Oil field reservoirs

Dranfield, P., Begg, S.H. Carter, R.R. (1987) Wytch Farm oil-field reservoir characterisation of the Triassic Sherwood Sandstone for input into reservoir simulation studies. In Petroleum Geology of North-West Europe (Eds Brooks, J. Glennie, K.W.), pp. 149-160. Graham Trotman, London. 

The pores between the rock components, e.g. the sand grains in a sandstone reservoir, will initially be filled with the pore water. The migrating hydrocarbons will displace the water and thus gradually fill the reservoir. For a reservoir to be effective, the pores need to be in communication to allow migration, and also need to allow flow towards the borehole once a well is drilled into the structure. The pore space is referred to as porosity in oil field terms. Permeability measures the ability of a rock to allow fluid flow through its pore system. A reservoir rock which has some porosity but too low a permeability to allow fluid flow is termed tight . 

The dissolution of carbonates can create spectacular features like those found in many caves. The process is termed karstification. Some reservoirs are related to Karst. Examples are the Bohai Bay Field in China or the Nang Nuan oil field in the Gulf of Thailand. These reservoirs are characterised by high initial production from the large open pore system. However, since the Karst features are connected downdip to the waterleg this is usually followed by rapid and substantial water breakthrough. ... 

One of the major differences in fluid flow behaviour for gas fields compared to oil fields is the mobility difference between gas and oil or water. Recall the that mobility is an indicator of how fast fluid will flow through the reservoir, and is defined as... 

When petroleum occurs in a reservoir that allows the cmde material to be recovered by pumping operations as a free-flowing dark-to-light colored hquid, it is often referred to as conventional petroleum. In some oil fields, the downhole pressure is sufficient for recovery without the need for pumping. Heavy oil differs from conventional petroleum in that its flow properties are reduced and it is much more difficult to recover from the subsurface reservoir. These materials have a much higher viscosity and lower API (American Petroleum Institute) gravity than conventional petroleum, and primary recovery of these petroleum types usually requires thermal stimulation of the reservoir. 

To date (ca 1997), steam methods have been appHed almost exclusively in relatively thick reservoirs containing viscous cmde oils. In the case of heavy oil fields and tar sand deposits, the cycHc steam injection technique has been employed with some success. The technique involves the injection of steam at greater than fracturing pressure, usually in the 10.3—11.0 MPa (1500—1600 psi) range, foUowed by a soak period, after which production is commenced (15). 

Chlorine. Nearly all chlorine compounds are readily soluble in water. As a result, the major reservoir for this element in Figure 1 is the ocean (5). Chloride, as noted earHer, is naturally present at low levels in rain and snow, especially over and near the oceans. Widespread increases in chloride concentration in mnoff in much of the United States can be attributed to the extensive use of sodium chloride and calcium chloride for deicing of streets and highways. Ref. 19 points out the importance of the increased use of deicing salt as a cause of increased chloride concentrations in streams of the northeastern United States and the role of this factor in the chloride trends in Lake Ontario. Increases in chloride concentration also can occur as a result of disposal of sewage, oil field brines, and various kinds of industrial waste. Thus, chloride concentration trends also can be considered as an index of the alternation of streamwater chemistry by human development in the industrialized sections of the world. Although chlorine is an essential element for animal nutrition, it is of less importance for other life forms. 

Another EOR approach to reducing the viscosity of oil in the reservoir is ntiscible flooding— the injection of fluids that mix with the oil under reservoir conditions. Such fluids include carbon dioxide, light hydrocarbons, and ititrogen. Supply and cost of carbon dioxide are often more favorable than for other injectants. Extensive research and field testing have established the techiucal viability of miscible flooding, and a nnmber of commercial carbon dioxide miscible flooding projects are in operation. 

Adamantane and other diamondoids are constituents of petroleum, gas condensate (also called NGL or natural gas liquid), and natural gas reservoirs [52-56]. Adamantane was originally discovered [40] and isolated from petroleum fractions of the Hodonin oil fields in Czechoslovakia in 1933. 

Conventional polymer and phosphonate scale inhibitors may not be appropriate for application in high-pressure and high-temperature reservoirs. Only a limited range of commercially available oil field scale inhibitor chemicals are sufficiently thermally stable at temperatures above 150° C. These chemicals are homopolymers of vinyl sulfonate and copolymers of acrylic acid... 

Among the bacteria that can inhabit an oil reservoir are the sulfur bacteria that use sulfur compounds in their metabolism. These bacteria produce hydrogen sulhde, which has been responsible for extensive corrosion in the oil field. Thus exclusion of these bacteria from MEOR is highly desirable. The net effect of souring a reservoir is a decrease in the economic value of the reservoir [1835]. 

Oil-field chemistry has undergone major changes since the publication of earlier books on this subject Enhanced oil recovery research has shifted from processes in which surfactants and polymers are the primary promoters of increased oil production to processes in which surfactants are additives to improve the incremental oil recovery provided by steam and miscible gas injection fluids. Improved and more cost-effective cross-linked polymer systems have resulted from a better understanding of chemical cross-links in polysaccharides and of the rheological behavior of cross-linked fluids. The thrust of completion and hydraulic fracturing chemical research has shifted somewhat from systems designed for ever deeper, hotter formations to chemicals, particularly polymers, that exhibit improved cost effectiveness at more moderate reservoir conditions. 

For this study flow (dynamic) and static (batch) tests were carried out on Wilmington oil field unconsolidated sands at reservoir temperatures and flow rates with polyacrylamide (Dow Pusher-500) polymers. Effluent concentration, viscosity, and pH were monitored as a function of time. Extensive characterization studies for the sand were also carried out. 

Static(batch) and dynamic(flow) tests were carried out on toluene - extracted and peroxide - treated Wilmington oil field unconsolidated sands with dilute solutions of polyacrylamide (Dow Pusher-500) polymer in 1 wt% NaCl at 50° C and 1.5 ft./day, simulating reservoir temperature and flow rates. In the static tests, Ottawa sand, with particle size distributions similar to the Wilmington sand, were also used for comparison purposes. 

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). 

Pressure management, where fluid is injected into oil fields in order to maintain adequate fluid pressure in reservoir rocks. Calcium carbonate may precipitate as mineral scale, for example, if pressure is allowed to deteriorate, especially in fields where formation fluids are rich in Ca++ and HCO3 and CO2 fugacity is high. 

In this chapter, in an attempt to devise methods for helping to foresee such unfavorable consequences, we construct models of the chemical interactions between injected fluids and the sediments and formation waters in petroleum reservoirs. We consider two cases the effects of using seawater as a waterflood, taking oil fields of the North Sea as an example, and the potential consequences of using alkali flooding (i.e., the injection of a strong caustic solution) in order to increase oil production from a clastic reservoir. 

Sulfate scaling poses a special problem in oil fields of the North Sea (e.g., Todd and Yuan, 1990, 1992 Yuan et al., 1994), where formation fluids are notably rich in barium and strontium. The scale can reduce permeability in the formation, clog the wellbore and production tubing, and cause safety equipment (such as pressure release valves) to malfunction. To try to prevent scale from forming, reservoir engineers use chemical inhibitors such as phosphonate (a family of organic phosphorus compounds) in squeeze treatments, as described in the introduction to this chapter. 

Fig. 30.1. Volumes of minerals precipitated during a reaction model simulating the mixing at reservoir temperature of seawater into formation fluids from the Miller, Forties, and Amethyst oil fields in the North Sea. The reservoir temperatures and compositions of the formation fluids are given in Table 30.1. The initial extent of the system in each case is 1 kg of solvent water. Not shown for the Amethyst results are small volumes of strontianite, barite, and dolomite that form during mixing.

Fig. 30.2. Saturation states (Q/K) of supersaturated sulfate minerals over the courses of simulations in which seawater mixes at reservoir temperature with formation fluids from three North Sea oil fields. Reaction paths are the same as shown in Figure 30.1, except that minerals are not allowed to precipitate.

Amy Berger helped me write Chapter 10 (Surface Complexation), and Chapter 31 (Acid Drainage) is derived in part from her work. Edward Warren and Richard Worden of British Petroleum s Sunbury lab contributed data for calculating scaling in North Sea oil fields, Richard Wendlandt first modeled the effects of alkali floods on clastic reservoirs, and Kenneth Sorbie helped write Chapter 30 (Petroleum Reservoirs). I borrowed from Elisabeth Rowan s study of the genesis of fluorite ores at the Albigeois district, Wendy Harrison s study of the Gippsland basin, and a number of other published studies, as referenced in the text. 

An oil field may comprise more than one reservoir, i.e., more than one single, continuous, bounded accumulation of oil. Indeed, several reservoirs may exist at various increasing depths, stacked one above the other, isolated by intervening shales and impervious rock strata. Such reservoirs may vary in size from a few tens of hectares to tens of square kilometers. Their layers may be from a few meters in thickness to several hundred or more. Most of the oil that has been discovered and exploited in the world has been found in a relatively few large reservoirs. In the USA, for example, 60 of the approximately 10,000 oil fields have accounted for half of the productive capacity and reserves in the country. 

Enhanced oil recovery is a method used for oil extraction in partly depleted oil fields. One variant of EOR is based on injecting CO2 into the reservoir. This has a twofold effect first, it increases the pressure in the reservoir and, second, the CO2 can reduce the viscosity of the oil. Both effects help improve the flow of oil to the production wells and, thus, increase the oil production, compared with recovery without EOR. 

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