scholarly journals Experimental Investigation on the Effects of CO2 Displacement Methods on Petrophysical Property Changes of Ultra-Low Permeability Sandstone Reservoirs Near Injection Wells

Energies ◽  
2019 ◽  
Vol 12 (2) ◽  
pp. 327 ◽  
Author(s):  
Qian Wang ◽  
Shenglai Yang ◽  
Haishui Han ◽  
Lu Wang ◽  
Kun Qian ◽  
...  
Keyword(s):  
Physical Properties ◽  
Pore Size ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Low Permeability ◽  
Co2 Flooding ◽  
Formation Water ◽  
Injection Wells ◽  
Rock Interaction ◽  
Sandstone Reservoirs

The petrophysical properties of ultra-low permeability sandstone reservoirs near the injection wells change significantly after CO2 injection for enhanced oil recovery (EOR) and CO2 storage, and different CO2 displacement methods have different effects on these changes. In order to provide the basis for selecting a reasonable displacement method to reduce the damage to these high water cut reservoirs near the injection wells during CO2 injection, CO2-formation water alternate (CO2-WAG) flooding and CO2 flooding experiments were carried out on the fully saturated formation water cores of reservoirs with similar physical properties at in-situ reservoir conditions (78 °, 18 MPa), the similarities and differences of the changes in physical properties of the cores before and after flooding were compared and analyzed. The measurement results of the permeability, porosity, nuclear magnetic resonance (NMR) transversal relaxation time (T2) spectrum and scanning electron microscopy (SEM) of the cores show that the decrease of core permeability after CO2 flooding is smaller than that after CO2-WAG flooding, with almost unchanged porosity in both cores. The proportion of large pores decreases while the proportion of medium pores increases, the proportion of small pores remains almost unchanged, the distribution of pore size of the cores concentrates in the middle. The changes in range and amplitude of the pore size distribution in the core after CO2 flooding are less than those after CO2-WAG flooding. After flooding experiments, clay mineral, clastic fines and salt crystals adhere to some large pores or accumulate at throats, blocking the pores. The changes in core physical properties are the results of mineral dissolution and fines migration, and the differences in these changes under the two displacement methods are caused by the differences in three aspects: the degree of CO2-brine-rock interaction, the radius range of pores where fine migration occurs, the power of fine migration.

Pore–Scale Numerical Investigations of the Impact of Mineral Dissolution and Transport in Naturally Fractured Systems During CO2–Enriched Brine Injection

2021 ◽  
Author(s):  
Jiahui You ◽  
Kyung Jae Lee
Keyword(s):  
Dissolution Rate ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Initial Time ◽  
Co2 Injection ◽  
Pore Scale ◽  
Acid Rock ◽  
Rock Interaction ◽  
Connected Area ◽  
The Impact

Abstract CO2 storage and sequestration are regarded as an effective approach to mitigate greenhouse gas emissions. While injecting an enormous amount of CO2 into carbonate–rich aquifers, CO2 dissolves in the formation brine under the large pressure, and the subsequently formed CO2–enriched brine reacts with the calcite. Reaction–induced changes in pore structure and fracture geometry alter the porosity and permeability, giving rise to concerns of CO2storage capacity and security. Especially in the reservoir or aquifer with natural fractures, the fractures provide a highly permeable pathways for fluid flow. This study aims to analyze the acid–rock interaction and subsequent permeability evolution in the systems with complex fracture configurations during CO2 injection by implementing a pore–scale DBS reactive transport model. The model has been developed by expanding the functionality of OpenFOAM, which is an open–source code for computational fluid dynamics. A series of partial differential equations are discretized by applying the Finite Volume Method (FVM) and sequentially solved. Different fracture configurations in terms of fracture length, density, connection, and mineral components have been considered to investigate their impacts on the dynamic porosity–permeability relationship, dissolution rate, and reactant transport characteristics during CO2 storage. The investigation revealed several interesting findings. We found that calcium (Ca) concentration was low in the poorly connected area at the initial time. As CO2–enriched brine saturated the system and reacted with calcite, Ca started being accumulated in the system. However, Ca barely flowed out of the poor–connected area, and the concentration became high. Lengths of branches mainly influenced the dissolution rates, while they had slight impacts on the porosity–permeability relationship. While fracture connectivity had an apparent influence on the porosity–permeability relationship, it showed a weak relevance on the dissolution rate. These microscopic insights can help enhance the CO2 sealing capacity and guarantee environmental security.

scholarly journals Supercritical CO2-involved water–rock interactions at 85℃ and partial pressures of 10–20 MPa: Sequestration and enhanced oil recovery

2017 ◽  
Vol 35 (2) ◽  
pp. 237-258 ◽  
Author(s):  
Xiaoyu Wang ◽  
Xiaolin Wang ◽  
Wenxuan Hu ◽  
Ye Wan ◽  
Jian Cao ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Interaction Mechanism ◽  
Recovery Process ◽  
Sample Surface ◽  
Mineral Dissolution ◽  
Reservoir Rock ◽  
Formation Water ◽  
High Concentration ◽  
Rock Interaction

Studying the interactions between CO2-rich fluid and reservoir rock under reservoir temperature and pressure is important for investigating CO2 sequestration and the CO2-enhanced oil recovery processes. Using high-concentration CaCl2-type formation water as an example, this study performed a CO2-rich fluid–rock interaction experiment at 85℃ and compared the dissolution of calcite and sandstone samples, as well as sandstone powder and thin-slice samples. This study also investigated the effects of the sample surface area, the CO2 partial pressure ( PCO2 = 10 and 20 MPa), and the composition of formation water (3 mol/kg NaCl and 1 mol/kg CaCl2–2 mol/kg NaCl) on the water–rock interaction mechanism and process by weighing, ion chromatography, and scanning electron microscopy observations. The results showed that the injection of CO2 resulted in the dissolution of reservoir minerals such as carbonate cements and feldspar. The mineral dissolution increased with increasing PCO2. The dissolution of minerals such as calcite in the CaCl2-type formation water was significantly decreased because of the high concentration of Ca2+. Under the same conditions, more sandstone dissolved than calcite and more sandstone powder dissolved than sandstone thin slices. Dissolution of the potassium feldspar occurred in the sandstone, whereas the albite was nearly unaffected. No new minerals formed during the experimental process. The experimental results and a PHREEQC calculation demonstrated that the injection of CO2 causes a significant pH drop in the formation water, which improves the porosity and permeability of the reservoir, increases the capacity of the reservoir to store CO2, and facilitates the progression of the CO2-enhanced oil recovery process. However, if alkaline minerals in the caprocks of the reservoir are also dissolved by the CO2-rich fluid, the sealing capacity of the caprocks may be reduced.

Lessons from Trinidad's CO2 Immiscible Pilot Projects

2005 ◽  
Vol 8 (05) ◽  
pp. 397-403 ◽  
Author(s):  
Lorna J. Mohammed-Singh ◽  
Ashok K. Singhal
Keyword(s):  
Natural Gas ◽  
Oil Recovery ◽  
Water Injection ◽  
Lessons Learned ◽  
Co2 Injection ◽  
Efficient Production ◽  
Co2 Flooding ◽  
Injection Wells ◽  
Forest Reserve ◽  
Stable Mode

Summary Four immiscible carbon dioxide (CO2) pilot floods were implemented in the Petroleum Co. of Trinidad and Tobago's (Petrotrin's) reservoirs at its Forest Reserve and Oropouche fields, Trinidad, over the period 1973 to 1990. The projects were conducted in a gravity-stable mode after primary, secondary, and tertiary production (after natural-gas and water injection). CO2 was injected into thick sands of variable continuity containing medium-gravity crude (17 to29°API). Production increases were observed in all projects. It is postulated that injected CO2 swelled the oil, reduced viscosity and helped form oil banks that could move more easily under gravity. Oil-production rates and recovery improved as a consequence. In some of the projects, these beneficial effects continued for several years, even after discontinuation of CO2 injection(supply interruptions), with recovery aided by water influx. Interruptions in CO2 supply did not appear to harm incremental oil recovery materially. Channeling was observed at high injection rates and was promoted in reservoirs with low transmissibility. Oil recovery improved as more offtake (production) wells were added downstream of the injection wells. This phenomenon reinforced the importance of optimizing volumetric sweep and of capture during CO2 flooding by judiciously selecting injection and offtake locations. Incremental recovery ranges between2 and 8% of the original oil in place (OOIP), with predicted ultimate recoveries of 4 to 9% of OOIP. Cumulative CO2 use improved with efficient production practices and ranges from 3 to 11 Mcf/bbl to date. Introduction The Forest Reserve and Oropouche fields are located in the southwest peninsula of the island of Trinidad, as shown in Fig. 1. In 1973, CO2 injection was initiated into a former natural-gas-injection project in Forest Reserve when there was a shortage of natural gas. Three immiscible pilot floods and one cyclic-injection project were later implemented between 1974 and 1986. Another immiscible pilot flood was implemented in 1990 in the Oropouche field. These projects were implemented in a "poor boy" mode using existing wells and equipment. CO2 is piped 25 miles from an ammonia plant, compressed, and injected into target reservoirs. This paper documents Petrotrin's 30 years of experience1 with CO2 immiscible injection into these projects and presents a comparative analysis of the performance of the four enhanced-oil-recovery (EOR) projects with some immiscible CO2-flood projects from the literature. Results and lessons learned will be used to guide the extension of CO2 injection to other similar reservoirs in the company's operations and to improve the management of existing projects.

scholarly journals Impact of Diagenesis on the Low Permeability Sandstone Reservoir: Case Study of the Lower Jurassic Reservoir in the Niudong Area, Northern Margin of Qaidam Basin

Minerals ◽  
2021 ◽  
Vol 11 (5) ◽  
pp. 453
Author(s):  
Wenhuan Li ◽  
Tailiang Fan ◽  
Zhiqian Gao ◽  
Zhixiong Wu ◽  
Ya’nan Li ◽  
...  
Keyword(s):  
Physical Properties ◽  
Oil And Gas ◽  
Qaidam Basin ◽  
Isotope Analysis ◽  
Lower Jurassic ◽  
Low Permeability ◽  
Hydrocarbon Generation ◽  
Northern Margin ◽  
Pore Evolution ◽  
Sandstone Reservoir

The Lower Jurassic reservoir in the Niudong area of the northern margin of Qaidam Basin is a typical low permeability sandstone reservoir and an important target for oil and gas exploration in the northern margin of the Qaidam Basin. In this paper, casting thin section analysis, scanning electron microscopy, X-ray diffraction, and stable isotope analysis among other methods were used to identify the diagenetic characteristics and evolution as well as the main factors influencing reservoir quality in the study area. The predominant types of sandstone in the study area are mainly feldspathic lithic sandstone and lithic arkose, followed by feldspathic sandstone and lithic sandstone. Reservoir porosity ranges from 0.01% to 19.5% (average of 9.9%), and permeability ranges from 0.01 to 32.4 mD (average of 3.8 mD). The reservoir exhibits robust heterogeneity and its quality is mainly influenced by diagenesis. The Lower Jurassic reservoir in the study area has undergone complex diagenesis and reached the middle diagenesis stage (A–B). The quantitative analysis of pore evolution showed that the porosity loss rate caused by compaction and cementation was 69.0% and 25.7% on average, and the porosity increase via dissolution was 4.8% on average. Compaction was the main cause of the reduction in the physical property of the reservoir in the study area, while cementation and dissolution were the main causes of reservoir heterogeneity. Cementation can reduce reservoir space by filling primary intergranular pores and secondary dissolved pores via cementation such as a calcite and illite/smectite mixed layer, whereas high cement content increased the compaction resistance of particles to preserve certain primary pores. δ13C and δ18O isotopes showed that the carbonate cement in the study area was the product of hydrocarbon generation by organic matter. The study area has conditions that are conductive to strong dissolution and mainly occur in feldspar dissolution, which produces a large number of secondary pores. It is important to improve the physical properties of the reservoir. Structurally, the Niudong area is a large nose uplift structure with developed fractures, which can be used as an effective oil and gas reservoir space and migration channel. In addition, the existence of fractures provides favorable conditions for the uninterrupted entry of acid fluid into the reservoir, promoting the occurrence of dissolution, and ultimately improves the physical properties of reservoirs, which is mainly manifested in improving the reservoir permeability.

Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated With H2S Into Depleted Gas Fields in the Northeast of the Netherlands

SPE Journal ◽  
2014 ◽  
Vol 19 (06) ◽  
pp. 1058-1068 ◽  
Author(s):  
P.. Bolourinejad ◽  
R.. Herber
Keyword(s):  
The Netherlands ◽  
Carbonic Acid ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Geological Time ◽  
Core Samples ◽  
Carbon Dioxide Co2 ◽  
Gas Fields

Summary Depleted gas fields are among the most probable candidates for subsurface storage of carbon dioxide (CO2). With proven reservoir and qualified seal, these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine because of the formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and caprock. Thus, for adequate, safe, and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. To investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30-day) laboratory experiments (300 bar, 100°C) on reservoir and caprock core samples from gas fields in the northeast of the Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream [hydrogen sulfide (H2S)] in these fields. The injected gases—CO2, CO2+100 ppm H2S, and CO2+5,000 ppm H2S—were reacting with core samples and brine (81 g/L Na+, 173 g/L Cl−, 22 g/L Ca2+, 23 g/L Mg2+, 1.5 g/L K+, and 0.2 g/L SO42−). Before and after the experiments, the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. The permeability of the samples was also measured. After the experiments, dissolution of feldspars, carbonates, and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S to the CO2 stream. First, we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection, where dissolution of anhydrite was dominant in the samples. Second, severe salt precipitation took place in the presence of H2S. This is mainly caused by the nucleation of anhydrite and pyrite, which enabled halite precipitation, and to a lesser degree by the higher solubility of H2S in water and higher water content of the gas phase in the presence of H2S. This was confirmed by the use of CMG-GEM (CMG 2011) modeling software. The precipitation of halite, anhydrite, and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and ≤3%, respectively. In caprock samples, permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5,000 ppm H2S, the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, halite, anhydrite, and pyrite precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.

scholarly journals Corrosion Study on Wellbore Materials for the CO2 Injection Process

Processes ◽  
2021 ◽  
Vol 9 (1) ◽  
pp. 115
Author(s):  
Le Quynh Hoa ◽  
Ralph Bäßler ◽  
Dirk Bettge ◽  
Enrico Buggisch ◽  
Bernadette Nicole Schiller ◽  
...  
Keyword(s):  
Cross Sections ◽  
Low Cost ◽  
Co2 Injection ◽  
Uniform Corrosion ◽  
Injection Wells ◽  
Safety Issues ◽  
Carbonation Process ◽  
Injection Process ◽  
Materials Used ◽  
Low Alloyed Steel

For reliability and safety issues of injection wells, corrosion resistance of materials used needs to be determined. Herein, representative low-cost materials, including carbon steel X70/1.8977 and low alloyed steel 1.7225, were embedded in mortar to mimic the realistic casing-mortar interface. Two types of cement were investigated: (1) Dyckerhoff Variodur commercial Portland cement, representing a highly acidic resistant cement and (2) Wollastonite, which can react with CO2 and become stable under a CO2 stream due to the carbonation process. Exposure tests were performed under 10 MPa and at 333 K in artificial aquifer fluid for up to 20 weeks, revealing crevice corrosion and uniform corrosion instead of expected pitting corrosion. To clarify the role of cement, simulated pore water was made by dispersing cement powder in aquifer fluid and used as a solution to expose steels. Surface analysis, accompanied by element mapping on exposed specimens and their cross-sections, was carried out to trace the chloride intrusion and corrosion process that followed.

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