Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract A new analytical model for the tertiary miscible CO2-WAG is developed. The model is based on analytical solutions of non-self-similar and self-similar problems for a system of hyperbolic equations of mass conservation laws. Explicit formulae allow to analyze the propagation of displacement and phase transition fronts, mechanisms of trapping of oil with the sequential injection of water and gas slugs, mobility ratios on shock fronts and the dynamics of water and gas slugs. Six different regimes for gas-water injection, after waterflooding, have been distinguished depending on the water-gas ratio, They differ from each other by the structure of the mixture zone and by the mechanisms of displacement caused by two-phase displacement and phase transitions phenomena. The analytical model presented shows that the higher the WGR the lower the recovery, but the more favourable is the mobility ratio on the displacement front, which suggest the existence of an optimal water-gas ratio (WGR) for the tertiary miscible WAG. As it follows from the analytical model there does exist a minimum slug size which prevents gas breakthrough via all the water slugs. With the injection of thinner slugs a connected gas network appears in the reservoir and it catches the front of water creating an unstable gas-oil front at the presence of the connate water only. So, simultaneous injection of gas and water, which corresponds to the reduction of slug size to the zero limit, is not an optimal WAG regime as it was suggested in the literature. On the other hand, the thinner the slugs the higher the displacement efficiency, which suggest the existence of an optimal slug size with the tertiary miscible WAG. Introduction Tertiary miscible gas injection after waterflooding is an effective method of improved oil recovery. The mechanism of an additional recovery is the dissolution of the low mobility residual oil in the gas injected. Nevertheless, the injected gas has a high mobility, compared to the water one, and this leads to unstable displacement because the injected gas moves mainly in highly permeable zones resulting in low areal sweep efficiency. Due to the lower mobility of water, when compared with oil mobility, the injected gas cannot displace oil from the low permeable zones which have not been swept during the waterflooding. The displaced oil forms a high viscosity bank in front of the injected gas improving sweep, but not significantly. Also, some residual oil in the gas swept zone remains unrecovered due to the blocking by water during the primary flood, this water is not removable by the gas injected. Injection of water during the tertiary gas flood decreases the mobility of the injected fluid. So, the displacement from the water-swept zones is occurs with a higher sweep coefficient when compared with the tertiary gas flooding. At some water-gas ratio the mobility of the gas-water system is even higher than the water mobility, so the injected fluid enters in some zones which that were not swept during the waterflooding. The local redistribution of the reservoir pressure near to water and gas slugs, which happen due to the different viscosities for water and gas, also results in some improvement of the sweep efficiency. The effect of the increased sweep efficiency caused by the use of water during the gas flooding has been observed in a number of laboratory simulation studies and in pilot tests. The physical mechanisms of the incremental recovery using miscible WAG can be captured by a 1-D model that takes into account interaction between water and gas slugs during the sequential injection, phase transitions and effects of phase compositions on relative permeabilities and phase viscosities. This model, however, does not take into account areal heterogeneity and viscous fingering. P. 575
- Europe (1.00)
- North America > United States > Oklahoma (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.74)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (9 more...)
Abstract This paper presents an extended evaluation of the results of natural gas huff 'n' puff field tests performed in a light oil reservoir in Brazil (in Miranga field, state of Bahia). Both advantages and disadvantages of natural gas and CO2 cyclic injection are compared. The wells submitted to the process presented increase in the oil production in spite of those operational limitations. The cost of the process is vary low, what encourages its application to a larger number of wells in the same field and in other ones. Some of the reasons to low costs are due to sake good use of the available gas lift facilities and the injected gas recovery during production. The process can be applied to in substitution to CO2 cyclic injection with great advantages such as: lower corrosion levels, no contamination of the produced fluids, recovery of the injected gas and lower project costs. The use of natural gas in substitution to CO2 is very attractive because brings the opportunity of spreading out the application of the process to a larger number of projects than before. Introduction In literature there are many cases histories about succeeded in cyclic CO2 injection, Cyclic CO2 injection succeeded in heavy oil reservoirs 1 as such as in light oil recovery. The sean oil recovery increment has been between 2.8 and 5.6 cubic meters of oil for each a thousand cubic meters of injected CO2. It is a general assent that the quantity of injected CO2 is the more influential factor on oil production. The more the former, more the later. An analysis of Miranga field reservoirs has shown CO2 injection as one of the applicable methods for oil recovery increase. But, in order to get that, there would be a series of difficulties to be dissolved, among them the following:where to obtain CO2 to be injected in Miranga without endangering other projects that are using or will use it In what manner would CO2 be brought as far as Miranga. By carbodute or by truck? In what manner would other reservoirs contamination with injected CO2 and field production be avoided? How to maintain corrosion rate level controlled after CO2 appearance in surface and bottomhole equipments? In what manner to treat produced gases to diminish environmental impact given rise to CO2 production? And many other questions that would at least imply in additional investment needs, that would result in cost increase of the project. For avoiding the majority of the problems due to continuous CO2 injection, cyclic CO2 injection was chosen to be applied in some wells. According to the results cyclic CO2 injection would be extended to a larger number of wells. To avoid problems related to corrosion due to carbonic act formation, low water-oil wells were chosen. To make sure low risk of production loss, low production wells were chosen to be cycled.
- South America > Brazil > Bahia (0.44)
- North America > United States > California (0.29)
- North America > United States > Texas (0.28)
- North America > United States > Kansas > Cowley County (0.24)
Abstract A numerical compositional simulation based reservoir engineering study has been made of alternative recovery processes for the Santa Barbara field, El Tejero-Bosque area. The Santa Barbara field reservoir is comprised of two productive zones, the Naricual and the Cretaceous, totaling about 2,500 feet of thickness. The reservoir is estimated to have originally contained 4.6 billion barrels of stock-tank liquids in the form of condensate in the gas zone and black oil in the oil zone, and 20.5 trillion scf of gas. This paper describes the results of a mechanistic study, designed, to examine the physical mechanisms that govern fluid behavior, transport and production in the reservoir. The study utilized numerical models of two prototype regions, of the reservoir, representing different reservoir characteristics. The process investigated include straight depletion, pressure maintenance at 8000 psi and 6000 psi by injection of either inlet (separator) or outlet (dry) gas from the local cryogenic gas plant, re-injection of separator gas produced, and water injection into the oil column. Also were investigated the effects of completing the wells, above or below the gas oil transition zone. The hydrocarbon fluid column at Santa Barbara is highly unusual, characterized by a variation in composition with depth, being an undersaturated rich gas at the top and an undersaturated oil at the bottom, both separated by a transition zone. It was determined that condensate recovery is highly sensitive to reservoir pressure performance, and independent of the composition of the gas injected. Best recoveries were obtained with injection of dry gas at high pressure. INTRODUCTION A numerical simulation based reservoir engineering study has been made of alternative recovery processes for the Santa Barbara field, El Tejero Bosque area, (El Tejero), located in the Norte de Monagas region of eastern Venezuela. The study integrated the efforts of geophysics, geology, petrophysics and reservoir engineering, first for the construction of numerical models of prototype regions of the reservoir, then, using these models, for the prediction of recovery performance at El Tejero for alternative operating conditions.
- South America > Venezuela > Monagas (1.00)
- North America > United States > Texas > Archer County (1.00)
- North America > United States > California > Santa Barbara County (1.00)
- (3 more...)
- South America > Venezuela > Monagas > Eastern Venezuela Basin > Maturin Basin > Santa Barbara Field (0.99)
- South America > Venezuela > Monagas > Eastern Venezuela Basin > Bosque Field (0.99)
- South America > Venezuela > Eastern Venezuela Basin > Furrial Field (0.98)
Abstract This study examines the necessity of pressure maintenance by immiscible gas injection into solution gas naturally fractured reservoirs. Gas injection is shown to be a controlling factor to minimize resaturation of down structure matrix blocks. Spatial variability in matrix properties influences the overall recovery. Realization of recovery optimization amid spatial variability is illustrated for some idealized reservoir structures. Introduction Number of studies have been published on understanding the solution gas drive process and immiscible gas injection in homogeneous reservoirs. Transferring such technology to heterogenous reservoirs requires two additional levels of understanding. First is the spatial heterogeneity of matrix blocks and second is the interporosity flow characteristics among flow units of significant permeability contrast. An important class of. heterogenous reservoirs is the one that contains natural fractures. Depending on the nature of stress field acting on the initial sediments, fractures may extend across permeability fields regardless of the stratgraphical conditions, further complicating the flow geometry. Because of prevalent control of fracture flow on hydraulic conductivity, the role of the rock matrix becomes more of pressure support nature than an effective flow units. Fracture flow units are thus, in communication with several units of variable conductivities. The low conductivity of the matrix support units may be in part attributed to the nature of sedimentation. post depositional compaction and cementation material. Such loss in conductivity can also be caused by fracture skin, Figure 1. Fracture skin in the form of precipitation of minerals can adversely hinder the interporosity flow from matrix blocks into the fractures. In brief, in solution gas drive reservoirs, there are essentially two sets of parameters which control the recovery factor. First are the reservoir fluid related properties including density, composition, pressure and temperature. Second are the reservoir rock related properties such as rock permeability, porosity, capillary pressure and critical gIs saturation. In heterogenous reservoirs and in particular in naturally fractured reservoir, as indicated earlier, the spatial variation of rock properties are also an important factor which need to be taken into consideration. Beyond the primary recovery process, when pressure maintenance by immiscible gas injection is under consideration certain process related phenomena must be examined including gravity and capillary effects for the fractured systems. Mechanisms of capillary de-saturation / re-saturation commonly referred to reinfiltration can exist with considerable impact on the overall recovery. A complete model of gas injection into fractured systems should also include the mass transfer due to convection and diffusion. For the purpose of this study, the focus is spatial variation of certain rock properties to high-light the rock related mechanisms. As such, compositional fluid effects are not included.