A Case Study of Natural Flow and Tubing String Design for a Water Drive Reservoir
Chapter One
OBJECTIVES AND SCOPE OF THE WORK
The main objectives of this study include:
- To design natural flow and artificial lift tubing strings for the whole life of a
- To design and simulate along time the production conditions for natural flow, continuous liftand ESP for the later phases of the reservoir by imposing either a constant flowrate or a constant bottom hole flowing pressure.
- To present a forecast of the production of oil and gas as well as the time where tubing strings should be replaced as a function of both the cumulative production and time.
Chapter Two
Literature Review
The Inflow Performance Relationship (IPR) describes the behaviour of a well’s flowing pressure
and production rate, which is an important tool in understanding the reservoir or well behaviour and quantifying the production rate. The IPR is often required for designing well completion, optimizing well production, nodal analysis calculations, and designing artificial lift. Different IPR correlations exist today in the petroleum industry with the most commonly used models being that of Vogel’s and Fetkovich’s (Mohammed et al, 2009).
RESERVOIR NATURAL DRIVE MECHANISMS
Natural drive mechanisms refers to the energy in the reservoir that allows the fluid to flow through the porous network and into the wells. In its simplest definition, reservoir energy is always related to some kind of expansion (Cosentino et al, 2001). For a proper understanding of reservoir behaviour and predicting future performance, it is necessary to have knowledge of the driving mechanisms that control the behaviour of fluids within reservoirs. Several types of expansions take place inside and outside the reservoir, as a consequence of fluid withdrawals. Inside the reservoir, the expansion of hydrocarbons, connate water and the rock itself provides energy for the fluid to flow. Outside the producing zone, the expansion of a gas cap and/or of an aquifer may also supply a significant amount energy to the reservoir. In this case, the expansion of an external phase causes its influx into the reservoir and will ultimately result in a displacement process (Cosentino et al, 2001). There are basically six driving mechanisms that provide the natural energy necessary for oil recovery:
- Rock and liquid expansion drive
- Depletion drive
- Gas cap drive
- Water drive
- Gravity drainage drive
- Combination drive
The attention of this project is on the Depletion drive mechanism also known as the solution gas drive mechanism which is reviewed as follows.
SOLUTION – GAS DRIVE RESERVOIR
This driving form may also be referred to by the following various terms: Solution gas drive, Dissolved gas drive or Internal gas drive. A solution gas drive reservoir is one in which the principal drive mechanism is the expansion of the oil and its originally dissolved gas. The increase in fluid volumes during the process is equivalent to the production (Dake, 1978). A solution – gas drive reservoir is mostly closed from any outside source of energy, such as water encroachment. Its pressure is initially above bubble-point pressure, and, therefore, no free gas exists. The only source of material to replace the produced fluids is the expansion of the fluids remaining in the reservoir (Beggs, 2003). Some small but usually negligible expansion of the connate water and rock may also occur.
When the reservoir falls below the saturation pressure, gas is liberated from the hydrocarbon liquid phase. Expansion of the gas phase contributes to the displacement of the residual liquid phase. Initially the liberated gas will expand but not flow, until its saturation reaches a threshold value, called critical gas saturation (Cosentino et al, 2001). Typical values of the critical saturation ranges between 2 and 10% (Cosentino et al, 2001). When this value is reached, gas starts to flow with a velocity proportional to its saturation. The more the pressure drops, the faster the gas is liberated and produced, thus lowering further the pressure, in a sort of chain reaction that quickly leads to the depletion of the reservoir (Cosentino et al, 2001).
At the surface, solution gas drive reservoirs are characterised in general by rapidly increasing in Gas – Oil Ratios (GORs) and decreasing oil rates. Generally no or little water is produced. The ideal behaviour of a field under solution gas drive is depletion is illustrated in fig.
2.3. The GOR curve has a peculiar shape, in that it tends to remain constant and equal to the initial Rsi while the reservoir pressure is below the bubble point, then it tends to decline slightly until the critical gas saturation is reached. This decline corresponds to the existence of some gas in the reservoir, that cannot be mobilized (Cosentino et al., 2001). After the critical saturation is reached, the GOR increases rapidly and finally declines towards the end of the field life, when the reservoir approaches the depletion pressure.
The most important parameter in solution – gas drive reservoirs is gas – oil relative permeability (Cosentino et al., 2001). Actually, the increase in the GOR curve is related to the increased gas permeability with respect to oil, as its saturation increases. The lower the critical gas saturation, the more rapidly the gas will be mobilised and produced, thus accelerating the depletion and impairing the final recovery (Cosentino et al., 2001).
Chapter Three
Material Balance For Predicting The Primary Recovery
Tracy’s calculations are performed in series of pressure drops that proceed from known reservoir condition at the previous reservoir pressure p* to the new assumed lower pressure p. The calculated results at the new reservoir pressure become “known” at the next assumed lower pressure.
In progressing from the conditions at any pressure p* to the lower reservoir pressure p, consider that the incremental oil and gas production are ∆Np and ∆Gp, or:
N p =N p +ΔN p 3.1
G p =G p +ΔG p 3.2
where N p ,G p = ” known ” cumulative oil and gas production at previous pressure level p*
N p ,G p = ” unknown ” cumulative oil and gas production at new pressure level p
Chapter Four
Design of Artificial Lift and Tubing Strings
DESIGN PARAMETER
The following data is available for the oil well:
Average reservoir pressure = 2740 psi Water Cut = 0%
Initial Gas – Liquid ratio (GLRi) = 721 scf/stb J* = 1.5
API = 25
Specific gravity to gas = 0.7 Average Temperature = 170 °F Reservoir depth = 7500 ft Wellhead pressure = 150 psi
Inclination angle with Horizontal = 90o (vertical well)
Nominal tubing sizes of 1/2”, 1”, 1 1/2”, 2 3/8”, or 3 1⁄2” is employed in the design ofthe gas lift.
CHAPTER FIVE
CONCLUSIONS AND RECOMMENDATIONS
Conclusions
- Reservoir pressure was maintained much longer in comparison to other drive mechanismwhen there is an active water drive preferably edge water drive reservoirs which maintains a steady- flow condition for a long time before water breakthrough into the
- In selecting the optimum tubing size both the hydrostatic loss and friction loss due to thetubing string must be carefully analysed. Optimum tubing string for the production of this reservoir is the 2.375” tubing which produces the reservoir from an average pressure of 2740 psi at a GOR of 760 scf/stb up to a pressure of about 1300 psi
Recommendations
The following areas have been identified for improvement in the development of the work
- One of the assumptions in this work is the use of synthetic reservoir performance data basedon material balance a possible extension is by incorporating more practical condition by including more wells and the performance with time better analysed
- Furtheroil production economic analysis should be inclusive in the work so that the optimum production pattern of the reservoir will be determined
REFERENCES
- Beggs,, Production Optimization Using Nodal Analysis, Second Edition, OGCI and Petroskills Publications, Tulsa, Oklahoma, pp. 150 – 153, 2003.
- Boyun, , Lyons, W. C., and Ghalambor, A., Petroleum Production Engineering, ElsevierScience and Technology Books, 287 pp., 2007.
- Craft, C., and Hawkins, M., Applied Petroleum Reservoir Engineering, Second Edition, Prentice – Hall, Inc., New Jersey, pp. 370 – 375, 1991.
- Cosentino,, Integrated Reservoir Studies, Technip Editions, Paris, pp. 182 – 187, 2001.
- Dake, P., Fundamentals of Reservoir Engineering, Elsevier, Amsterdam, The Netherlands, 1978.
- Dake, P., The Practice of Reservoir Engineering, Revised Edition, Elsevier, pp. 86 – 109, 1994.
- Golan,, and Whitson, C. H., Well Performance, Second Edition, Prentice – Hall, Inc., 1995.
- Lyons, C., Standard Handbook of Petroleum & Natural Gas Engineering, Vol. 1, Gulf Publishing Company, Houston, Texas, 1996.
- Mohamed, E., Ahmed, E. H., Fattah, K. A., and El-Sayed, A. M. E., “New InflowPerformance Relationship for Solution-Gas Drive Oil Reservoirs,” paper SPE 124041 presented at the 2009 SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 4–7 October
- Oudeman, P., “On the Flow Performance of Velocity Strings To Unload Wet Gas Wells,”paper SPE 104605 presented at the 15th SPE Middle East Oil & Gas Show and Conference held in Bahrain International Exhibition Centre, Kingdom of Bahrain, 11 – 14 March,
