A Current Review of Oil Recovery by Steam Injection

A CURRENT REVIEW OF OIL RECOVERY BY STEAM INJECTION

Abstract In the last three years, oil recovery by steam injec-

tion has become recognized as a process of major importance in several areas of the world. The reason for this increase in importance is the development of a cyclic-injection-production process known variously as : cyclic steam injection, steam “soaking”, “huff-and- puff’, steam ‘‘push-pull’’, and numerous other names. A current review of field experience with this process in various parts of the world is presented. There is a curious paradox in regard to literature concerning continuous and cyclic steam injection. Most papers concerning continuous steam injection are theoretical in nature, while most reports concerning cyclic steam injection report field results with no detailed description of the mechanism. In regard to ultimate oil recovery, the consensus seems to be that cyclic steam injection is principally a stimulation technique to be used in conjunction with some other type of fluid injection, or reservoir drive. A discussion is given of the potential importance of steam injection oil recovery as compared to combustion oil recovery.

Résumé Dans les trois dernières années, la récupération du

pétrole par injection de vapeur est apparue comme une méthode d’importance capitale dans plusieurs régions dans le monde. La raison de cette importance accrue est le développement d’un procédé cyclique d’injection et de production désigné de diverses mani- ères: injection cyclique de vapeur, lessivage à la vapeur, “huff and puff’, vapeur “va et vient”, etc. On présente une revue de l’utilisation de ce procédé dans différentes régions du monde. Une remarque curieuse se dégage de la littérature relative à l’injection continue et à l’injection cyclique de vapeur. La plupart des publications sur l’injection continue de vapeur sont de nature theorique, alors que celles traitant de l’injection cyclique décrivent des résultats d’exploitation sans entrer en détail dans la description du mécanisme. En ce qui concerne la récupération de l’huile, l’avis général qui semble ressortir est que l’injection de vapeur cyclique est essentiellement une technique de stimulation qui doit être utilisée en combinaison avec une autre méthode d’injection de fluide ou de drainage du réservoir. On présente une comparaison des per- spectives d’avenir des méthodes de récupération par injection de vapeur et par combustion souterraine.

INTRODUCTION

People involved in the mineral extractive industries have usually been ingenious. For this reason it has been almost impossible to determine “first” application of oil recovery processes such as hot fluid injection. For example, Barb and Shelley’ in 1930 discussed the use of hot water for flooding and stated: “There is a rumor that hot water (injection) was used on a property in New York State but was abandoned because of the excessive cost.” The point is that the idea of injecting hot fluids is quite old. But serious interest in this class of oil recovery processes is recent. The main reason has been increasing awareness of the huge quantity of unrecoverable oil in the world.

Within the last three years, oil recovery by steam

by H. J. RAMEY, Jr., Stanford University, California, U.S.A.

injection has become recognized as a process of major importance in several areas of the world. Although there is great enthusiasm within these geographic areas, there is reluctance to publish engineering information of potential competitive value. Thus broad scepticism by engineers outside areas of current application still exists. The purpose of this paper is to review current information concerning oil recovery by steam injection.

“Steam” injection is a misleading name. This name has been applied mainly to injection of two-phase mixtures of hot water and steam, although hot water injection, and superheated steam injection have also been included. There is a further complication in that the mode of injection provides another classification. Continuous injection of hot fluid from an injection well to a production well is an old process, but a cyclic process involving injection of a batch of steam into a single well followed by a production period is the most important process currently. This process has been

47 1

472 New Mefhods in Secondary Recovery

named variously as : steam-soaking (because a shut-in or “soaking” period following steam injection is often used), cyclic steam injection, “push-pull” steam injection, “huff-and-puff”, and by many other colloquial names. This cyclic injection process has been so successful in California in the United States, that it is one of two factors given credit for a sudden increase in the state’s oil prod~ction’.~. Cyclic steam injection has also been used successfully in Venezuela4.

Fortunately, a great deal of information on the cyclic steam injection process has become available recently. However, a curious problem exists. Papers dealing with continuous steam injection have almost all been of a theoretical nature, while papers concerning cyclic steam injection are mostly practical field case histories.

A brief history of hot fluid injection will help provide a frame of reference for current practices. Then a summary of theoretical material will be presented. Finally, a discussion of field case histories of steam injection will be reviewed.

HISTORY

Interest in hot fluid injection to recover oil has been apparent since the early 1930’s. It is likely that an early publication concerning hot water injection by Schaller and Bjornsson in 1923 was a stimulus. In 1934, Stoval16 described both laboratory and field trials of steam injection. The work was described as initiated in 1926, leading to a field trial in 1931. This work was remarkable. It is clear that Stovall under- stood ali of the important technical features of continuous steam injection. Injection of hot, non- condensable gas was described by Lindsly in 1928’. In- terest in hot gas injection was related to development of the Marietta process: air injection at low rates and pressures to improve oil recovery. (See reference 1 for a complete case history of one Marietta process application.) In regard to hot gas injection, it was discovered early that the low sensible heat of non-condensable gases (flue gas, natural gas) made these fluids poor heat exchange mediums. Lapuk* published an excellent review of early work in thermal recovery in 1939. In it he described hot air injection field tests where low- melting temperature alloys in an injection well had indicated that heat was not reaching the depth of the formation interval. Lapuk also described casing thermal expansion of more than one foot-a commonly recognized problem today. During the 1940‘s, several interesting article^^.'^ reported hot air injection field tests by E. W. Hartman near Bartlesville, Oklahoma. It appears Hartman was successful in transporting heat to the formation and may have ignited the oil and

moved a combustion front. On the other hand, a hot (450°F) natural gas injection project’ conducted in the early 1950’s resulted in no detectable temperature increase at a depth of i300 feet after more than one year of injection.

There were several different ideas involving hot fluid injection described during the 1950’s. Breston and PearmanI2 described injection of hot water to increase injectivity of water into tight sands. Injection of warm water13 in Pembina field, Canada, was proposed to guarantee that water would enter the formation at formation temperature. Finally, injection of hot crude oil in wells in California as a stimulation treatment was described’ ’.

During the 1950s, a number of publications concerning theoretical aspects of heat transport involved in hot fluid injection began to appear in the literature. These will be listed later in this paper. At the same time rumours began to circulate in the industry concerning steam and hot water injection field testing of a con- fidential nature. Thus it is not possible to draw a distinctive line separating historical and modern hot fluid injection. Elkins14 did consider this problem, and concluded that the end of the Second World War was significant. The availability of manpower for research and the realization of low oil recovery and decreasing exploration potential led to intensive industry effort on oil recovery. Potential benefits to the industry are considerable. It has been estimated’ that in excess of 150 billion barrels of heavy oil remain in place in currently-producing reservoirs in the United States alone. This does not consider known tar and oil shale deposits which have not been produced.

The fact is that responsible agencies are currently considering significant portions of this oil recoverable. The main reason for this optimism is the remarkable result of cyclic steam injection in California and Venezuela. Rumored results of cyclic steam injection in California led to widespread use of the process in i 963. Within the last year, publications citing factual results have begun to sppear.

THEQRY OF CONTINUOUS INJECTIQN

Heat transport is a prime consideration because the goal is to inject thermal energy into an oil reservoir using a hot fluid as the transport medium. Since the potential benefits of heating were presented at the 6th World Petroleum Congress16, attention will be restric- ted to the mechanics of the heat transport and fluid flow problems involved. First, hot water or steam have become the most important heat transport mediums- because of high heat content, availability, and usually moderate cost. The steam generators in use in oil field

‘New Methods in Secondary Recovery 473

operations are single-pass, high efficiency units (70 to 80 % thermal efficiency). Many recent publications‘ 7,1 deal with details of-these units. Because the economic success of steam injection usually depends upon efficient operation and maintenance of the steam generators, operators are justified in spending much attention on the unit. The most important problems associated with the steam generators have been : availability and cost of fuel, fuel type, availability and cost of feedwater, need for water treating, operator attention, and maintenance of the unit.

Once steam or hot water has been generated, heat transmission becomes important through the heat loss involved in piping hot fluid to the formation. These losses include: heat loss from surface lines, heat loss from the tubing or casing within the wellbore, and finally, heat loss from the heated portion of the formation.

HEAT TRANSMISSION

Heat losses from surface lines from the steam generator to the wellhead may be evaluated from existing technology developed for process steam piping. A useful summary of this type of information is available”. In general, surface piping heat loss depends on pipe size, length, insulation, and temperature levels. I t is influenced only indirectly by steam flow rate. The order of magnitude is roughly 0.1 MMBtu/d per 100 ft. of line length to 1 MMBtu/d per 100 ft. of length. This order of magnitude is not significant for the sizes of steamgeneratorscommonly in use: 10to25MMBthu/h.

Heat will also be lost during passage of the hot fluid down the well because the fluid temperature is much higher than geothermal temperatures. The first publication dealing with this problem in connection with hot water flooding was published by Moss and White” in 1959. Since publication of two papers in 196221.22 dealing with wellbore heat losses in hot water and steam injection, there has been a steady flow of publications on this subject. The wellbore heat problem is of great interest from the standpoint of temperature of wellbore metal goods as well as heat loss. Steel expands approxi- mately 0.8 inch per 100°F per 100 ft. of length if unrestrained. If restrained, heating causes an increase in stress of roughly 10,000 psi for 50°F increments of temperature increase. Field experience is that tubular goods may rise as much as 3 feet or more out of the ground during steam injection. In many cases, the pipe will contract back into the ground upon cooling without apparent damage to the well. But there have also been an increasing number of serious well failures upon steam injection.

In regard to order of magnitude of wellbore heat

losses, reference 19 presents convenient summaries of information. Values of 0.5 MMBtu/d per 100 ft. of depth are not uncommon. Again, this order of magnitude is not critical for steam generation system capaci- ties of IO to 25 MMBtu/h. On the other hand, it is apparent that it may be difficult to move heat to significant depths with hot, non-condensable gas injection.

Assuming that it is possible to move significant quantities of heat to the sand face by hot water or steam injection, the problem remaining is the most complex one considered so far. The problem involves the non- isothermal transient flow of two or three immiscible fluids through porous media. That is, the coupled Aow of heat, oil, water, and possibly steam. The usual attack taken on this problem has been to separate the heat and fluid flow aspects of the problem and consider each separately. In regard to the heat flow problem, the approach has generally been to consider thermal properties of formation and adjacent strata to be con- stants (but perhaps different), and make a heat balance considering injected heat distributed between advancing the heated zone in the formation and supplying heat lost to the adjacent strata. The first significant study of the magnitude of the heat loss from the interval to adjacent strata was presented by LauwerierZ3 in 1955. Lauwerier assumed that injection rate and temperature would remain constant, vertical heat flow was in parallel rays normal to fluid flow, the flow system was linear, and that heat in injected fluid was sensible heat only. Thus loss of heat from the injected fluid would result in a decrease in temperature as opposed to the possibility of condensation of steam. In 1959, Marx and LangenheimZ4 presented a solution for a heat loss problem similar to that considered by Lauwerier- except that the temperature in the heated region was held constant. Physically, this would imply a case close to steam injection. These two cases are particu- larly interesting for several reasons. First, it was pointed out in a discussion that the Marx-Langen- heim solution was extraordinarily general and inde- pendent of the flow system geometry. Second, it was later shown that both solutions indicated the same cumulative heat loss to adjacent strata”. The last fact was surprising because Lauwerier’s solution indicated a decreasing temperature distribution in the direction of flow, while the Marx-Langenheim solution assumed the heated region to remain at a constant elevated temperature. In 1959, R ~ b i n s h t e i n ~ ~ published a more complete

analysis of the vertical heat loss for hot water injection conditions. Rubinshtein did not assume the vertical heat loss to flow normal to the direction of fluid flow, and relaxed other assumptions as well. Rubinshtein did not compute the temperature field, but did deter-

414 New Methods in Secondary Recovery

mine the fraction of the cumulative heat input lost to adjacent strata by integration of the temperature distributions. This fraction has been called the “integral heat loss” by some authors26. Rubinshtein’s mode of presentation of vertical heat loss as the fraction of cumulative heat loss as a function of a dimensionless time has been applied to both the Lauwerier and Marx- Langenheim solutions to provide a ready means for c~mparison’~*~’. Recently, a number of publications have reviewed various studies of vertical heat ~ O S S ~ * * ~ ~ . In addition, other studies of vertical heat losses have recently appeared2 6 * 3 O.

In regard to order of magnitude, the vertical heat loss is very important. Although the thermal conductivity and thermal diffusivity of the earth are quite low, the area heated from the injection well to the heat front may be on the order of acres. Theoretical solutions such as those described above indicate the fraction of the cumulative heat lost by vertical conduction may easily be half or more of the cumulative heat input.

In general, vertical heat loss solutions employing the “integral heat loss” and time do not contain a term involving the heat injection rate. On the other hand, the vertical heat loss fraction is a monotonic-increasing function of time. Clearly, low injection rate requires long operating time, and high integral heat loss. In hot fluid injection, it is extremely desirable to operate at as high an injection rate as is practical within other limits.

it is interesting to note that Stoval16 made experi- mental measurements aimed at determination of both wellbore heat loss and vertical heat loss from the formation during his pioneer steam injection field test in Texas.

OIL DISPLACEMENT BY HOT FLUIDS

The theoretical analysis of heat flow in the formation described above generally ignores fluid movement, and the possibility of compositional changes in the fluid stream. One of the earliest studies of oil recovery by hot water injection was presented by Van Heiningan and Schwarz3’ in 1955. The heat flow and fluid flow were analyzed separately. Marx and Langenheim later suggested that oil recovery be estimated by applying an oil recovery factor to the volume heated determined by heat flow calculations. F a y e r ~ ~ ~ presented a justifica- tion for separation of the heat and fluid flow portions of the problem in 1962.

Although there have been a number of studies of hot water displacement of oil in laboratory flood-pot studies 33,34*35*36 by far the most thorough study ofoilrecovery by hot water and steam injection was presented by Willman et al3’ in 1961. Laboratory tests of cold water,

hot water, and steam injection with a variety of cores and test oils were conducted. Willman et al. found that hot water flooding results could be forecast on the basis of thermally-reduced viscosity, and thermal expansion of reservoir fluids. Steam injection appeared to have three additional oil recovery mechanisms : (1) steam distillation of residual oil left by the hot water flood, (2) a reduced residual oil from hot water flooding by virtue of oil gravity reduction through condensation of distilled light hydrocarbons, and (3) a minor effect attributed to gas-driving residual oil from hot water flooding. In regard to oil recovery, it was reported that oil recovery from laboratory hot water flood tests might be in the range of 55 to 70% of initial oil in the core, while oil recovery from steam injection floodpot tests was in the range of 60 to 90% of initial oil in place. These results do not include field conformance factors and are not representative of field results, of course.

Willman et al. proposed a hot fluid injection design method which involved coupling heat transfer results such as those described above with a frontal-advance calculation for non-isothermal displacement. This method was recently applied by Donohue3’ to field test design.

In the Willman et al. study, there was a clear implication that relative permeability is not affected seriously by temperature change. A series of recent s t ~ d i e s ~ ~ * ~ ~ * ~ ~ indicate the likelihood that such is not the case.

FIELD RESULTS

Modern hot fluid injection interest initially concerned continuous injection in a normal flooding pattern. Hot water injection in the Schoonebeek Field, Holland, was started in the mid 1 9 5 0 ’ ~ ~ ~ , and operations in Venezuela and California started in the late 1950’s. But interest shifted to a cyclic injection-production process in the early 1960’s. As a result, there is very little field data on continuous hot fluid injection available. Other than the Stovall field test mentioned previously, attention is called to references 40*41 s4’. Thereis, however, a great deal of field case history availablerecently for the cyclic steam injection p r o c e ~ s ~ ~ - ~ * .

Although there have been large variations in detail, the basic principles of the cyclic steam injection process appear reasonably uniform. As much as 15,000 barrels (measured as feedwater) of an 80% quality steam is injected into a well during a period of one to two weeks. The well is then shut-in and pressure declines during a “soaking” period of about one to five days. The well is then returned to production. The initial oil rate is often twenty times the rate before steam injec-

New Methods in Secondary Recovery 475

tion, but declines rapidly to a level about ten times the pre-injection rate. Production continues to decline over a period from two to seven months as wellhead temperature declines. The cycle of steam injection- production is then repeated. Production data for as many as six cycles have been presented45. Perhaps the most useful information available on this process have been summary tables of performance for a large variety of well treatment^^^. Key information such as barrels (as feedwater) of steam injected per barrel of incremental oil produced have been reported. For successful operations, this ratio has been as low as 0.3 barrels (as liquid feedwater) of steam per barrel of incremental oil produced, although usually higher. In California, steam costs from $0.25 to $0.35 per barrel feedwater have been reported. Large ranges in steam generation cost would be expected in view of the large range in cost of fuel, supply water, and treating costs.

One reason for the immediate acceptance of cyclic steam injection is that a single steam generator may service a large number of wells. Another reason is that, if successful, increased oil production happens im- mediately. I t is not necessary to wait for a fillup period and peak production rate as would be likely the case in a continuous injection operation.

Surprisingly, case histories of successful field use were available before any significant theoretical work on this process was published. To date, only limited design information is available. Owens and Suter” offered probably the original analysis of cyclic injection. These investigators concluded that viscosity reduction coupled with wellbore cleanup pro- vided the major benefit. Several other papers concerning cyclic steam injection performance have recently become available5 l .

In regard to field experience with successful cyclic steam injection operations in California, recent publi- c a t i o n ~ ~ ’ . ~ ~ indicate the following. Steam generators rated as high as 2500 psi have been installed. In regard to formation selection criteria : maximum formation depth of 3000 ft., net sand thickness of at least 50 feet with no maximum limit to thickness, good reservoir pressure (some as low as 40 psi), and well condition should be good49.54.

It appears that most field applications have been made on a trial basis. Without question, very important operating problems have been recognized. In the San Joquin Valley in California, adequate feedwater supply and treating has been a serious problem. This has led to novel agreements for purchase of municipal waters and to development of steam generators capable of handling very poor feedwater. Another serious problem has been well failure due to the effect of high temperatures and cyclic heating.

RECOVERY AND ECONOMICS

Remarks will be confined mainly to cyclic steam injection. Although none of the field case histories reported so far have been produced to abandonment, there have been several mentioris of estimated oil recovery under cyclic steam injection. These range from 5 to 40 percent of the oil in place at the start of steam injection. Clearly, experience with this process has been of limited time duration. It would be necessary to make significant extrapolations to obtain such data. Nevertheless, there is a feeling among some Cali- fornia operators that Cyclic steam injection alone will not be the ultimate thermal oil recovery process in the California area. Although cyclic steam injection will undoubtedly increase oil recovery, it is stili re- garded as largely a stimulation treatment. Thus it should not be surprising that combination combustion-cyclic steam injection projects55 have been insti- tuted in California, and combination continuous- cyclic steam injection operations have been proposed for Texas56.

In regard to economics of steam injection, several concluding remarks are in order. It has been estimated that the average steam generator in California is barely economic. Many operators have reported complete failures: either the wells did not respond, or a costly well failure interrupted oil production. Clearly, important technical problems will have to be solved before use of the cyclic injection process is elevated above a trial-and-error approach. On the other hand, phenomenal economic success has also resulted.

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College Mineral Industries Experiment Station Bulletin 6, 1930.

2. ARMSTRONG, T. A., Oil Gas J., 7.2.66, 64 (6), 54-55. 3. ARMSTRONG, T. A., Oil Gas J. , 26.9.66,64 (39), 47-49. 4. PAYNE, R. W., and ZAMBRANO. Ci.. Oil Gas J.. 24.5.65,

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10. GIBBON, A., Oil Weekly, 6.11.44, 170. 1 1 . NELSON, T. W., and McNIEL, J. S. , Jr., Petrol. Engr.,

Feb. 1959, 31 (2), B-27; Petrol. Engr., Mar. 1959, 31 (3). 12. BRESTON, J. N., and PEARMAN, B. R., Prod. Mon., Nov.,

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ABSTRACTO

Una Revision de Actualidad de la Recuperacion de Petroleo por Injeccion de Vapor

En los últimos tres años la recuperación de petróleo por inyección de vapor ha sido reconocida como un proceso de primordial importancia en varias areas del mundo. La razón de este incremento en importancia, es debido al desarrollo de un proceso de producción mediante inyección cíclica, conocido indistintamente como: inyección cíclica devapor, embebido por vapor, “huff and puff’, e inyección y extracción de vapor, vapor de “push and pull” entre otros numerosos nombres. Se presenta una revisión de actualizada de la experiencia en el campo obtenida con este proceso, en

38. DONOHUE, D. A. T., J. Cunud. Petrol. Tech., Oct.-Dec.

39. KASTROP, J. E., Petrol. Engr., Nov. 1963, 35 (12), 21-35. 40. DOSCHER, T. M., et al., Petrol. Engr.. Jan. 1964,36 (i), 71. 41. JURANEK. J. U.. Neft.1 Gaz.. 1963. (71. 69-70.

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42. EMERY. M. N.. Petrol. EnPr.: Sent: 1966. 38 (10). 63-67. 43. LONG, R. J., J.’Petrol. Tech.,’Sepí. 1965,’17 (9), 989-998. 44. KEPLINGER, C. H., Prod. Mon., May 1965,29 (5), 14-21. 45. McLAREN, G. R., and PRICE, E. O.. Oil Gas J., 11.7.66,

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51. DOSCHER, T. M., Oil Gus J. , 22.11.65, 63 (47), 58-61 ; 11.7.66,64 (28), 95.

52. DIETRICH, W. K., and WILLHITE, G . P., API Preprint No. 875-20-H, Rocky Mt. Spring Dist. Mtg., Casper, Wyoming, April 1966.

53. PAMENTER, C. B., Can. Petrol., May 1966,7 (5),37-38. 54. RINTOUL, B., Culif. Oil World, 31.1.66, 59 (2), 18. 55. CADY, G . V., and SCARBOROUGH, R. M., API Pre-

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varias partes del mundo. Existe una paradoja curiosa en relación con la literatura relativa a la inyección de vapor continua y cíclica. La mayoría de los informes concernientes a la inyección de vapor continua es teórica por naturaleza, mientras que la mayoría de los reportes relativos a la inyección de vapor cíclica, presentan resultados de campo con una descripción sin detalles del mecanismo. En relacióncon la recuperación final del aceite, el epílogo parece indicar que la inyección de vapor cíclica es principalmente una técnica de estímulo, para ser usada en conjunto con algún otro tipo de inyección de flúidos o ampuje del yacimiento. Se presenta una discusión de la importancia potencial de la recuperación de petróleo por inyec- ción de vapor, comparada con la recuperación obtenida por el método de combustión.

Documents

A Current Review of Oil Recovery by Steam Injection