scholarly journals Enhanced Gas and Condensate Recovery: Review of Published Pilot and Commercial Projects

Nafta-Gaz ◽  
2021 ◽  
Vol 77 (1) ◽  
pp. 20-25
Author(s):  
Oleksandr Burachok ◽  
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Early Stage ◽  
Gas Condensate ◽  
Dew Point ◽  
Commercial Application ◽  
Hydrocarbon Production ◽  
Carbon Footprints ◽  
Stage Of Development ◽  
Reservoir Conditions

The majority of the Ukrainian gas condensate fields are in the final stage of development. The high level of reservoir energy depletion has caused significant in situ losses of condensed hydrocarbons. Improving and increasing hydrocarbon production is of great importance to the energy independence of Ukraine. In this paper, a review of the pilot and commercial enhanced gas and condensate recovery (EGR) projects was performed, based on published papers and literature sources, in order to identify those projects which could potentially be applied to the reservoir conditions of Ukrainian gas condensate fields. The EGR methods included the injection of dry gas (methane), hydrocarbon solvents (gas enriched with C2–C4 components), or nitrogen and carbon dioxide. The most commonly used and proven method is dry gas injection, which can be applied at any stage of the field’s development. Dry gas and intra-well cycling was done on five Ukrainian reservoirs, but because of the need to block significant volumes of sales gas they are not being considered for commercial application. Nitrogen has a number of significant advantages, but the fact that it increases the dew point pressure makes it applicable only at the early stage, when the reservoir pressure is above or near the dew point. Carbon dioxide is actively used for enhanced oil recovery (EOR) or for geological storage in depleted gas reservoirs. In light of the growing need to reduce carbon footprints, CO2 capture and sequestration is becoming very favourable, especially due to the low multi-contact miscibility pressure, the high density under reservoir conditions, and the good miscibility with formation water. All of these factors make it a good candidate for depleted gas condensate reservoirs.

scholarly journals Aspects of protection against carbon dioxide corrosion of gas production facilities

2019 ◽  
Vol 121 ◽  
pp. 02013 ◽  
Author(s):  
Dmitry Zapevalov ◽  
Ruslan Vagapov
Keyword(s):  
Carbon Dioxide ◽  
Gas Production ◽  
Gas Condensate ◽  
Safe Operation ◽  
Hydrocarbon Production ◽  
Stage Of Development ◽  
The Media ◽  
Technical Solutions ◽  
Intensive Development ◽  
Production Facilities

The modern stage of development of many onshore and offshore gas and gas condensate fields is associated with objects in which carbon dioxide (CO2) gas is present in the production. The presence of CO2 in the produced gas in combination with other factors stimulates the intensive development of corrosion processes, which requires careful and reasonable attitude both to assess the degree of aggressiveness of the media and to choose technical solutions to ensure reliable and safe operation of hydrocarbon production facilities. The authors analyzed the existing approaches to the assessment of the danger of corrosion produced media, selection and implementation of protection against corrosion in the presence in them of aggressive CO2.

Enhancing Hydrocarbon Production Through Thermal Gas Injection from a Retrograde as Condensate Reservoir in the Western Desert in Egypt

2021 ◽  
Author(s):  
Maged Alaa Taha ◽  
Eissa Shokier ◽  
Attia Attia ◽  
Aamer Yahia ◽  
Khaled Mansour
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Gas Injection ◽  
Gas Production ◽  
Gas Condensate ◽  
Dew Point ◽  
Western Desert ◽  
Co2 Injection ◽  
Hydrocarbon Production ◽  
Gas Condensate Reservoirs

Abstract In retrograde gas condensate reservoirs, condensate blockage is a major reservoir damage problem, where liquid is dropped-out of natural gas, below dew-point pressure. Despite that most of this liquid will not produce due to not reaching the critical saturation, natural gas will be blocked by the accumulated liquid and will also not produce. This work investigates the effects of gas injection (such as methane, carbon-dioxide, and nitrogen) and steam at high temperatures on one of the Egyptian retrograde gas condensate reservoirs. Several gas injection scenarios that comprise different combination of gas injection temperature, enthalpy, injection gas types (CO2, N2, and CH4), and injection-rates were carried out. The results indicated that all conventional and thermal gas injection scenarios do not increase the cumulative gas production more than the depletion case. The non-thermal gas injection scenarios increased the cumulative condensate production by 8.6%. However, thermal CO2 injection increased the condensate production cumulative by 28.9%. It was observed that thermal gas injection does not vaporize condensate It was observed that thermal gas injection does not vaporize condensate more than conventional injection that have the same reservoir pressure trend. However, thermal injection mainly improves the condensate mobility. Appropriately, thermal injection in retrograde reservoirs, is mostly applicable for depleted reservoirs when the largest amount of non-producible liquid is already dropped out. Finally, this research studied executing thermal gas injection in retrograde gas condensate reservoirs, operationally, by considering the following items: carbon dioxide recovery unit, compressors, storage-tanks, anti-corrosion pipe-lines and tubing-strings, and corrosion-inhibitors along with downhole gas heaters.

Self-gasified biosystems for enhanced oil recovery

2021 ◽  
pp. 2150274
Author(s):  
B. A. Suleimanov ◽  
S. J. Rzayeva ◽  
U. T. Akhmedova
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Experimental Studies ◽  
Microbial Enhanced Oil Recovery ◽  
Heterogeneous Porous Medium ◽  
Oil Displacement ◽  
Subcritical Region ◽  
Reservoir Conditions

Microbial enhanced oil recovery is considered to be one of the most promising methods of stimulating formation, contributing to a higher level of oil production from long-term fields. The injection of bioreagents into a reservoir results in the creation of oil-displacing agents along with a significant amount of gases, mainly carbon dioxide. Earlier, the authors failed to study the preparation of self-gasified biosystems and the implementation of the subcritical region (SR) under reservoir conditions. Gasified systems in the subcritical phase have better oil-displacing properties than nongasified systems. In a heterogeneous porous medium, the filtration profile of gasified liquids in the SR should be more uniform than for a degassed liquid. Based on experimental studies, the superior efficiency of oil displacement by gasified biosystems compared with degassed ones has been demonstrated. The possibility of efficient use of gasified hybrid biopolymer systems has been shown.

The Effect of Phase Equilibria on the CO2 Displacement Mechanism

1979 ◽  
Vol 19 (04) ◽  
pp. 242-252 ◽  
Author(s):  
R.S. Metcalfe ◽  
Lyman Yarborough
Keyword(s):  
Carbon Dioxide ◽  
Phase Equilibria ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Miscible Displacement ◽  
Co2 Flooding ◽  
Recovery Method ◽  
Two Fluids ◽  
Reservoir Conditions

Abstract Carbon dioxide flooding under miscible conditions is being developed as a major process for enhanced oil recovery. This paper presents results of research studies to increase our understanding of the multiple-contact miscible displacement mechanism for CO2 flooding. Carbon dioxide displacements of three synthetic oils of increasing complexity (increasing number of hydrocarbon components) are described. The paper concentrates on results of laboratory flow studies, but uses results of phase-equilibria and numerical studies to support the conclusions.Results from studies with synthetic oils show that at least two multiple-contact miscible mechanisms, vaporization and condensation, can be identified and that the phase-equilibria data can be used as a basis for describing the mechanism. The phase-equilibria change with varying reservoir conditions, and the flow studies show that the miscible mechanism depends on the phase-equilibria behavior. Qualitative predictions with mathematical models support our conclusions.Phase-equilibria data with naturally occurring oils suggest the two mechanisms (vaporization and condensation) are relevant to CO2 displacements at reservoir conditions and are a basis for specifying the controlling mechanisms. Introduction Miscible-displacement processes, which rely on multiple contacts of injected gas and reservoir oil to develop an in-situ solvent, generally have been recognized by the petroleum industry as an important enhanced oil-recovery method. More recently, CO2 flooding has advanced to the position (in the U.S.) of being the most economically attractive of the multiple-contact miscibility (MCM) processes. Several projects have been or are currently being conducted either to study or use CO2 as an enhanced oil-recovery method. It has been demonstrated convincingly by Holm and others that CO2 can recover oil from laboratory systems and therefore from the swept zone of petroleum reservoirs using miscible displacement. However, several contradictions seem to exist in published results.. These authors attempt to establish the mechanism(s) through which CO2 and oil form a miscible solvent in situ. (The solvent thus produced is capable of performing as though the two fluids were miscible when performing as though the two fluids were miscible when injected.) In addition, little experimental work has been published to provide support for the mechanisms of multiple-contact miscibility, as originally discussed by Hutchinson and Braun.One can reasonably assume that the miscible CO2 process will be related directly to phase equilibria process will be related directly to phase equilibria because it involves intimate contact of gases and liquids. However, no data have been published to indicate that the mechanism for miscibility development may differ for varying phase-equilibria conditions.This paper presents the results of both flow and phase-equilibria studies performed to determine the phase-equilibria studies performed to determine the mechanism(s) of CO2 multiple-contact miscibility. These flow studies used CO2 to displace three multicomponent hydrocarbon mixtures under first-contact miscible, multiple-contact miscible, and immiscible conditions. Results are presented to support the vaporization mechanism as described by Hutchinson and Braun, and also to show that more than one mechanism is possible with CO2 displacements. The reason for the latter is found in the results of phase-equilibria studies. SPEJ P. 242

scholarly journals Laboratory Results of the Influence of Carbon Dioxide on the Development of the Permo-Carboniferous Reservoir of the Usinskoe Deposit

2021 ◽  
Vol 21 (1) ◽  
pp. 28-35
Author(s):  
Stanislav A. Stanislav A. ◽  
◽  
Oleg A. Morozyuk ◽  
Konstantin S. Kosterin ◽  
Semyon P. Podoinitsyn ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Co2 Concentration ◽  
High Viscosity ◽  
Co2 Injection ◽  
Oil Displacement ◽  
Displacement Mode ◽  
Use Of Technology ◽  
Reservoir Conditions ◽  
High Viscosity Oil

As an option for enhancing oil recovery of a high-viscosity Permo-Carboniferous reservoir associated with the Usinskoye field, the use of technology based on technogenic carbon dioxide as an injection agent is considered. In the world practice, several fields are known as close in their parameters to the parameters of the Permo-Carboniferous reservoir, and in which CO2 injection was accepted as successful. Based on this, CO2 injection can potentially be applicable in the conditions of a Permo-Carboniferous reservoir. At present, as a result of the various development technologies implementation, reservoir zones are distinguished, characterized by different thermobaric properties. Depending on reservoir conditions, when displacing oil with gases, various modes of oil displacement can be realized. This article describes the results of studies carried out to study the effect of the concentration of carbon dioxide on the properties of high-viscosity oil in the Permo-Carboniferous Reservoir of the Usinskoye field, as well as the results of filtration experiments on slim models performed to assess the oil displacement regime under various temperature and pressure conditions of the Permo-Carboniferous Reservoir. The study of the influence of CO2 concentration on oil properties was carried out using the standard PVT research technique. The displacement mode was assessed using the slim-tube technique. Based on the performed experiments, it was established that an increase in the concentration of CO2 in high-viscosity oil led to a noticeable change in its properties; for the conditions of a Permo-Carboniferous Reservoir, the most probable mode of oil displacement by carbon dioxide was established. Difficulties associated with the preparation of the CO2-heavy oil system were described separately. Based on a literature review, it was shown that the rate of mixing of oil with carbon dioxide depended on certain conditions.

scholarly journals THE USE OF OIL-SOLUBLE POLYMERS TO ENHANCE OIL RECOVERY IN HARD TO RECOVER HYDROCARBONS RESERVES

2021 ◽  
Author(s):  
Sudad H Al-Obaidi ◽  
Patkin AA ◽  
Chang WJ
Keyword(s):  
Oil Recovery ◽  
Early Stage ◽  
New Technology ◽  
Salt Content ◽  
Water Soluble ◽  
Heterogeneous Structure ◽  
Water Soluble Polymers ◽  
Soluble Polymers ◽  
Stage Of Development ◽  
Effective Development

Currently, the share of new fields in many places over the world, which are at the initial stage of development, is constantly growing.Fields often have a complex heterogeneous structure with hard-to-recover reserves, therefore, for their effective development, it is necessary to use completely new approaches, including improving existing methodsof enhanced oil recovery.In this work, experimental verification of a new technology using oil-soluble polymers and comparing it with technology based on the use of water-soluble polymers has been performed. In laboratory conditions, a newtechnology for polymer flooding at an early stage of development using oil-soluble polymers was developed and experimentally confirmed. The new technology has made it possible to increase the degree of reservesrecovery by an average of 30% compared to existing methods of enhanced oil recovery and to solve a number of problems arising from the use of water-soluble polymers. Such problems are the freezing of aqueouspolymer solutions in winter and the poor solubility of polymers in formation waters with a high salt content. The use of new technology can also reduce energy costs by 25%.

scholarly journals Assessment of CO2 flooding as enhanced oil recovery

2021 ◽  
Vol 340 ◽  
pp. 01021
Author(s):  
Akhat Makhambetov ◽  
Nursultan Azilkhanov
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Oil Fields ◽  
Co2 Flooding ◽  
Carbon Dioxide Injection ◽  
Recovery Method ◽  
Stage Of Development ◽  
Temperature And Pressure

This article discusses evaluating CO2 injection as an enhanced oil recovery method. Carbon dioxide injection is a secondary and tertiary enhanced oil recovery method and is used in the final stage of development. Carbon dioxide mixes well with oil and can dissolve heavy components. Also, CO2 maintains reservoir pressure, which prevents the flow rate from dropping. In order for carbon dioxide and oil to mix, it must be brought to a critical state by increasing the temperature and pressure. After reaching the required conditions, both substances are fully compatible. The result of this combination is a medium that can easily seep through a porous medium. In fact, gas injection would be appropriate to use in a carbonate reservoir, and in our country and all over the world there are many oil fields that are located in carbonate rock. This work is based on data on a field located in the Krasnoyarsk region, which is part of the Angara fold zones. The field itself is represented mainly by carbonate reservoirs. Also, application of this method for Kazakhstan oilfield will be considered, using an example Zhetybay oilfield.

Predicting development parameters for gas-condensate deposits with oil banks in the exploitation of horizontal wells

2020 ◽  
pp. 19-24
Author(s):  
M.S. Khalilov ◽  
Keyword(s):  
Oil Recovery ◽  
Horizontal Wells ◽  
Gas Condensate ◽  
Technological Parameters ◽  
Well Production ◽  
Oil Displacement ◽  
Stage Of Development ◽  
Three Phase ◽  
Displacement Regime ◽  
Filtration Model

The paper presents comparative analysis of technological parameters of depletion and water-oil displacement modes during the exploitation of oil banks in gas-condensate deposit with horizontal well in gas-free production rates based on the three-phase multi-component filtration model. In water-oil displacement regime the oil recovery factors were higher compared to the depletion mode. The development profitability was justified. The increase of oil recovery factor in water-oil displacement regime is achieved due to the weak rate of flooding in well production and unrecoverable capacity of the fluid injected into the reservoir. The practicability of oil banks exploitation in gas-condensate deposit in gas-free rates at the first stage of development in depletion and in water-oil displacement modes at further stage correspondingly is justified.

Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-Ins and Surfactant Additives

SPE Journal ◽  
2017 ◽  
Vol 22 (04) ◽  
pp. 1011-1023 ◽  
Author(s):  
Tianbo Liang ◽  
Rafael A. Longoria ◽  
Jun Lu ◽  
Quoc P. Nguyen ◽  
David A. DiCarlo
Keyword(s):  
Experimental Investigation ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Fluid Loss ◽  
Permeability Reduction ◽  
Fracturing Fluid ◽  
Hydrocarbon Production ◽  
The Matrix ◽  
Reservoir Conditions ◽  
Tight Reservoirs

Summary Fracturing-fluid loss into the formation can potentially damage hydrocarbon production in shale or other tight reservoirs. Well shut-ins are commonly used in the field to dissipate the lost water into the matrix near fracture faces. Borrowing from ideas in chemical enhanced oil recovery (CEOR), surfactants have potential to reduce the effect of fracturing-fluid loss on hydrocarbon permeability in the matrix. Unconventional tight reservoirs can differ significantly from one another, which could make the use of these techniques effective in some cases but not in others. We present an experimental investigation dependent on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically fractured reservoirs. We compare the benefits of shut-ins and reduction in interfacial tension (IFT) by surfactants for hydrocarbon permeability for different initial reservoir conditions (IRCs). From this work, we identify the mechanism responsible for the permeability reduction in the matrix, and we suggest criteria that can be used to optimize fracturing-fluid additives and/or manage flowback operations to enhance hydrocarbon production from unconventional tight reservoirs.

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