Reservoirs conditions

A brief introduction to the reservoir conditions from geological aspects will help in understanding the role of pressure in oil and gas reservoirs. 

Petroleum is originally formed from insoluble organic matter called kerogen by pyrolysis under elevated temperatures up to 150 °C. Different factors contributed to the migration of fluids that are composed of alkanes and aromatics (Table 7.1). Cracking of long alkane chains into volatile components, such as methane, leads to pressure buildup in the reservoir. High reservoir temperatures (200 °C) also enhance the pressure accumulation under certain circumstances [1]. 

Each factor in Table 7.1 is thoroughly discussed in view of improving oU recovery techniques at high-pressure conditions. 

Fluid saturation in reservoir rocks is divided into gas, oil, and water saturation water refers to formation water that is believed to be the original fluid in place before 

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The initial condition for the dry gas is outside the two-phase envelope, and is to the right of the critical point, confirming that the fluid initially exists as a single phase gas. As the reservoir is produced, the pressure drops under isothermal conditions, as indicated by the vertical line. Since the initial temperature is higher than the maximum temperature of the two-phase envelope (the cricondotherm - typically less than 0°C for a dry gas) the reservoir conditions of temperature and pressure never fall inside the two phase region, indicating that the composition and phase of the fluid in the reservoir remains constant. 

Gas density at reservoir conditions is useful for calculation the pressure gradient of the gas when constructing pressure-depth relationships (see Section 5.2.8). 

Oil viscosity is an important parameter required in predicting the fluid flow, both in the reservoir and in surface facilities, since the viscosity is a determinant of the velocity with which the fluid will flow under a given pressure drop. Oil viscosity is significantly greater than that of gas (typically 0.2 to 50 cP compared to 0.01 to 0.05 cP under reservoir conditions). 

The downhole density of oil (at reservoir conditions) can be calculated from the surface density using the equation ... 

The density of the oil at reservoir conditions is useful in calculating the gradient of oil and constructing a pressure - depth relationship in the reservoir (see section 5.2.8). 

Assuming an initial reservoir pressure above the bubble point (undersaturated reservoir oil), only one phase exists in the reservoir. The volume of oil (rm or rb) at reservoir conditions of temperature and pressure is calculated from the mapping techniques discussed in Section 5.4. 

The oil formation volume factor at initial reservoir conditions (B., rb/stb) is used to convert the volumes of oil calculated from the mapping and volumetries exercises to... 

Fluid samples may be collected downhole at near-reservoir conditions, or at surface. Subsurface samples are more expensive to collect, since they require downhole sampling tools, but are more likely to capture a representative sample, since they are targeted at collecting a single phase fluid. A surface sample is inevitably a two phase sample which requires recombining to recreate the reservoir fluid. Both sampling techniques face the same problem of trying to capture a representative sample (i.e. the correct proportion of gas to oil) when the pressure falls below the bubble point. 

The formation volume factor for water (B, reservoir volume per stock tank volume), is close to unity (typically between 1.00 and 1.07 rb/stb, depending on amount of dissolved gas, and reservoir conditions), and is greater than unity due to the thermal contraction and evolution of gas from reservoir to stock tank conditions. 

This section will look at formation and fluid data gathering before significant amounts of fluid have been produced hence describing how the static reservoir is sampled. Data gathered prior to production provides vital information, used to predict reservoir behaviour under dynamic conditions. Without this baseline data no meaningful reservoir simulation can be carried out. The other major benefit of data gathered at initial reservoir conditions is that pressure and fluid distribution are in equilibrium this is usuaily not the case once production commences. Data gathered at initial conditions is therefore not complicated... 

One method of sampling reservoir fluids and taking formation pressures under reservoir conditions in open hole is by using a wireline formation tester. A number of wireline logging companies provide such a tool under the names such as RFT (repeat formation tester) and FMT (formation multi tester), so called because they can take a series of pressure samples in the same logging run. A newer version of the tool is called a modular dynamic tester or MDT (Schlumberger tool), shown in Figure 3.8. 

The most commonly used polymers are partially hydrolyzed polyacrylamides (32). The optimum degree of hydrolysis depends on the apphcation, injection water composition, and reservoir conditions (33,34). More salt-tolerant acrylamide copolymers may permit this technology in higher salinity injection water (35). Eield apphcations of cross-linked xanthan gum have also been reported (36). 

In addition to the mobihty control characteristics of surfactants, critical issues in gas mobihty control processes are surfactant salinity tolerance, hydrolytic stabihty under reservoir conditions, surfactant propagation through the reservoir, and foam stabihty in the presence of cmde oil saturations. 

The alpha-olefin sulfonates (AOS) have been found to possess good salt tolerance and chemical stabiUty at elevated temperatures. AOS surfactants exhibit good oil solubilization and low iaterfacial tension over a wide range of temperatures (219,231), whereas less salt tolerant alkylaromatic sulfonates exhibit excellent chemical stabiUty. The nature of the alkyl group, the aryl group, and the aromatic ring isomer distribution can be adjusted to improve surfactant performance under a given set of reservoir conditions (232,233). 

Tar sand, also variously called oil sand (in Canada) or bituminous sand, is the term commonly used to describe a sandstone reservoir that is impregnated with a heavy, viscous black extra heavy cmde oil, referred to as bitumen (or, incorrectly, as native asphalt). Tar sand is a mixture of sand, water, and bitumen, but many of the tar sand deposits in the United States lack the water layer that is beHeved to cover the Athabasca sand in Alberta, Canada, thereby faciHtating the hot-water recovery process from the latter deposit. The heavy asphaltic organic material has a high viscosity under reservoir conditions and caimot be retrieved through a weU by conventional production techniques. 

Knowledge of the temperature and pressure of a gas stream at the wellhead is important for determining whether hydrate formation can be expected when the gas is expanded into the flow lines. The temperature at the wellhead can change as the reservoir conditions or production rate changes over the producing life of the well. Thus, wells that initially flowed at conditions at which hydrate formation in downstream equipment was not expected may eventually require hydrate prevention, or vice versa. 

First the amount of water that will be condensed will be determined from Figure 4-6, assuming the gas is saturated at reservoir conditions. 

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. 

B. licheniformis JF-2 and Clostridium acetogutylicum were investigated under simulated reservoir conditions. Sandstone cores were equilibrated to the desired simulated reservoir conditions, saturated with oil and brine, and flooded to residual oil saturation. The waterflood brine was displaced with a nutrient solution. The MEOR efficiency was directly related to the dissolved gas/oil ratio. The principal MEOR mechanism observed in this work was solution gas drive [505]. 

Laboratory experiments have indicated that carbonate precipitation can alter the permeability of the core samples under reservoir conditions. The precipitation reduces the gas permeability in favor of the liquid permeability. This indicates that precipitation occurs preferentially in the larger pores. 

E. C. Donaldson and T. Obeida. Enhanced oil recovery at simulated reservoir conditions. In E. C. Donaldson, editor. Microbial enhancement of oil recovery Recent advances Proceedings of the 1990 International Conference on Microbial Enhancement of Oil Recovery, volume 31 of Developments in Petroleum Science, pages 227-245. Elsevier Science Ltd, 1991. 

G. M. Graham, M. M. Jordan, K. S. Sorbie, J. Bunney, G. C. Graham, W. SableroUe, and P. HiU. The implication of HP/HT (high pressure/high temperature) reservoir conditions on the selection and application of conventional scale inhibitors Thermal stability studies. In Proceedings Volume, pages 627-640. SPE Oilfield Chem Int Symp (Houston, TX, 2/18-2/21), 1997. 

J. A. Ramsay, D. G. Cooper, and R. J. Neufeld. Effects of oil reservoir conditions on the production of water-insoluble levan by Bacillus licheniformis. GeomicrobiolJ, 7(3) 155-165, July 1989. 

In situ NMR measurements can be made in conjunction with down-hole fluid sampling [5, 6]. The NMR relaxation time and diffusivity can be measured under high-temperature, high-pressure reservoir conditions without loss of dissolved gases due to pressure depletion. In cases when the fluids may be contaminated by invasion of the filtrate from oil-based drilling fluids, the NMR analysis can determine when the fluid composition is approaching that of the formation [5, 6]. 

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 a miscible displacement at the required reservoir conditions, carbon dioxide must exist as a dense fluid (in the range 0.5 to 0.8g/cc). Unfortunately, the viscosity of even dense CO2 is in the range of 0.03 to 0.08 cp, no more than one twentieth that of crude oil. When CO2 is used directly to displace the crude, the unfavorable viscosity ratio produces inefficient oil displacement by causing fingering of the CO2, due to frontal instability. In addition, the unfavorable mobility ratio accentuates flow non-... 

Laboratory Apparatus for Study of the Flow of Foam In Porous Media Under Reservoir Conditions... 

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