The Experimental Study on the Flooding Regularities of Various CO2 Flooding Modes Implemented on Ultralow Permeability Cores

2018 ◽  
Vol 140 (7) ◽  
Author(s):  
Aifen Li ◽  
Xiaoxia Ren ◽  
Shuaishi Fu ◽  
Jiao Lv ◽  
Xuguang Li ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Water Injection ◽  
Water Flooding ◽  
Co2 Injection ◽  
Rapid Decline ◽  
Co2 Flooding ◽  
Gas Oil ◽  
Water Cut ◽  
Ultralow Permeability

The application of water flooding is not successful for the development of low permeability reservoirs due to the fine pore sizes and the difficulty of water injection operation. CO2 can dissolve readily in crude oil and highly improve the mobility of crude oil, which makes CO2 flooding an effective way to the development of the ultralow-permeability reservoirs. The regularities of various CO2 displacement methods were studied via experiments implemented on cores from Chang 8 Formation of Honghe Oilfield. The results show that CO2 miscible displacement has the minimum displacement differential pressure and the maximum oil recovery; CO2-alternating-water miscible flooding has lower oil recovery, higher drive pressure, and relatively lower gas-oil ratio; water flooding has the minimum oil recovery and the maximum driving pressure. A large amount of oil still can be produced under a high gas-oil ratio condition through CO2 displacement method. This fact proves that the increase of gas-oil ratio is caused by the production of dissolved CO2 in oil rather than the free gas breakthrough. At the initial stage of CO2 injection, CO2 does not improve the oil recovery immediately. As the injection continues, the oil recovery can be improved rapidly. This phenomenon suggests that when CO2 displacement is performed at high water cut period, the water cut does not decrease immediately and will remain high for a period of time, then a rapid decline of water cut and increase of oil production can be observed.

Improving Water Injectivity Through Lateral Radial Drilling into the Reservoir

2021 ◽  
Author(s):  
Effiong Essien ◽  
Uchenna Onyejiaka ◽  
Stanley Onwukwe ◽  
Nnaemeka Uwaezuoke
Keyword(s):  
Oil Recovery ◽  
Damage Zone ◽  
Water Injection ◽  
Progressive Increase ◽  
Recovery Factor ◽  
Water Flooding ◽  
Increase With Increase ◽  
Drilling Technology ◽  
Water Cut ◽  
Radial Drilling

Abstract Poor formation permeability and near well bore damage may limit water injectivity into the reservoir in a water injection project. This paper seeks to evaluate the effect of radial drilling technique on water injectivity and oil recovery in water flooding operation. Radial drilling technology utilizes hydraulic energy to create lateral perpendicular small holes through the casing into the reservoir. The holes may extend to 100 m (330 ft) into the reservoir to access fresh formations beyond the near wellbore, and damage zone. A black oil simulator (Eclipse 100) was used to modeling a lateral radial drill from the borehole into the reservoir, and that of a conventional perforation of the wellbore respectively. A simulation study was carried out using various presumed radial drill configurations in determining injectivity index, displacement efficiencies, recovery factor and water cut of the process. The determined results were further compared with that of the conventional perforation process case respectively. The results show a significant improvement in water injectivity in radial drill case with the increasing length and number of radials as compared to the conventional wellbore perforation case. The determined Recovery factor shows a progressive increase with increase in the numbers of radials drilled, irrespective of the radial length. However, it was observed that, the more the number and length of the radials drilled in to the reservoir, the higher the water cut from producer wells. Radial Drilling Technology, therefore, has a promising potential to improving water injectivity into the reservoir and thereby optimizing oil recovery in a water flooding operation.

scholarly journals Techniques for improving the water-flooding of oil fields during the high water-cut stage

2019 ◽  
Vol 74 ◽  
pp. 69 ◽  
Author(s):  
Kuiqian Ma ◽  
Ao Li ◽  
Shuhao Guo ◽  
Jieqiong Pang ◽  
Yongchao Xue ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Reduction Rate ◽  
High Water ◽  
Water Flooding ◽  
Variable Intensity ◽  
Remaining Oil ◽  
High Water Cut Stage ◽  
High Water Cut ◽  
Water Cut

The multi-layer co-exploitation method is often used in offshore oilfields because of the large spacing between the injection and production wells. As oilfields gradually enter the high water-cut stage, the contradiction between the horizontal and vertical directions becomes more prominent, and the distribution of the remaining oil is more complex. Oilfields are facing unprecedented challenges in further enhancing oil recovery. Using oilfield A, which is in the high water-cut stage, as the research object, we compiled a detailed description of the remaining oil during the high water-cut stage using the information collected during the comprehensive adjustment and infilling of the oilfield. In addition various techniques for tapping the potential reservoir, stabilizing the oil, and controlling the water were investigated. A set of key techniques for the continuous improvement of the efficiency of water injection after comprehensive adjustment of high water-cut fields was generated. Based on the determined configuration of the offshore deltaic reservoir, a set of detailed descriptive methods and tapping technology for extracting the remaining oil in the offshore high water-cut oilfield after comprehensive adjustment was established. By considering the equilibrium displacement and using a new quantitative characterization method that includes displacement, a new technique for determining the quantity of water that needs to be injected into a stratified injection well during the high water-cut stage was established. Based on the principle of flow field intensity reconfiguration, a linear, variable-intensity, alternating injection and withdrawal technique was proposed. With the application of this series of techniques, the increase in the water content was controlled to within 1%, the natural reduction rate was controlled to within 9%, and the production increased by 1.060 × 107 m3.

scholarly journals Study on Reasonable Injection-Production Parameters of Water-Flooding Reservoir: A Case Study of Daqing Oilfield

2021 ◽  
Vol 329 ◽  
pp. 01065
Author(s):  
Cong Nie
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Water Flooding ◽  
Evaluation Indexes ◽  
The Third ◽  
Production Parameters ◽  
Production Ratio ◽  
Optimization Principle ◽  
Water Cut

This paper, by conducting comprehensive analysis on water-flooding reservoir, intensively studied and discussed the characteristics of geological development, determined the evaluation indexes of development effect, carried out research from five steps, the first is the introduction part, it conducted indepth study and discussion from research background, research significance, literature review, and research methods four aspects. The second outlined the related theory from the optimization principle and mechanism of injection-production parameters, and the distribution mechanism of remaining oil two aspects. The third analyzed the current situation of reasonable injection-production of water-flooding reservoirs in Daqing Oilfield from reservoir characteristics and reservoir deposition. The fourth evaluated the water-flooding development effect from combined water cut, changing conditions of production and predicted recovery ratio. The fifth intensively studied the reasonable injection-production parameters of water- flooding reservoirs in Daqing oilfield from design of separated layer water injection plan, maintaining level reservoir formation pressure, and reasonable plan of injection-production ratio and oil recovery rate three aspects, and provides theoretical guidance for later targeted excavation of water-flooding reservoirs.

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.

Enhanced heavy oil recovery and CO2 storage in a reservoir with high-water-cut: laboratory to field

2021 ◽  
Author(s):  
Xiang Zhou ◽  
Yongsheng Tan ◽  
Qi Jiang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Co2 Storage ◽  
High Water ◽  
Production Performance ◽  
Water Flooding ◽  
Heavy Oil Recovery ◽  
Co2 Flooding ◽  
High Water Cut ◽  
Water Cut

<p>In this study, in order to enhance heavy oil recovery in the heavy oil reservoir with a high-water-cut after water flooding process, experimental and numerical simulation studies are conducted. In the experimental studies, firstly, the properties of the heavy oil-CO2 system were measured under different saturation pressures at the reservoir temperature. Secondly, to mimic the high-water-cut condition in the real reservoir, water flooding process was conducted for each core; then four long core experiments insist of one CO2 huff `n` puff process and three CO2 flooding processes were implemented. The CO2 huff `n` puff process is conducted to compare the production performance with that in the CO2 flooding process to optimize the method. Regarding the CO2 flooding process, different gas (pure CO2, flue gas) and different production categories (constant production pressure, pressure depletion) were applied to study the heavy oil production performance in the heavy oil reservoir with high-water-cut. The experimental results indicate that, the CO2 flooding coupling with pressure depletion process is the best choice to reduce the water-cut and enhance the heavy oil recovery, which is 41.84% of the original oil in place and the water-cut reduced to lower than 70%. In the numerical simulation studies, the WinProp module in CMG is applied to simulate the properties of the heavy oil-CO2 system, which is generated by recombining CO2 into heavy oil, and high agreement simulation results were obtained. Then the results of the optimized experiment were history matched using GEM module. Finally, the upscaling studied was conducted. The CO2 flooding processes are carried out in the studied reservoir to maximum the heavy oil recovery factor. Moreover, the CO2 storage ratio is studied using GEM model.</p>

scholarly journals Investigation of Oil Recovery in Fractured Carbonate Rock by

2016 ◽  
Vol 6 (1) ◽  
pp. 14
Author(s):  
H. Karimaie ◽  
O. Torsæter
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Co2 Injection ◽  
Recovery Method ◽  
Asmari Limestone ◽  
Fractured Carbonate ◽  
Efficient Recovery ◽  
Live Oil ◽  
Non Equilibrium

The purpose of the three experiments described in this paper is to investigate the efficiency of secondary andtertiary gas injection in fractured carbonate reservoirs, focusing on the effect of equilibrium gas,re-pressurization and non-equilibrium gas. A weakly water-wet sample from Asmari limestone which is the mainoil producing formation in Iran, was placed vertically in a specially designed core holder surrounded withfracture. The unique feature of the apparatus used in the experiment, is the capability of initializing the samplewith live oil to obtain a homogeneous saturation and create the fracture around it by using a special alloy whichis easily meltable. After initializing the sample, the alloy can be drained from the bottom of the modified coreholder and create the fracture which is filled with live oil and surrounded the sample. Pressure and temperaturewere selected in the experiments to give proper interfacial tensions which have been measured experimentally.Series of secondary and tertiary gas injection were carried out using equilibrium and non-equilibrium gas.Experiments have been performed at different pressures and effect of reduction of interfacial tension werechecked by re-pressurization process. The experiments showed little oil recovery due to water injection whilesignificant amount of oil has been produced due to equilibrium gas injection and re-pressurization. Results alsoreveal that CO2 injection is a very efficient recovery method while injection of C1 can also improve the oilrecovery.

scholarly journals A Reheat Gas Turbine Oilfield Cogeneration System, Fueled With Heavy Crude Oil, Which Produces Very Low NOx Emissions

1987 ◽  
Author(s):  
Frederick E. Moreno ◽  
Philip J. Divirgilio
Keyword(s):  
Crude Oil ◽  
Gas Turbine ◽  
Steam Generator ◽  
Oil Recovery ◽  
Catalytic Reduction ◽  
Water Injection ◽  
Industrial Process ◽  
Field Testing ◽  
Nox Emissions ◽  
Cogeneration System

A gas turbine cogeneration system is described that offers fuel flexibility plus substantially reduced NOx emissions without water injection or selective catalytic reduction (SCR). The entirely new turbine design developed by TurboEnergy Systems permits boiler repowering and other cogeneration applications. The first application will be in the California heavy oilfields; the system will be retrofitted to an existing 50 million btu/hr oilfield steam generator used in thermally enhanced oil recovery. The turbine, rated at 1250 kw (site output), was sized to match the combustion air flow requirements of the steam generator. A reheated design was selected to maximize power output from the limited airflow available and to maximize the exhaust temperature for cogeneration and industrial process applications. The oilfield cogeneration system being developed includes a new heavy oil burner for the steam generator which will be fired on the high temperature exhaust from the turbine. The system will also provide low NOx emissions, below the tightest projected standards in Kern County, which has a large concentration of heavy oilfields. Both the turbine and the steam generator burner will burn heavy (API 13 gravity) crude oil. The paper describes the overall system, its interface with the existing process, the design techniques used, and presents performance projections. Field testing will begin at a site near Bakersfield, California, starting in early to mid-1987.

Experimental Study on Direct Current Voltage Assisted Carbonated Water-Flooding Mechanism in Tight Oil Reservoir

2021 ◽  
Author(s):  
Rukuan Chai ◽  
Yuetian Liu ◽  
Yuting He ◽  
Qianjun Liu ◽  
Wenhuan Gu
Keyword(s):  
Crude Oil ◽  
Direct Current ◽  
Oil Recovery ◽  
Co2 Sequestration ◽  
Water Flooding ◽  
Current Voltage ◽  
Direct Current Voltage ◽  
Carbonated Water ◽  
Ft Icr Ms ◽  
Ft Icr

Abstract Tight oil reservoir plays an increasingly important role in the world energy system, but its recovery is always so low. Hence, a more effective enhanced oil recovery (EOR) technology is urgently needed. Meanwhile, greenhouse effect is more and more serious, a more effective carbon capture and sequestration (CCS) method is also badly needed. Direct current voltage assisted carbonated water-flooding is a new technology that combines direct current voltage with carbonated water-flooding to enhance oil recovery and CO2 sequestration efficiency, simultaneously. Experimental studies were conducted from macroscopic-scale to microscopic-scale to study the performance and mechanism of direct current voltage assisted carbonated water-flooding. Firstly, core flood experiments were implemented to study the effect of direct current voltage assisted carbonated water on oil recovery and CO2 sequestration efficiency. Secondly, contact angle and interfacial tension/dilatational rheology were measured to analyze the effect of direct current voltage assisted carbonated water on crude oil-water-rock interaction. Thirdly, total organic carbon (TOC), gas chromatography (GC), and electrospray ionization-fourier transform ion cyclotron resonance-mass spectrometry (ESI FT ICR-MS) were used to investigate the organic composition change of produced effluents and crude oil in direct current voltage assisted carbonated water treatment. Through direct current voltage assisted carbonated water-flooding experiments, the following results can be obtained. Firstly, direct current voltage assisted carbonated waterflooding showed greater EOR capacity and CO2 sequestration efficiency than individual carbonated water and direct current voltage treatment. With the increase of direct current voltage, oil recovery increases to 38.67% at 1.6V/cm which much higher than 29.07% of carbonated water-flooding and then decreases, meanwhile, CO2 output decreases to only 35.5% at 1.6V/cm which much lower than 45.6% of carbonated water-flooding and then increases. Secondly, in direct current voltage assisted carbonated water-flooding, the wettability alteration is mainly caused by carbonated water and the effect of direct current can be neglected. While both carbonated water and direct current have evident influence on interfacial properties. Herein, with direct current voltage increasing, the interfacial tension firstly decreases and then increases, the interfacial viscoelasticity initially strengthens and then weakens. Thirdly, GC results indicated that crude oil cracking into lighter components occurs during direct current voltage assisted carbonated water-flooding, with the short-chain organic components increasing and the long-chain components decreasing. Meanwhile, TOC and ESI FT ICR-MS results illustrated that CO2 electroreduction do occur in direct current voltage assisted carbonated water-flooding with the dissolved organic molecules increases and the emergence of formic acid. Conclusively, the synergy of CO2 electrochemical reduction into formic acid in aqueous solution and the long-chain molecules electrostimulation pyrolysis into short ones in crude oil mutually resulted in the enhancement of crude oil-carbonated water interaction. This paper proposed a new EOR & CCS technology-direct current voltage assisted carbonated water-flooding. It showed great research and application potential on tight oil development and greenhouse gas control. More work needs to be done to further explore its mechanism. This paper constructs a multiscale & interdisciplinary research system to study the multidisciplinary (EOR&CCS) problem. Specifically, a series connected physical (Core displacement, Contact angle, and Interfacial tension/rheology measurements) and chemistry (TOC, GS, and ESI FT ICR-MS) experiments are combined to explore its regularity and several physics (Atomic physics) and chemistry (Electrochemistry/Inorganic Chemistry) theories are applied to explain its mechanisms.

Advances in Midland Basin Expand Boundaries of CO2 EOR in Marginal Pay Areas

2021 ◽  
Vol 73 (06) ◽  
pp. 65-66
Author(s):  
Judy Feder
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Improved Oil Recovery ◽  
Midland Basin ◽  
The North ◽  
Production Wells ◽  
Original Oil In Place ◽  
Carbon Dioxide Co2

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200460, “A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance,” by John Kalteyer, SPE, Kinder Morgan, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field’s future. Field Overview and Development History The first six pages of the paper discuss the field’s location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has sur-passed 7 TCF and yielded cumulative EOR of over 180 million bbl. The reservoir is a primarily limestone reef complex containing an estimated original oil in place (OOIP) of just under 3 billion bbl. The reservoir ranges from 200 ft gross thickness in the south to 900 ft in the north, where the limestone matrix averages 8% porosity and 20-md permeability. The Canyon Reef structure is divided into four major intervals, of which the Upper Canyon zone provides the highest-quality pay. The field was discovered in 1948 at a pressure of 3,122 psi. By late 1950, 1,600 production wells had been drilled and the reservoir pressure plummeted, settling as low as 1,700 psi. Waterflooding begun in 1954 enabled the field to continue producing for nearly 20 years, at which time the operators deter-mined that another recovery mechanism would be needed to maximize recovery and reach additional areas of the field. The complete paper discusses various CO2 injection programs that were developed and applied—including a true tertiary response from a miscible CO2 flood in 1981—along with their outcomes. Acquisition and CO2-Injection Redevelopment In June 2000 Kinder Morgan acquired the SACROC Unit and took over as operator. Approximately 6.7 billion bbl of water and 1.3 TCF of CO2 had been injected across the unit to that date, but the daily oil rate of 8,700 B/D was approaching the field’s economic limit. An estimated 40% of the OOIP had been produced through the combination of recovery methods that each previous operator had used. Expanding on the conclusions of its immediate predecessor, the operator initiated large-scale CO2-flood redevelopment in a selection of project areas. These redevelopments were based on several key distinctions differentiating them from previous injection operations.

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

2019 ◽  
Vol 9 (8) ◽  
pp. 1686 ◽  
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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