Reservoir recovery

In [259] results are obtained when using foams for EOR in oil fields in China. Many oil fields in China contain up to 80% water as result of water flooding, and the oil recovery does not exceed 20%. The main reason of the low reservoir recovery is a strong heterogeneity of the reservoir which causes the injected water to channel through only the high-permeability zones. Injection of foams in the water-oil front can improve the profiles of injected liquids in view of a drastic difference in flow properties between foam and water, so that the efficiency of oil production can be increased. Anionic surfactants (petroleum sulfonates, a-olefin sulfonates, alkylsulphates) as well as their mixtures with nonionic surfactant and polyacrylamide were tested under laboratory conditions. Data are presented concerning one of the projects accomplished in one of the oil fields in China. Within the period from May 1971 to June 1973 (26.6 months) 933 of 1% solution of surfactant mixture and 8082 m air has been injected which is equivalent to about 5% of the reservoir volume. The water cut decreased by 27.7% while the recovery factor increased by 6%-8%. 

Emulsions, foams, suspensions and aerosols occur, or are created, throughout the full range of processes in the petroleum producing industry (see Table 11.1), including drilling and completion, fracturing and stimulation, reservoir recovery. 

The extent of adsorption of eommereial surfaetants developed for use in reservoir recovery proeesses ean vary from near zero to as high as 2.5 mg/g. Surfactant adsorption on rock surfaces is usually measured by either static (batch) or dynamic (coreflood) experiments. The static adsorption method, employing crushed rock samples, is essentially the classical method for determining adsorption isotherms at the aqueous solution/solid interface and involves batch equilibrations of particles in solutions of different initial surfactant concentration. The dynamic coreflood method is more involved but employs a greater solid to liquid ratio and is therefore more sensitive, see references [J69-J7J]. Temperature, brine salinity and hardness, solution pH, rock type, wettability, and the presence of a residual oil phase have all been found to influence the extent of adsorption of different surfactants [116,152,172],... 

The degree of oil recovery from reservoirs is never 100%, and therefore, some (more than 30%) of the oil in the reservoir remains behind. In order to recover the residual oil, one needs to apply FOR technology (Birdi, 2010a). Major factors arise from capillary forces, as well as adsorption and flow hindrances. The same is valid for nonconventional oil reservoirs recovery from shale deposits. On the other hand, one may consider this as an advantage, since in the long run, as the shortage of... 

All the parameters discussed above are needed to calculate the volume of hydrocarbons in the reservoir. The formation permeability is a measure of the ease with which fluids can pass through the reservoir, and hence is needed for estimating well productivity, reservoir performance and hydrocarbon recovery. 

For example in estimating the ultimate recovery (UR) for an oil reservoir, one would need to use the following variables ... 

The purpose of this exercise is to identify what parameters need to be further investigated if the current range of uncertainty in reserves is too great to commit to a development. In this example, the engineer may recommend more appraisal wells or better definition seismic to reduce the uncertainty in the reservoir area and the net-to-gross ratio, plus a more detailed study of the development mechanism to refine the understanding of the recovery factor. Afluid properties study to reduce uncertainty in (linked to the shrinkage... 

It should be noted that the recovery factor for a reservoir is highly dependenf upon the development plan, and that initial conditions alone cannot be used to determine this parameter. 

Keywords compressibility, primary-, secondary- and enhanced oil-recovery, drive mechanisms (solution gas-, gas cap-, water-drive), secondary gas cap, first production date, build-up period, plateau period, production decline, water cut, Darcy s law, recovery factor, sweep efficiency, by-passing of oil, residual oil, relative permeability, production forecasts, offtake rate, coning, cusping, horizontal wells, reservoir simulation, material balance, rate dependent processes, pre-drilling. 

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. 

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. 

This rather low recovery factor may be boosted by implementing secondary recovery techniques, particularly water Injection, or gas injection, with the aim of maintaining reservoir pressure and prolonging both plateau and decline periods. The decision to implement these techniques (only one of which would be selected) Is both technical and economic. Technical considerations would be the external supply of gas, and the... 

The recovery factor (RF) is in the range 30-70%, depending on the strength of the natural aquifer, or the efficiency with which the injected water sweeps the oil. The high RF is an incentive for water injection into reservoirs which lack natural water drive. 

Gas reservoirs are produced by expansion of the gas contained in the reservoir. The high compressibility of the gas relative to the water in the reservoir (either connate water or underlying aquifer) make the gas expansion the dominant drive mechanism. Relative to oil reservoirs, the material balance calculation for gas reservoirs is rather simple. A major challenge in gas field development is to ensure a long sustainable plateau (typically 10 years) to attain a good sales price for the gas the customer usually requires a reliable supply of gas at an agreed rate over many years. The recovery factor for gas reservoirs depends upon how low the abandonment pressure can be reduced, which is why compression facilities are often provided on surface. Typical recovery factors are In the range 50 to 80 percent. 

The primary drive mechanism for gas field production is the expansion of the gas contained in the reservoir. Relative to oil reservoirs, the material balance calculations for gas reservoirs is rather simple the recovery factor is linked to the drop in reservoir pressure in an almost linear manner. The non-linearity is due to the changing z-factor (introduced in Section 5.2.4) as the pressure drops. A plot of (P/ z) against the recovery factor is linear if aquifer influx and pore compaction are negligible. The material balance may therefore be represented by the following plot (often called the P over z plot). 

The subscript i refers to the initial pressure, and the subscript ab refers to the abandonment pressure the pressure at which the reservoir can no longer produce gas to the surface. If the abandonment conditions can be predicted, then an estimate of the recovery factor can be made from the plot. Gp is the cumulative gas produced, and G is the gas initially In place (GIIP). This is an example of the use of PVT properties and reservoir pressure data being used in a material balance calculation as a predictive tool. 

From the above plot, it can be seen that the recovery factor for gas reservoirs depends upon how low an abandonment pressure can be achieved. To produce at a specified delivery pressure, the reservoir pressure has to overcome a series of pressure drops the drawdown pressure (refer to Figure 9.2), and the pressure drops in the tubing, processing facility and export pipeline (refer to Figure 9.12). To improve recovery of gas, compression facilities are often provided on surface to boost the pressure to overcome the pressure drops in the export line and meet the delivery pressure specified. 

Typical recovery factors for gas field development are in the range 50 to 80 percent, depending on the continuity and quality of the reservoir, and the amount of compression installed (i.e. how low an abandonment pressure can be achieved). 

The recovery factors for oil reservoirs mentioned in the previous section varied from 5 to 70 percent, depending on the drive meohanism. The explanation as to why the other 95 to 30 percent remains in the reservoir is not only due to the abandonment necessitated by lack of reservoir pressure or high water cuts, but also to the displacement of oil in the reservoir. 

If the mobility ratio is greater than 1.0, then there will be a tendency for the water to move preferentially through the reservoir, and give rise to an unfavourable displacement front which is described as viscous fingering. If the mobility ratio is less than unity, then one would expect stable displacement, as shown in Figure 8.16. The mobility ratio may be influenced by altering the fluid viscosities, and this is further discussed in Section 8.8, when enhanced oil recovery is introduced. 

Analytical models using classical reservoir engineering techniques such as material balance, aquifer modelling and displacement calculations can be used in combination with field and laboratory data to estimate recovery factors for specific situations. These methods are most applicable when there is limited data, time and resources, and would be sufficient for most exploration and early appraisal decisions. However, when the development planning stage is reached, it is becoming common practice to build a reservoir simulation model, which allows more sensitivities to be considered in a shorter time frame. The typical sorts of questions addressed by reservoir simulations are listed in Section 8.5. 

The type of development, type and number of development wells, recovery factor and production profile are all inter-linked. Their dependency may be estimated using the above approach, but lends itself to the techniques of reservoir simulation introduced in Section 8.4. There is never an obvious single development plan for a field, and the optimum plan also involves the cost of the surface facilities required. The decision as to which development plan is the best is usually based on the economic criterion of profitability. Figure 9.1 represents a series of calculations, aimed at determining the optimum development plan (the one with the highest net present value, as defined in Section 13). 

In the case of the very low vertical permeability, the horizontal well actually produces at a lower rate than the vertical well. Each of these examples assumes that the reservoir is a block, with uniform properties. The ultimate recovery from the horizontal well in the above examples Is unlikely to be different to that of the vertical well, and the major benefit is in the accelerated production achieved by the horizontal well. 

Horizontal wells have a large potential to connect laterally discontinuous features in heterogeneous or discontinuous reservoirs. If the reservoir quality is locally poor, the subsequent section of the reservoir may be of better quality, providing a healthy productivity for the well. If the reservoir is faulted or fractured a horizontal well may connect a series of fault blocks or natural fractures In a manner which would require many vertical wells. The ultimate recovery of a horizontal well is likely to be significantly greater than for a single vertical well. 

In gas field development, the recovery factor is largely determined by how low a reservoir pressure can be achieved before finally reaching the abandonment pressure. As the reservoir pressure declines, it is therefore common to install compression facilities at the surface to pump the gas from the wellhead through the surface facilities to the delivery point. This compression may be installed in stages through the field lifetime. 

Water may be injected into the reservoir to supplement oil recovery or to dispose of produced water. In some cases these options may be complementary. Water will generally need to be treated before it can be injected into a reservoir, whether it is cleaned sea water or produced water. Once treated it is injected into the reservoir, often at high pressures. Therefore to design a process flow scheme for water injection one needs specifications of the source water and injected water. 

Gas can be injected into reservoirs to supplement recovery by maintaining reservoir pressure or as a means of disposing of gas which cannot be flared under environmental legislation, and for which no market exists. 

Generally EOR techniques have been most successfully applied in onshore, shallow reservoirs containing viscous crudes, where recoveries under conventional methods are very low. The Society of Petroleum Engineers publishes a regular report on current EOR projects, including both pilot and full commercial schemes (the majority of which are in the USA). In the 1992 report, EOR methods could be divided into three basic types ... 

Steam is injected into a reservoir to reduce oil viscosity and make it flow more easily. This technique is used in reservoirs containing high viscosity crudes where conventional methods only yield very low recoveries. Steam can be injected in a cyclic process in which the same well is used for injection and production, and the steam is allowed to soak prior to back production (sometimes known as Huff and Puff). Alternatively steam is injected to create a steam flood, sweeping oil from injectors to producers much as in a conventional waterflood. In such cases it is still found beneficial to increase the residence (or relaxation) time of the steam to heat treat a greater volume of reservoir. 

Lubricants, Fuels, and Petroleum. The adipate and azelate diesters of through alcohols, as weU as those of tridecyl alcohol, are used as synthetic lubricants, hydrauHc fluids, and brake fluids. Phosphate esters are utilized as industrial and aviation functional fluids and to a smaH extent as additives in other lubricants. A number of alcohols, particularly the Cg materials, are employed to produce zinc dialkyldithiophosphates as lubricant antiwear additives. A smaH amount is used to make viscosity index improvers for lubricating oils. 2-Ethylhexyl nitrate [24247-96-7] serves as a cetane improver for diesel fuels and hexanol is used as an additive to fuel oil or other fuels (57). Various enhanced oil recovery processes utilize formulations containing hexanol or heptanol to displace oil from underground reservoirs (58) the alcohols and derivatives are also used as defoamers in oil production. 

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