Reservoirs Tertiary

For example, the many deepwater fields located in the Gulf of Mexico are of Tertiary age and are comprised of complex sand bodies which were deposited in a deepwater turbidite sequence. The BP Prudhoe Bay sandstone reservoir in Alaska is of Triassic/ Cretaceous age and was deposited by a large shallow water fluvial-alluvial fan delta system. The Saudi Arabian Ghawar limestone reservoir is of Jurassic age and was deposited in a warm, shallow marine sea. Although these reservoirs were deposited in very different depositional environments they all contain producible accumulations of hydrocarbons, though the fraction of recoverable oil varies. In fact, these three fields are some of the largest in the world, containing over 12 billion barrels of oil each ... 

Petroleum Recovery. Steam is iajected iato oil wells for tertiary petroleum recovery. Steam pumped iato the partly depleted oil reservoirs through iaput wells decreases the viscosity of cmde oil trapped ia the porous rock of a reservoir, displaces the cmde, and maintains the pressure needed to push the oil toward the production well (see Petroleum, enhanced recovery). Steam is also used ia hot-water extractioa of oil from tar sands (qv) ia the caustic conditioning before the separatioa ia a flotatioa tank (35). 

Oil recovery from underground reservoirs can be improved by injection of water and pressing of oil to the surface. This secondary oil recovery process is relatively cheap though not always successful. Further, however more expensive, methods are the so-called tertiary oil recovery processes whereby the viscosity of the oil is lowered by mixing with low viscous oils or gas, or by temperature increase due to injection of steam, and where the viscosity of the pressing water layer is increased or the surface tension between water and oil is decreased via addition of surfactants. 

Micellar flooding is a promising tertiary oil-recovery method, perhaps the only method that has been shown to be successful in the field for depleted light oil reservoirs. As a tertiary recovery method, the micellar flooding process has desirable features of several chemical methods (e.g., miscible-type displacement) and is less susceptible to some of the drawbacks of chemical methods, such as adsorption. It has been shown that a suitable preflush can considerably curtail the surfactant loss to the rock matrix. In addition, the use of multiple micellar solutions, selected on the basis of phase behavior, can increase oil recovery with respect to the amount of surfactant, in comparison with a single solution. Laboratory tests showed that oil recovery-to-slug volume ratios as high as 15 can be achieved [439]. 

The assessment of surfactant structures and optimal mixtures for potential use in tertiary flooding strategies in North Sea fields has been examined from fundamental investigations using pure oils. The present study furthermore addresses the physico-chemical problems associated with reservoir oils and how the phase performance of these systems may be correlated with model oils, including the use of toluene and cyclohexane in stock tank oils to produce synthetic live reservoir crudes. Any dependence of surfactant molecular structure on the observed phase properties of proposed oils of equivalent alkane carbon number (EACN) would render simulated live oils as unrepresentative. 

The works of various investigators such as Gogarty and Tosch (1), Healy and Reed (2), and Davis and Jones (2), have shown that the micellar flooding process can be used effectively to mobilize residual oil in watered-out light oil reservoirs. Many field tests conducted in the U.S. have further proved its effectiveness. However, the economics of the process remain unattractive for implementing the process for tertiary oil recovery. 

Once the C02 is captured and compressed, it needs to be transported to the sequestration or utilization locations, unless the capture and sequestration processes are located at the same site. A C02 transportation infrastructure could be done with a rather conventional approach. On land, pipelines for long-distance C02 transport already exist. For example, a pipeline system more than 500 mi. long connects C02 fields in Southern Colorado to oil fields in West Texas. The C02 is purchased at about 15/ton for tertiary oil recovery. The cost of C02 transportation is a function of distance, whereas the costs of pipeline construction vary significantly by region (Doctor et al., 1997). The construction and operation of pipelines for ocean would be quite different from land-based pipelines. Generally, C02 is transported at supercritical pressures (-2000 psi). If C02 is sequestered at geological formations, the transferred C02 may require additional compression at the injection site depending on the specifics of the reservoir (Doctor et al., 1997). 

However, these projects and similar projects in Canada demonstrate that the disposal of C02 is practically feasible. Nevertheless, the capacity of tertiary oil and gas recovery is quite limited. Estimates range from 20 to 60 GtC (Holloway, 2001 and IPCC, 2005). The uncertainty of the practice for C02 storage, however, lies in the long-term stability of the reservoirs (Blunt et al., 1993). 

In the tertiary process, more complicated chemical additives are designed for a particle reservoir. In all these recovery processes, the interfacial tension (IFT) between the oil phase and the water phase is needed. 

The reservoir rocks that yield crude oil range in age from Precambrian to Recent geologic time but rocks deposited during the Tertiary, Cretaceous, Permian, Pennsylvanian, Mississippian, Devonian, and Ordovician periods are particularly productive. In contrast, rocks of Jurassic, Triassic, Silurian, and Cambrian age are less productive and rocks of Precambrian age yield petroleum only under exceptional circumstances. 

In primary oil recovery from underground reservoirs, the capillary forces described by the Young and Young-Laplace equations are responsible for retaining much of the oil (residual oil) in parts of the pore structure in the rock or sand. It is these same forces that any secondary or enhanced (tertiary) oil-recovery-process strategies are intended to overcome [2,133,421,690,691]. In an oil-bearing reservoir the relative oil and water saturations depend upon the distribution of pore sizes in the rock. The capillary pressure in a pore is... 

Computerized Tomography (CT) was used to study mobility control with CO2 foam during tertiary horizontal corefloods at reservoir pressures and temperatures. CO2 foam provided effective mobility control under first-contact miscible conditions. However, mobility control was not observed when the pressure was substantially reduced so -that the oil and CO2 were immiscible. If the beneficial effects of foam can be extended to developed-miscibility conditions, CO2 foam will be an outstanding EOR process. 

A fundamental concern in CO2 foam applications is how far foams can be transported at reservoir temperatures and salinities in the presence of crude oil. Oils that spread at gas/brine interfaces are known to have severe debilitating effects on foam stability. Another concern is that surfactants may retard oil droplet coalescence and therefore reduce tertiary oil reconnection and mobilization efficiency. 

Final laboratory testing of CO2 foam was performed in Shell s CT facility (11-12L Tertiary miscible and immiscible CO2 corefloods, with and without foam mobility control, were scanned during flow at reservoir conditions. The cores were horizontally mounted continuous cylinders of Berea sandstone. Table I lists pertinent core and fluid data. 

Recently, use of a surfactant in the injected water such that a foam or emulsion is formed with carbon dioxide has been proposed (20.21) and research is proceeding on finding appropriate surfactants (22-24). The use of such a foam or emulsion offers the possibility of providing mobility control combined with amelioration of the density difference, a combination which should yield improved oil recovery. Laboratory studies at the University of Houston (25) with the same five-spot bead-pack model as used before show that this is so, for both the relatively water-wet and relatively oil-wet condition. We have now simulated, with a finite-difference reservoir process computer program, the laboratory model results under non-WA3, WAG, and foam displacement conditions for both secondary and tertiary recovery processes. This paper presents the results of that work. 

Tertiary oil was increased up to 41% over conventional CO2 recovery by means of mobility control where a carefully selected surfactant structure was used to form an in situ foam. Linear flow oil displacement tests were performed for both miscible and immiscible floods. Mobility control was achieved without detracting from the C02-oil interaction that enhances recovery. Surfactant selection is critical in maximizing performance. Several tests were combined for surfactant screening, included were foam tests, dynamic flow tests through a porous bed pack and oil displacement tests. Ethoxylated aliphatic alcohols, their sulfate derivatives and ethylene oxide - propylene oxide copolymers were the best performers in oil reservoir brines. One sulfonate surfactant also proved to be effective especially in low salinity injection fluid. 

Aagaard P., Egeberg P. K., Saigal G. C., Morad S., and Bj0rlykke K. (1990) Diagenetic albitization of detrital K-feldspars in Jurassic, Lower Cretaceous, and Tertiary clastic reservoir rocks from offshore Norway 11. Formation water chemistry and kinetic considerations. J. Sedim. Petrol. 60, 575-581. 

Loucks R. G., Dodge M. M., and Galloway W. E. (1984) Regional controls on diagenesis and reservoir quality in Lower Tertiary sandstones. In Clastic Diagenesis (eds. D. A. McDonald and R. C. Surdam). American Association of Petroleum Geologists, Tulsa, OK, vol. 37, pp. 15-45. 

McCaffery M. A., Dahl J. E., Sundararaman P., Moldowan J. M., and Schoell M. (1994a) Source rock quality determination from oil biomarkers II. A case study using Tertiary-reservoired Beaufort Sea oils. Am. Assoc. Petrol. Geol. Bull. 78(10), 1527-1540. 

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