Fluid reservoirs

a knowledge of the reservoir fluids is essential. This includes the fluid types (oil or gas) and the fluid properties. Fluid properties include carbon dioxide (CO ) or hydrogen sulfide (H S) content in gas, gravity of oil, paraffin and asphaltene contents, and volume and properties (ionic composition and scaling tendency) of produced water. 

Reservoir fluid sample analyses should be reviewed or conducted if analyses do not yet exist. Produced fluids can cause damage through deposition of wax or asphaltenes from oil or through scale formed from produced brine. Also, while well assessment continues, it may be found that fluids incompatible with the reservoir fluids, inducing organic deposition or scale formation, may have been introduced sometime in the well s past. 

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Reservoir fluids are broadly cafegorised using those properties which are easy to measure in the field, namely oil and gas gravity, and the producing gasioil ratio (GOR) which is the volumetric ratio of the gas produced at standard condition of femperature and pressure (STP) fo fhe oil produced at STP. The commonly used units are shown in the following table. 

There are no definitions for categorising reservoir fluids, but the following table indicates typical GOR, API and gas and oil gravities for the five main types. The compositions show that the dry gases contain mostly paraffins, with the fraction of longer chain components increasing as the GOR and API gravity of the fluids decrease. 

So far we have considered only a single component. However, reservoir fluids contain a mixture of hundreds of components, which adds to the complexity of the phase behaviour. Now consider the impact of adding one component to the ethane, say n-heptane (C7H.,g). We are now discussing a binary (two component) mixture, and will concentrate on the pressure-temperature phase diagram. 

The example of a binary mixture is used to demonstrate the increased complexity of the phase diagram through the introduction of a second component in the system. Typical reservoir fluids contain hundreds of components, which makes the laboratory measurement or mathematical prediction of the phase behaviour more complex still. However, the principles established above will be useful in understanding the differences in phase behaviour for the main types of hydrocarbon identified. 

Figure 5.21 helps to explain how the phase diagrams of the main types of reservoir fluid are used to predict fluid behaviour during production and how this influences field development planning. It should be noted that there are no values on the axes, since in fact the scales will vary for each fluid type. Figure 5.21 shows the relative positions of the phase envelopes for each fluid type. 

Black oils are a common category of reservoir fluids, and are similar to volatile oils in behaviour, except that they contain a lower fraction of volatile components and therefore require a much larger pressure drop below the bubble point before significant volumes of gas are released from solution. This is reflected by the position of the iso-vol lines in the phase diagram, where the lines of low liquid percentage are grouped around the dew point line. 

When the pressure of a volatile oil or black oil reservoir is above the bubble point, we refer to the oil as undersaturated. When the pressure is at the bubble point we refer to it as saturated oil, since if any more gas were added to the system it could not be dissolved in the oil. The bubble point is therefore the saturation pressure for the reservoir fluid. 

The value of the compresjiibility of oil is a function of the amount of dissolved gas, but is in the order of 10 x 10" psi" By comparison, typical water and gas compressibilities are 4x10" psi" and 500 x 10" psi" respectively. Above the bubble point in an oil reservoir the compressibility of the oil is a major determinant of how the pressure declines for a given change in volume (brought about by a withdrawal of reservoir fluid during production). 

The collection of representative reservoir fluid samples is important in order to establish the PVT properties - phase envelope, bubble point, Rg, B, and the physical properties - composition, density, viscosity. These values are used to determine the initial volumes of fluid in place in stock tank volumes, the flow properties of the fluid both in the reservoir and through the surface facilities, and to identify any components which may require special treatment, such as sulphur compounds. 

Reservoir fluid sampling is usually done early in the field life in order to use the results in the evaluation of the field and in the process facilities design. Once the field has been produced and the reservoir pressure changes, the fluid properties will change as described in the previous section. Early sampling is therefore an opportunity to collect unaltered fluid samples. 

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. 

Surface sampling involves taking samples of the two phases (gas and liquid) flowing through the surface separators, and recombining the two fluids in an appropriate ratio such that the recombined sample is representative of the reservoir fluid. 

Below is a typical oil PVT table which is the result of PVT analysis, and which would be used by the reservoir engineer in calculation of reservoir fluid properties with pressure. The initial reservoir pressure is 6000 psia, and the bubble point pressure of the oil Is 980 psia. 

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. 

In nearly all oil or gas reservoirs there are layers which do not contain, or will not produce reservoir fluids. These layers may have no porosity or limited permeability and are generally defined as non reservoir intervals. The thickness of productive (net) reservoir rock within the total (gross) reservoir thickness is termed the net-to-gross or N/G ratio. 

The other parameters used in the calculation of STOMP and GIIP have been discussed in Section 5.4 (Data Interpretation). The formation volume factors (B and Bg) were introduced in Section 5.2 (Reservoir Fluids). We can therefore proceed to the quick and easy deterministic method most frequently used to obtain a volumetric estimate. It can be done on paper or by using available software. The latter is only reliable if the software is constrained by the geological reservoir model. 

This section will consider the behaviour of the reservoir fluids in the bulk of the reservoir, away from the wells, to describe what controls the displacement of fluids towards the wells. Understanding this behaviour is important when estimating the recovery factor for hydrocarbons, and the production forecast for both hydrocarbons and water. In Section 9.0, the behaviour of fluid flow at the wellbore will be considered this will influence the number of wells required for development, and the positioning of the wells. 

Reservoir fluids (oil, water, gas) and the rock matrix are contained under high temperatures and pressures they are compressed relative to their densities at standard temperature and pressure. Any reduction in pressure on the fluids or rock will result in an increase in the volume, according to the definition of compressibility. As discussed in Section 5.2, isothermal conditions are assumed in the reservoir. Isothermal compressibility is defined as ... 

The expansion of the reservoir fluids, which is a function of their volume and compressibility, act as a source of drive energy which can act to support primary producf/on from the reservoir. Primary production means using the natural energy stored in the reservoir as a drive mechanism for production. Secondary recovery would imply adding some energy to the reservoir by injecting fluids such as water or gas, to help to support the reservoir pressure as production takes place. 

The above experiment was conducted for a single fluid only. In hydrocarbon reservoirs there is always connate water present, and commonly two fluids are competing for the same pore space (e.g. water and oil in water drive). The permeability of one of the fluids is then described by its relative permeability (k ), which is a function of the saturation of the fluid. Relative permeabilities are measured in the laboratory on reservoir rock samples using reservoir fluids. The following diagram shows an example of a relative permeability curve for oil and water. For example, at a given water saturation (SJ, the permeability... 

A speed controller does not ehminate the need for a recycle valve, flare valve, or suction throttling valve, but it will minimize their use. The recycle valve and suction throttling valve add arbitrary loads to the compressor and thus increase fuel usage. The flare valve leads to a direct waste of reservoir fluids and tlius loss of income. For this reason, engine speed control is rec-... 

Burcik, E.J., Properties of Petroleum Reservoir Fluids, International Human Resources Development Corp., Boston, 1979. 

Displacement of reservoir fluids by influx of water into a reservoir as a result of a pressure differential. 

Deposition of adamantane from petroleum streams is associated with phase transitions resulting from changes in temperature, pressure, and/or composition of reservoir fluid. Generally, these phase transitions result in a solid phase from a gas or a liquid petroleum fluid. Deposition problems are particularly cumbersome when the fluid stream is dry (i.e., low LPG content in the stream). Phase segregation of solids takes place when the fluid is cooled and/or depressurized. In a wet reservoir fluid (i.e., high LPG content in the stream) the diamondoids partition into the LPG-rich phase and the gas phase. Deposition of diamondoids from a wet reservoir fluid is not as problematic as in the case of dry streams [74, 75]. 

Fig. 2.19. Reservoir temperature versus saturation indices (logQ/K) for calcite, anhydrite, K-feldspar and K-mica based on the estimated composition of reservoir fluid (Seki, 1991). Estimation based on gas results of Seki (1990), with saturation calculations carried out by PECS (Takeno, 1988). Gas concentrations were assumed to be 1 wt% of CO2 and 250 mg/kg for H2S for all wells (Seki, 1991).

Several surfactants were studied in ambient-pressure foam tests, including alcohol ethoxylates, alcohol ethoxysulfates, alcohol ethoxyethylsulfonates, and alcohol ethoxyglycerylsuUbnates [210]. Surfactants that performed well in the 1-atm foaming experiment were also good foaming agents in site cell and core flood experiments performed in the presence of CO2 and reservoir fluids under realistic reservoir temperature and pressure conditions. 

Tracers have been used to label fluids in order to track fluid movement and monitor chemical changes of the injected fluid. Radioactive materials are one class of commonly used tracers. These tracers have several drawbacks. One drawback is that they require special handling because of the danger posed to personnel and the environment. Another drawback is the alteration by the radioactive materials of the natural isotope ratio indigenous to the reservoir— thereby interfering with scientific analysis of the reservoir fluid characteristics. In addition, the half life of radioactive tracers tends to be either too long or too short for practical use. 

B. Tohidi, A. Danesh, R. W. Burgass, and A. C. Todd. Effect of heavy hydrate formers on the hydrate free zone of real reservoir fluids. In Proceedings Volume, pages 257-261. SPE/Norwegian Petrol Soc Europe Prod Oper Conf (Stavanger, Norway, 4/16-4/17), 1996. 

Chemical reactions may result from interactions among and between the three phases of matter solid, liquid, and gas. The major interactions that occur in the deep-well environment are those between different liquids (injected waste with reservoir fluids) and those between liquids and solids (injected wastes and reservoir fluids with reservoir rock). Although gases may exist, they are usually dissolved in liquid at normal deep-well pressures. 

Precipitation may be significant for heavy metals and other inorganic constituents in injected wastes. For example, sulfide ions have a strong affinity for metal ions, precipitating as metal sulfides. The dissolved constituents in injected wastes and reservoir fluids would not be in equilibrium with the in situ brines because of the fluids different temperature, pH, and Eh. When the fluids are mixed, precipitation reactions can lead to injection-well plugging. 

If osmotic effects are possible, several other effects would need to be considered in a geochemical-fate assessment, depending on whether the solute concentration is increased or decreased. If solute concentrations are increased, pressures associated with injection would increase beyond those predicted without osmotic effects. Also, the movement of ions to the injection zone from the aquifer with lower salinity (above the clay confining layer) would increase the salinity above those levels predicted by simple mixing of the reservoir fluid and the injected wastes. This action could affect the results of any geochemical modeling. 

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