The primary physical mechanisms that occur as a result of gas injection are (1) partial or complete maintenance of reservoir pressure, (2) displacement of oil by gas both horizontally and vertically, (3) vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation, and (4) swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas. Gas injection is particularly effective in high-relief reservoirs where the process is called "gravity drainage" because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations. The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available. Nevertheless, a variety of opportunities still exist. First are those reservoirs with characteristics and conditions particularly conducive to gas/oil gravity drainage and where attendant high oil recoveries are possible. Second are those reservoirs where decreased depletion time resulting from lower reservoir oil viscosity and gas saturation in the vicinity of producing wells is more attractive economically than alternative recovery methods that have higher ultimate recovery potential but at higher costs. And third are reservoirs where recovery considerations are augmented by gas storage considerations and hence gas sales may be delayed for several years. Nonhydrocarbon gases such as CO2 and nitrogen can and have been used. In general, calculation techniques developed for hydrocarbon-gas injection and displacement can be used for the design and application of nonhydrocarbon, immiscible gas projects. Valuing the use of such gases must include any additional costs related to these gases, such as corrosion control, separating the nonhydrocarbon components to meet gas marketing specifications, and using the produced gas as fuel in field operations. The conceptual aspects of the displacement of oil by gas in reservoir rocks are discussed in this section. There are three aspects to this displacement: gas and oil viscosities, gas/oil capillary pressure (Pc) and relative permeability (kr) data, and the compositional interaction, or component mass transfer, between the oil and gas phases.
A variety of gases can and have been used for immiscible gas displacement, with lean hydrocarbon gas used for most applications to date. Historically, immiscible gas injection was first used for reservoir pressure maintenance. The first such projects were initiated in the 1930s and used lean hydrocarbon gas (e.g., Oklahoma City field and Cunningham pool in the US and Bahrain field in Bahrain). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance. This page discusses gas injection into oil reservoirs to increase oil recovery by immiscible displacement.
The Haft Kel field is located in Iran. Its Asmari reservoir structure is a strongly folded anticline that is 20 miles long by 1.5 to 3 miles wide with an oil column thickness of approximately 2,000 ft. The matrix block size determined from cores and flowmeter surveys varied from 8 to 14 ft. The numerical simulation model considered matrix permeabilities from 0.05 to 0.8 md. The overall horizontal and vertical permeabilities are approximately equal.
Many aspects of reservoir geology interplay with the immiscible gas/oil displacement process to determine overall recovery efficiency. Because there is always a considerable density difference between gas and oil, the extent to which vertical segregation of the fluids occurs and can be taken advantage of or controlled is critical to the success of gas displacing oil. As with any oil recovery process involving the injection of one fluid to displace oil in the reservoir, the internal geometries of the reservoir interval have a controlling effect on how efficiently the injected fluid displaces the oil from the whole of the reservoir. The stratigraphy of a reservoir is determined primarily by its depositional environment. First and foremost is how layered the reservoir is in terms of both how heterogeneous the various sand intervals are and the scale at which shales or other barriers to vertical flow are interbedded with the sands.
Ghasemi, Mohammad (Petrostreamz) | Astutik, Wynda (Petrostreamz) | Alavian, Sayyed A. (PERA) | Whitson, Curtis H. (PERA and Norwegian University of Science and Technology) | Sigalas, Lykourgos (Geological Survey of Denmark and Greenland) | Olsen, Dan (Geological Survey of Denmark and Greenland) | Suicmez, Vural S, (Maersk Oil & Gas)
This paper presents a novel technique to determine multicomponent diffusion coefficients for carbon dioxide (CO2) injection in a North Sea chalk field (NSCF) in Norway at reservoir conditions. The constant-volume-diffusion (CVD) method is used, consisting of an oil-saturated-chalk core in contact with an overlying free space, which is filled with the CO2. The experimental data are matched with an equation-of-state (EOS) -based compositional model.
Transport by diffusion controls the dynamics of the constant-volume system and, together with phase equilibria, allows a consistent estimation of diffusion coefficients needed to describe the observed changes in system pressure.
We conduct two experiments at reservoir conditions: One uses a core plug saturated with live oil and the other with stock-tank oil (STO). Once the experiments are completed, EOS-based compositional simulation is performed to match the experimental data by use of the oil- and gas-diffusion coefficients as history-matching parameters. The modeling work is conducted with a commercial reservoir simulator by use of a 2D radial-grid model to describe the experimental setup.
The experiment uses an outcrop chalk core mounted in a vertically oriented core holder. The chalk is shorter than the core holder, thus resulting in an overlying void space. The system is initially saturated with oil at reservoir conditions. CO2 is then injected from the top, forming an overlying CO2 chamber and displacing oil toward the bottom of the core holder. Once CO2 fills the overlying bulk space, the system is isolated with no further injection or production.
The CO2 and oil reach and remain in equilibrium locally at the gas/oil interface throughout the test, beginning and maintaining the diffusion mechanism. Diffusion of CO2 into the oil results in a decreasing pressure, which is the main history-matching parameter.
The multicomponent diffusion coefficients are found to match the model pressure/time prediction to the experimental data. This suggests the modeling work flow incorporates a representative EOS model and the main transport dynamics controlled by diffusion are being treated properly.
Proper simulation of CO2 injection in fractured-chalk reservoirs requires the ability to model multicomponent diffusion accurately. The proposed CVD method provides such modeling capabilities. Our modeling and experimental work indicate the novelty of the CVD method to determine the diffusion coefficients of a system where diffusion is the dominant displacement mechanism. The fact that the oil is contained within a low-permeability-chalk sample reduces density-driven convection that could result because of nonmonotonic oil-density changes as CO2 dissolves into the oil.
Mohsenzadeh, A. (Shiraz University) | Escrochi, M. (Shiraz University) | Afraz, M.V. (Shiraz University) | Ayatollahi, Sh. (shiraz university) | karimi, Gh. (shiraz university) | Al-wahaibi, Y. (Sultan Qaboos University)
Considerable heavy oil is accumulated in naturally fractured carbonate reservoirs, with very low oil recovery efficiency through costly production techniques. In this experimental study, the effects of different injecting gases on the performance
of immiscible gas injection and the GOGD process have been investigated at reservoir conditions from full sized carbonate cores in a long fractured laboratory model. During this study on heavy crude oil, three different gases: pure CO2, pure N2, and their mixture as synthetic flue gas injection; were used to study the performance of isothermal GOGD process. It was found that the oil recovery before gas breakthrough was mostly from the fracture; however the injected gas mostly affected the amount of oil recovery and its rate from the matrix part. The piston wise displacement during N2 injection and oil swelling during CO2 injection were found to be the most important mechanisms affecting the oil recovery performance before gas breakthrough. On the other hand, It was found that the oil recovery efficiency for CO2 injection after gas breakthrough was mainly due to gas dissolution mechanism and for N2 injection it was because of high oil-gas density difference; both resulted in approximately 14% recovery efficiency of the remained OIP. However, flue gas injection activated both mechanisms simultaneously with their adverse effects and the recovery efficiency decreased to approximately 10% of the remained OIP. It was also concluded that the GOGD mechanism needs to be stimulated by other compatible techniques such as thermal methods, to increase heavy oil recovery from the matrixes of the fractured formations.
In this study, gas-oil gravity drainage process and steam-gas assisted gravity drainage processes for heavy oil recovery from fractured models were investigated experimentally. For each test, six oil- wet saturated outcrop cores, 8.7 cm in diameter and 15 cm length, were stacked in a long core holder. In the first step, gas injection was started into the model at reservoir condition that results in oil production under gas-oil gravity drainage mechanism. In the second round of tests when no more oil was produced by gas injection, the tests were continued using steam-gas assisted gravity drainage process. In this stage, gas was injected together with specific steam/gas ratio at saturated temperature condition. In the course of experiments, oil and water productions, pressure and temperatures of system were monitored carefully. The experiments were performed using three different combination of gases consist of pure CO2, pure N2 and mixture of 15 % CO2 and 85% N2 as synthetic flue gas. The results showed that after gas breakthrough and fracture depletion, the ultimate oil recovery for CO2 injection was 58.4 % (14.8% for gas injection and 43.6 % for steam-gas co-injection), in the case of flue gas injection, it was 73.8 % (9.8 % for gas injection and 64% for steam-gas co-injection) and for N2 injection was 47% (13.5 % for gas injection and 33.5% for steam-gas co-injection). The results indicate the high performance of flue gas injection for heavy oil recovery from fractured reservoirs during gas-oil gravity drainage and steam-gas assisted gravity drainage processes.
In this study, different scenarios of CO2 injection in dipping gas condensate and oil reservoirs are investigated through reservoir simulations. Both miscible and immiscible flooding conditions were investigated for a range of different injection gas mixtures, and geological realizations.
We find particularly interesting results for miscible flooding of gas condensate systems below dewpoint pressure. Here, dropped out condensate is the prime target for enhanced recovery projects and multi-contact miscibility could develop through the combined condensing/vaporizing mechanism.
Different patterns of permeability variation with depth in layering scenarios with dip angle showed distinct different responses on produced condensate. CO2 WAG in partially depleted gas condensate reservoirs seems to have the same value of oil recovery in early times, but ultimate recovery is different according to layering heterogeneity. In the case of pure CO2 injection, both up-dip and down-dip, it was found that homogeneous layering showed highest recovery. Here developed multicontact miscible oil-bank is able to move and sweep condensate above it easier. Applying various gas injection mixtures of CO2 and C1 combinations, the effect on ultimate recovery were studied. In this case CO2 injection is above minimum miscibility pressure (MMP) resulting in high recoveries.
CO2 WAG in dipping oil reservoir was also studied extensively, based on injection pattern, MMP values and various layering systems. CO2 WAG in scenarios with increasingly trend of permeability with depth had the highest value of recovery. This is because of prevention from early gas breakthrough in upper layers and good sweep efficiency in lower layers. Pure CO2 injection with total same injection volume showed lower recovery. This may verify that gravity in WAG water injection period is the most effective parameter in the case of down-dip WAG.