A New Approach of Pressure Profile and Oil Recovery During Dual and Single Core Flooding of Seawater and CO2 Injection Process for Carbonate Reservoir

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.

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Investigation of Properties Alternation during Super-Critical CO2 Injection in Shale

Applied Sciences ◽

10.3390/app9081686 ◽

2019 ◽

Vol 9 (8) ◽

pp. 1686 ◽

Cited By ~ 3

Author(s):

Sai Wang ◽

Kouqi Liu ◽

Juan Han ◽

Kegang Ling ◽

Hongsheng Wang ◽

...

Keyword(s):

Oil Recovery ◽

Supercritical Co2 ◽

Indentation Test ◽

Nitrogen Adsorption ◽

Xrd Analysis ◽

Bet Surface Area ◽

Co2 Injection ◽

Co2 Flooding ◽

Recovery Method ◽

Injection Process

The low recovery of oil from tight liquid-rich formations is still a major challenge for a tight reservoir. Thus, supercritical CO2 flooding was proposed as an immense potential recovery method for production improvement. While up to date, there have been few studies to account for the formation properties’ variation during the CO2 Enhanced Oil Recovery (EOR) process, especially investigation at the micro-scale. This work conducted a series of measurements to evaluate the rock mechanical change, mineral alteration and the pore structure properties’ variation through the supercritical CO2 (Sc-CO2) injection process. Corresponding to the time variation (0 days, 10 days, 20 days, 30 days and 40 days), the rock mechanical properties were analyzed properly through the nano-indentation test, and the mineralogical alterations were quantified through X-ray diffraction (XRD). In addition, pore structures of the samples were measured through the low-temperature N2 adsorption tests. The results showed that, after Sc-CO2 injection, Young’s modulus of the samples decreases. The nitrogen adsorption results demonstrated that, after the CO2 injection, the mesopore volume of the sample would change as well as the specific Brunauer–Emmett–Teller (BET) surface area which could be aroused from the chemical reactions between the CO2 and some authigenic minerals. XRD analysis results also indicated that mesopore were altered due to the chemical reaction between the injected Sc-CO2 and the minerals.

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Compatibility evaluation of modified seawater for EOR in carbonate reservoirs through the introduction of polyphosphate compound

Petroleum Science ◽

10.1007/s12182-019-00380-6 ◽

2019 ◽

Vol 17 (2) ◽

pp. 393-408 ◽

Cited By ~ 1

Author(s):

Bisweswar Ghosh ◽

Liying Sun ◽

Nithin Chacko Thomas

Keyword(s):

Oil Recovery ◽

Economic Benefits ◽

Carbonate Reservoir ◽

Carbonate Reservoirs ◽

Core Flooding ◽

Systematic Screening ◽

Flood Water ◽

Scaling Potential ◽

Original Oil In Place ◽

New Formulation

Abstract Waterflood-assisted oil recovery with sulfate-spiked seawater would cause incompatibility scaling in carbonate reservoirs and reduce economic benefits. This research investigated the benefits of polyphosphate compounds in reducing scaling potential as well as its effect on oil recovery when mixed in high sulfate flood water. Severity of scaling potential of sulfate-spiked water in a carbonate reservoir environment was measured, followed by systematic screening of a polyphosphate compound, which successfully inhibited the sulfate scale precipitation at concentration as low as 100 ppm. The new formulation (seawater with four times sulfate and phosphate, SW4SP) was evaluated and compared with benchmark formulation (modified seawater with four times sulfate, SW4S). Contact angle, ζ-potential and drainage studies show that SW4SP changed the rock wettability from oil wet to water wet to a larger degree compared to SW4S. Improved recovery efficiency of SW4SP was confirmed through a set of core flooding studies in the tertiary and quaternary flood modes. Whereas SW4S recovered 7.7% of original oil in place (OOIP), SW4SP recovered about 8% of OOIP in the tertiary mode under approximately identical flow conditions. Flooding with SW4SP in the quaternary mode following a tertiary flood with SW4S on the same core resulted in 1.7% additional oil recovery, showing improved efficiency of the new flood water formulation.

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An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs

Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles ◽

10.2516/ogst/2019018 ◽

2019 ◽

Vol 74 ◽

pp. 59 ◽

Cited By ~ 2

Author(s):

Erhui Luo ◽

Zifei Fan ◽

Yongle Hu ◽

Lun Zhao ◽

Jianjun Wang

Keyword(s):

Oil Recovery ◽

Gas Injection ◽

Simulation Method ◽

Carbonate Reservoir ◽

Gas Oil ◽

Oil Composition ◽

Acid Gas ◽

Compositional Model ◽

Injection Process ◽

Acid Gas Injection

Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.

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MODEL-BASED OPTIMIZATION OF CYCLES OF CO2 WATER-ALTERNATING-GAS (CO2-WAG) INJECTION IN CARBONATE RESERVOIR

Brazilian Journal of Petroleum and Gas ◽

10.5419/bjpg2021-0012 ◽

2022 ◽

Vol 15 (4) ◽

pp. 139-149

Author(s):

F. G. A. Pereira ◽

V. E. Botechia ◽

D. J. Schiozer

Keyword(s):

Oil Recovery ◽

Carbonate Reservoir ◽

Co2 Production ◽

Co2 Injection ◽

Optimal Size ◽

Control Variables ◽

Limit Values ◽

Water Alternating Gas ◽

Production Wells ◽

The Impact

Pre-salt reservoirs are among the most important discoveries in recent decades due to the large quantities of oil in them. However, high levels of uncertainties related to its large gas/CO2 production prompt a more complex gas/CO2 management, including the use of alternating water and gas/CO2 injection (WAG) as a recovery mechanism to increase oil recovery from the field. The purpose of this work is to develop a methodology to manage cycle sizes of the WAG/CO2, and analyze the impact of other variables related to the management of producing wells during the process. The methodology was applied to a benchmark synthetic reservoir model with pre-salt characteristics. We used five approaches to evaluate the optimum cycle size under study, also assessing the impact of the management of producing wells: (A) without closing producers due to gas-oil ratio (GOR) limit; (B) GOR limit fixed at a fixed value (1600 m³/m³) for all wells; (C) GOR limit optimized per well; (D) joint optimization between GOR limit values of producers and WAG cycles; and (E) optimization of the cycle size per injector well with an optimized GOR limit. The results showed that the optimum cycle size depends on the management of the producers. Leaving all production wells open until the end of the field's life (without closing based on the GOR limit) or controlling the wells in a more restricted manner (with closing based on the GOR limit), led to significant variation of the results (optimal size of the WAG/CO2 cycles). Our study, therefore, demonstrates that the optimum cycle size depends on other control variables and can change significantly due to these variables. This work presents a study that aimed to manage the WAG-CO2 injection cycle size by optimizing the life cycle control variables to obtain better economic performance within the premises already established, such as the total reinjection of gas/CO2 produced, also analyzing the impact of other variables (management of producing wells) along with the WAG-CO2 cycles.

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Effective Prediction and Management of a CO2 Flooding Process for Enhancing Oil Recovery Using Artificial Neural Networks

Journal of Energy Resources Technology ◽

10.1115/1.4038054 ◽

2017 ◽

Vol 140 (3) ◽

Cited By ~ 31

Author(s):

Si Le Van ◽

Bo Hyun Chon

Keyword(s):

Oil Recovery ◽

Water Saturation ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

Environmental Benefits ◽

Co2 Production ◽

Co2 Injection ◽

Co2 Flooding ◽

Injection Process ◽

Artificial Neural

The injection of CO2 has been in global use for enhanced oil recovery (EOR) as it can improve oil production in mature fields. It also has environmental benefits for reducing greenhouse carbon by permanently sequestrating CO2 (carbon capture and storage (CCS)) in reservoirs. As a part of numerical studies, this work proposed a novel application of an artificial neural network (ANN) to forecast the performance of a water-alternating-CO2 process and effectively manage the injected CO2 in a combined CCS–EOR project. Three targets including oil recovery, net CO2 storage, and cumulative gaseous CO2 production were quantitatively simulated by three separate ANN models for a series of injection frames of 5, 15, 25, and 35 cycles. The concurrent estimations of a sequence of outputs have shown a relevant application in scheduling the injection process based on the progressive profile of the targets. For a specific surface design, an increment of 5.8% oil recovery and 4% net CO2 storage was achieved from 25 cycles to 35 cycles, suggesting ending the injection at 25 cycles. Using the models, distinct optimizations were also computed for oil recovery and net CO2 sequestration in various reservoir conditions. The results expressed a maximum oil recovery from 22% to 30% oil in place (OIP) and around 21,000–29,000 tons of CO2 trapped underground after 35 cycles if the injection began at 60% water saturation. The new approach presented in this study of applying an ANN is obviously effective in forecasting and managing the entire CO2 injection process instead of a single output as presented in previous studies.

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