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Cyclic steam stimulation design: Difference between revisions
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Prats<ref name="r1">Prats, M. 1982. Thermal Recovery, No. 7. Richardson, Texas: Monograph Series, SPE.</ref> defines stimulation as "any operation (not involving perforating or recompleting) carried out with the intent of increasing the post-treatment production rate without changing the driving forces in the reservoir." Periodic injection of steam into a producing well, alternating with a production cycle, has many features of this definition but also has many features that distinguish it as a true enhanced recovery mechanism. (This cyclic process is sometimes referred to as "huff and puff.") The primary benefit of the process is true stimulation—near wellbore reduction of flow resistance, viscosity reduction. However, there are enhanced oil recovery (EOR) benefits of high-temperature gas dissolution, wettability changes, and relative permeability hysteresis (water flows into the reservoir easier than it flows out). Fortunately, calculating the temperature history of the wellbore, tracking the water/oil saturation history and the [[Oil_viscosity|oil viscosity]] reduction is adequate to estimate the oil production response to the process. The design of the cyclic steam stimulation (CSS) process involves constantly changing conditions; this page discusses calculations that give a good representation of what can be expected. | Prats<ref name="r1">Prats, M. 1982. Thermal Recovery, No. 7. Richardson, Texas: Monograph Series, SPE.</ref> defines stimulation as "any operation (not involving perforating or recompleting) carried out with the intent of increasing the post-treatment production rate without changing the driving forces in the reservoir." Periodic injection of steam into a producing well, alternating with a production cycle, has many features of this definition but also has many features that distinguish it as a true enhanced recovery mechanism. (This cyclic process is sometimes referred to as "huff and puff.") The primary benefit of the process is true stimulation—near wellbore reduction of flow resistance, viscosity reduction. However, there are enhanced oil recovery (EOR) benefits of high-temperature gas dissolution, wettability changes, and relative permeability hysteresis (water flows into the reservoir easier than it flows out). Fortunately, calculating the temperature history of the wellbore, tracking the water/oil saturation history and the [[Oil_viscosity|oil viscosity]] reduction is adequate to estimate the oil production response to the process. The design of the cyclic steam stimulation (CSS) process involves constantly changing conditions; this page discusses calculations that give a good representation of what can be expected. | ||
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== External links == | == External links == | ||
Xiong, Hongjie. 2017. "Optimizing Cluster or Fracture Spacing: An Overview." The Way Ahead. Society of Petroleum Engineers. https://www.spe.org/en/twa/twa-article-detail/?art=3007 | |||
== See also == | |||
[[Steamflood_design|Steamflood design]] | |||
[[Thermal_recovery_by_steam_injection|Thermal recovery by steam injection]] | |||
[[Steam_delivery_systems_for_EOR|Steam delivery systems for EOR]] | |||
[[Steamflood_heat_management|Steamflood heat management]] | |||
[[PEH:Thermal_Recovery_by_Steam_Injection]] | |||
== Category == | |||
[[Category:3.2 Well operations, optimization, and stimulation]] [[Category:YR]] |
Revision as of 13:24, 20 June 2017
Prats[1] defines stimulation as "any operation (not involving perforating or recompleting) carried out with the intent of increasing the post-treatment production rate without changing the driving forces in the reservoir." Periodic injection of steam into a producing well, alternating with a production cycle, has many features of this definition but also has many features that distinguish it as a true enhanced recovery mechanism. (This cyclic process is sometimes referred to as "huff and puff.") The primary benefit of the process is true stimulation—near wellbore reduction of flow resistance, viscosity reduction. However, there are enhanced oil recovery (EOR) benefits of high-temperature gas dissolution, wettability changes, and relative permeability hysteresis (water flows into the reservoir easier than it flows out). Fortunately, calculating the temperature history of the wellbore, tracking the water/oil saturation history and the oil viscosity reduction is adequate to estimate the oil production response to the process. The design of the cyclic steam stimulation (CSS) process involves constantly changing conditions; this page discusses calculations that give a good representation of what can be expected.
Design calculations
Steamflood design is simple compared to CSS design. Whereas steamflood reaches equilibrium and can be represented by a set of steady-state equations for much of its life, the CSS process is one of constantly changing conditions. First there is the injection phase, which is relatively so short that it is a total transition period. Then during the soaking period, steam vapor condenses and temperature begins to fall. The producing period is in a constant state of flux as testified by the constantly changing producing rates. Relative permeability curves, which can typically be ignored in steamflood calculations, become very important to CSS.
In spite of these problems, there are several desktop calculations that give a good representation of what can be expected from CSS. Probably the simplest representation of the process is by Owens and Suter,[2]
This simply indicates the productivity ratio resulting from steam temperature-induced oil-viscosity reduction. No attempt was made to calculate how the reservoir got the peak temperature, but once the well is steamed and placed on production, the authors propose that the operator can simply watch leadline temperature and accurately predict the production history of the production period prior to the next cycle.
Boberg and Lantz[3] method
The referenced paper describes the definitive work that serves as the basis of virtually all subsequent analytical analyses of CSS. They first calculate the reservoir temperature distribution resulting during the injection period. Eq. 2 is used to calculate the area of the processed zone that is heated to Ti.
Then, the well is placed on production and temperature of the heated volume, which is assumed to remain constant and begins to fall by conduction to the surrounding cold reservoir rock and by hot fluid production. The average temperature in the hot zone is
where fVr and fVz are unit solutions of component conduction in the radial and vertical directions, respectively. They can be estimated from Fig. 1 or from
and
The term fpD accounts for heat removed with produced fluids.
and
The subscript, h, indicates that the properties should be for fluids from the hot zone at the sand face. The model does not predict steam, gas, or water producing rates, which must be estimated from some other source. Oil production rates are given by a method similar to Eq. 1, which is written as
and
F1 and F2 are radial flow factors for which Boberg and Lantz give expressions in Table 1. Note that the production rate is a function of only two variables—oil viscosity and the heated radius.
Fig. 1 – Vertical and radial heat-loss factors for Eq. 10.[2]
Table 1 - Boberg and Lantz[3] radial flow factors
The method can be calculated by hand for a very few time steps, but it is much easier to use if programmed into a spreadsheet.
Towson and Boberg[4] model
The Boberg and Lantz method assumes that there is significant reservoir energy to produce oil under primary conditions. Because many CSS candidates have only gravity forces and initial viscosity is high, there is no significant primary production. Many California reservoirs have free liquid surfaces in the oil zones with a gas oil interface at atmospheric pressure. Towson and Boberg extended the former work to cover this situation. Eq. 3 is used to calculate the heated zone temperature from which oil viscosity is estimated. Then, gravity drainage oil rate may be calculated.
hh must be computed for each time step during the production cycle by first calculating the average hot-zone fluid level.
Now the fluid level at the heated zone radius is
This procedure can be hand calculated but is much easier to use if a computer spreadsheet is used.
Jones[5] method
Jones took a similar approach to Towson and Boberg[4] in calculating oil rates as a function of gravity forces alone. He extended the model by also calculating heated-zone water rate. Information on relative permeability is necessary to accomplish this. Further, recognizing that Towson and Boberg and other similar models commonly over-predict oil production, he limited the vertical size of the zone that is invaded with steam using a version of Eq. 14.
This phenomenon is easily demonstrated by running a downhole temperature survey following a steam cycle. Then, because cold oil sand is still exposed in the wellbore, another set of equations similar to Eq. 11 is used to calculate oil and water from the cold zone. Using this modification, fluid rates can be matched quite well without need of a scaling factor to reduce predicted oil rates to realistic levels.
A convenient parameter to track, when trying to history-match a field steam cycle with this model, is produced fluid temperature that represents a combination of cold/hot oil and water.
This method does not lend itself to hand calculation and should be programmed on a computer.
Because steam only enters a small fraction of the sandface in a thick interval as in California oil fields, there is opportunity to improve performance of a steam cycle by using packers or other methods to divert steam into more of the oil zone.
Process optimization
There are always the operational questions of how much steam should be injected during a cycle; what rate should steam be injected; when should a well be resteamed; etc. Jones[5] reported the results of the use of the model previously described to history-match a massive 20-year, 1,500-well cyclic steam project in the Potter Sand in the Midway Sunset field, California. He then used the history-match information to do a long-life parametric study of the process. Table 2 lists the conclusions for this particular application. This is, however, not a common practice. There are so many variables that the results from a single well or even a small group of wells cannot be used for a meaningful history match. Further, cyclic steam is easy to apply in the field and is relatively inexpensive, so most operators simply start immediately with a field trial. Very little is published on optimizing CSS.
It is generally true of CSS that soak time should be as short as possible and that steam quality should be as high as possible. Further, efforts should be made to divert steam out of depleted zones and gas caps and into as much good oil-saturated sand as possible.
There are generally two reasons to apply CSS. First, there is the obvious stimulation of economic oil production immediately from the well. Second, because of the time delay in oil response from the initiation of steam injection into a continuous steam injector in a steamflood project, CSS concentrated in the steamflood zone is often used to accelerate project response.
Cumulative average daily profit method
Because process optimization is ultimately an economic decision, a resteaming decision can be based on the Rivero and Heintz[6] cumulative average daily profit (CADP) method. Fig. 2 shows a graphical representation of how to use this method. When steam is injected into a producer, profits of the cycle are driven negative because of the cost of the steam, costs to prepare the well for steaming, and lost production as a result of the well being shut down. Once the well is put back on production, the oil rate will peak, and daily cash flow will be at a relative high. Concurrently, CADP for the cycle will begin to increase as the daily production begins to pay for the injection costs. As the well continues to produce, the oil rate gradually falls, as does daily profit. CADP hopefully soon becomes positive, then continues to increase until it reaches a value equal to the daily cash flow. It is at this point that the well should be recycled because cash flow for the next day’s production will fall below the CADP.
Fig. 2 – Graphical representation of the cumulative average daily profit method of the recycle determination method.[6]
Although instructive as a concept for picking resteaming time, actual field application of the method is practically impossible because of ever-present problems in gathering precise enough well production gauges and in collecting all of the necessary economic data in a timely manner. Also, because the method is divorced from the reservoir process, it may lead to short-term economic decisions that damage the reservoir.
Sequential CSS method
In a large CSS project, one needs a way to decide which well to steam and in what sequence. McBean[7] and Jones and Cawthon[8] presented a sequential CSS method that ensures that all wells will be stimulated in a timely manner and takes advantage of the interwell stimulation often observed.
By steaming wells in a sequential manner from downdip to updip as shown in Fig. 3, they observed not only the oil response from the steamed wells but also some response from offset wells caused by a mini-steamflood. Kuo et al.[9] found in numerical simulations that small cycles in closely spaced wells are preferable in this process. Field experience in the sequential CSS project confirmed that finding with wells drilled on 5/8 acre (0.25 ha) spacing.
Fig. 3 – Well steaming schedule for the sequential steam method of cyclic steam design.[8]
Nomenclature
References
- ↑ Prats, M. 1982. Thermal Recovery, No. 7. Richardson, Texas: Monograph Series, SPE.
- ↑ 2.0 2.1 Owens, W.D. and Suter, V.E. 1965. Steam Stimulation—Newest Form of Secondary Petroleum Recovery. Oil & Gas J. 90 (April): 82.
- ↑ 3.0 3.1 Boberg, T.C. and Lantz, R.B. 1966. Calculation of the Production Rate of a Thermally Stimulated Well. J Pet Technol 18 (12): 1613–1623. SPE-1578-PA. http://dx.doi.org/10.2118/1578-PA
- ↑ 4.0 4.1 Towson, D.E. and Boberg, T.C. 1967. Gravity Drainage in Thermally Stimulated Wells. J. of Canadian Petroleum Technology (October–December): 130.
- ↑ 5.0 5.1 Jones, J.A. 1992. Why Cyclic Steam Predictive Models Get No Respect. SPE Res Eng 7 (1): 67–74. SPE-20022-PA. http://dx.doi.org/10.2118/20022-PA
- ↑ 6.0 6.1 Rivero, R.T. and Heintz, R.C. 1975. Resteaming Time Determination-Case History Of a Steam-Soak Well in Midway Sunset. J Pet Technol 27 (6): 665-671. SPE-4892-PA. http://dx.doi.org/10.2118/4892-PA
- ↑ McBean, W.N. 1972. Attic Oil Recovery by Steam Displacement. Presented at the SPE California Regional Meeting, Bakersfield, California, 8-10 November 1972. SPE-4170-MS. http://dx.doi.org/10.2118/4170-MS
- ↑ 8.0 8.1 Jones, J. and Cawthon, G.J. 1990. Sequential Steam: An Engineered Cyclic Steaming Method. J Pet Technol 42 (7): 848-853, 901. SPE-17421-PA. http://dx.doi.org/10.2118/17421-PA.
- ↑ Kuo, C.H., Shain, S.A., and Phocas, D.M. 1970. A Gravity Drainage Model for the Steam-Soak Process. SPE J. 10 (2): 119-126. SPE-2329-PA. http://dx.doi.org/10.2118/2329-PA
Noteworthy papers in OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
Hascakir, B., Kovscek, A., Reservoir Simulation of Cyclic Steam Injection Including the Effects of Temperature Induced Wettability Alteration, SPE Western Regional Meeting, Anaheim, California, USA, 27-29 May 2010, SPE 132608., https://www.onepetro.org/conference-paper/SPE-132608-MS
External links
Xiong, Hongjie. 2017. "Optimizing Cluster or Fracture Spacing: An Overview." The Way Ahead. Society of Petroleum Engineers. https://www.spe.org/en/twa/twa-article-detail/?art=3007
See also
Thermal recovery by steam injection
Steam delivery systems for EOR
PEH:Thermal_Recovery_by_Steam_Injection