(s):  
Yongfei Yang ◽  
Haiyuan Yang ◽  
Liu Tao ◽  
Jun Yao ◽  
Wendong Wang ◽  
...  
Keyword(s):  
Distribution Pattern ◽  
Oil Recovery ◽  
Distribution Patterns ◽  
High Water ◽  
Water Flooding ◽  
Oil Distribution ◽  
Computed Tomography Scanning ◽  
Remaining Oil ◽  
High Water Cut ◽  
Water Cut

To investigate the characteristics of oil distribution in porous media systems during a high water cut stage, sandstones with different permeability scales of 53.63 × 10−3 μm2 and 108.11 × 10−3 μm2 were imaged under a resolution of 4.12 μm during a water flooding process using X-ray tomography. Based on the cluster-size distribution of oil segmented from the tomography images and through classification using the shape factor and Euler number, the transformation of the oil distribution pattern in different injection stages was studied for samples with different pore structures. In general, the distribution patterns of an oil cluster continuously change during water injection. Large connected oil clusters break off into smaller segments. The sandstone with a higher permeability (108.11 × 10−3 μm2) shows the larger change in distribution pattern, and the remaining oil is trapped in the pores with a radius of approximately 7–12 μm. Meanwhile, some disconnected clusters merge together and lead to a re-connection during the high water cut period. However, the pore structure becomes compact and complex, the residual nonwetting phase becomes static and is difficult to move; and thus, all distribution patterns coexist during the entire displacement process and mainly distribute in pores with a radius of 8–12 μm. For the pore-scale entrapment characteristics of the oil phase during a high water cut period, different enhance oil recovery (EOR) methods should be considered in sandstones correspondent to each permeability scale.

Time-lapse seismic signal analysis for enhanced oil recovery at Cranfield CO2 sequestration site, Cranfield field, Mississippi

2013 ◽  
Vol 1 (2) ◽  
pp. T157-T166 ◽  
Author(s):  
Julie Ditkof ◽  
Eva Caspari ◽  
Roman Pevzner ◽  
Milovan Urosevic ◽  
Timothy A. Meckel ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Time Lapse ◽  
Seismic Signal ◽  
Injection Well ◽  
Saturation Curve ◽  
Seismic Surveys ◽  
Seismic Amplitude ◽  
The Difference ◽  
Seismic Volumes ◽  
4D Seismic

The Cranfield field in southwest Mississippi has been under continuous [Formula: see text] injection by Denbury Onshore LLC since 2008. Two 3D seismic surveys were collected in 2007 and 2010. An initial 4D seismic response was characterized after three years of injection, where more than three million tons of [Formula: see text] remain in the subsurface. This interpretation showed coherent seismic amplitude anomalies in some areas that received large amounts of [Formula: see text] but not in others. To understand these effects better, we performed Gassmann substitution modeling at two wells: the 31F-2 observation well and the 28-1 injection well. We aimed to predict a postinjection saturation curve and acoustic impedance (AI) change through the reservoir. Seismic volumes were cross-equalized, well ties to seismic were performed, and AI inversions were subsequently carried out. Inversion results showed that the change in AI is higher than Gassmann substitution predicted for the 28-1 injection well. The time-lapse AI difference predicted by the inversion is similar in magnitude to the difference inferred from a time delay along a marker horizon below the reservoir.

scholarly journals MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION

2018 ◽  
Vol 40 (2) ◽  
pp. 85-90
Author(s):  
Yani Faozani Alli ◽  
Edward ML Tobing ◽  
Usman Usman
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Viscosity ◽  
Oil Saturation ◽  
Remaining Oil ◽  
Tertiary Oil Recovery

The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.

scholarly journals Optimization Design of Injection Strategy for Surfactant-Polymer Flooding Process in Heterogeneous Reservoir under Low Oil Prices

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3789 ◽  
Author(s):  
He ◽  
Chen ◽  
Yu ◽  
Wen ◽  
Liu
Keyword(s):  
Oil Recovery ◽  
Oil Prices ◽  
Water Flooding ◽  
Fractional Flow ◽  
Simultaneous Injection ◽  
Oil Distribution ◽  
Remaining Oil ◽  
Remaining Oil Distribution ◽  
Incremental Oil Recovery ◽  
Injection Strategies

Surfactant–polymer (SP) flooding has significant potential to enhance oil recovery after water flooding in mature reservoirs. However, the economic benefit of the SP flooding process is unsatisfactory under low oil prices. Thus, it is necessary to reduce the chemical costs and improve SP flooding efficiency to make SP flooding more profitable. Our goal was to maximize the incremental oil recovery of the SP flooding process after water flooding by using the equal chemical consumption cost to ensure the economic viability of the SP flooding process. Thus, a systematic study was carried out to investigate the SP flooding process under different injection strategies by conducting parallel sand pack flooding experiments to optimize the SP flooding design. Then, the comparison of the remaining oil distribution after water flooding and SP flooding under different injection strategies was studied. The results demonstrate that the EOR efficiency of the SP flooding process under the alternating injection of polymer and surfactant–polymer (PASP) is higher than that of conventional simultaneous injection of surfactant and polymer. Moreover, as the alternating cycle increases, the incremental oil recovery increases. Based on the analysis of fractional flow, incremental oil recovery, and remaining oil distribution when compared with the conventional simultaneous injection of surfactant and polymer, the alternating injection of polymer and surfactant–polymer (PASP) showed better sweep efficiency improvement and recovered more remaining oil trapped in the low permeability zone. Thus, these findings could provide insights into designing the SP flooding process under low oil prices.

Residual Oil Saturation Determination for EOR Projects in Means Field, a Mature West Texas Carbonate Field

2012 ◽  
Vol 15 (05) ◽  
pp. 541-553 ◽  
Author(s):  
Prabodh Pathak ◽  
Dale E. Fitz ◽  
Kenneth P. Babcock ◽  
Richard J. Wachtman
Keyword(s):  
Data Acquisition ◽  
Oil Recovery ◽  
Tracer Tests ◽  
Carbonate Reservoir ◽  
Core Analysis ◽  
Residual Oil ◽  
Oil Saturation ◽  
West Texas ◽  
Remaining Oil ◽  
Data Acquisition Program

Summary The technical success of an enhanced oil recovery (EOR) project depends on two main factors: first, the reservoir remaining oil saturation (ROS) after primary and secondary operations, and second, the recovery efficiency of the EOR process in mobilizing the ROS. These two interrelated parameters must be estimated before embarking on a time-consuming and costly process for designing and implementing an EOR process. The oil saturation can vary areally and vertically within the reservoir, and the distribution of the ROS will determine the success of the EOR injectants in mobilizing the remaining oil. There are many methods for determining the oil saturation (Chang et al. 1988; Pathak et al. 1989), and these include core analysis, well-log analysis, log/inject/log (LIL) procedures (Richardson et al. 1973; Reedy 1984), and single-well chemical tracer tests (SWCTT) (Deans and Carlisle 1986). These methods have different depths of investigation and different accuracies, and they all provide valuable information about the distribution of ROS. No single method achieves the best estimate of ROS, and a combination of all these methods is essential in developing a holistic picture of oil saturation and in assessing whether the oil in place (OIP) is large enough to justify the application of an EOR process. As Teletzke et al. (2010) have shown, EOR implementation is a complex process, and a staged, disciplined approach to identifying the key uncertainties and acquiring data for alleviating the uncertainties is essential. The largest uncertainty in some cases is the ROS in the reservoir. This paper presents the results from a fieldwide data acquisition program conducted in a west Texas carbonate reservoir to estimate ROS as part of an EOR project assessment. The Means field in west Texas has been producing for more than the past 75 years, and the producing mechanisms have included primary recovery, secondary waterflooding, and the application of a CO2 EOR process. The Means field is an excellent example of how the productive life and oil recovery can be increased by the application of new technology. The Means story is one of judicious application of appropriate EOR technology to the sustained development of a mature asset. The Means field is currently being evaluated for further expansion of the EOR process, and it was imperative to evaluate the oil saturation in the lower, previously undeveloped zones. This paper briefly outlines the production history, reservoir description, and reservoir management of the Means field, but this paper concentrates on the residual oil zone (ROZ) that underlies the main producing zone (MPZ) and describes a recent data acquisition program to evaluate the oil saturation in the ROZ. We discuss three major methods for evaluating the ROS: core analysis, LIL tests, and SWCTT tests.

Scheme to Tap Remaining Oil Potential in Poor Pay Zones

2013 ◽  
Vol 734-737 ◽  
pp. 1257-1261
Author(s):  
Ji Cheng Zhang ◽  
Shu Hong Zhao ◽  
Jin Yu Lan ◽  
Kao Ping Song
Keyword(s):  
Oil Recovery ◽  
Water Flooding ◽  
Oil Distribution ◽  
Well Pattern ◽  
Remaining Oil ◽  
Tertiary Oil Recovery ◽  
Well Pattern Optimization ◽  
Numerical Simulation Technique ◽  
Production Target

This paper analyzed the balanced flood performance of various layers and the remaining oil distribution through numerical simulation technique. It shows that, the main remaining oil type of intended layers is caused by voidage-injection imperfection. Considering the needs of the follow-up infill well pattern and tertiary oil recovery, we decide to maintain the relative independence and integrity of each well network without disturbing the pattern configuration and the mining exploit object of various sets of well pattern. Finally we confirm to perforate adding the first infill wells of intended layers to consummate the water flooding regime. Through analyzing the production target of different well pattern optimization programs relatively, it shows that the best program has regular well pattern and large drilled thickness.

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