Steam Soak Research Articles

Pilot Steam Soak Operations in Deep Wells in China

Most the heavy-oil deposits in eastern China are buried fairly deep. Laboratory research and field pilot tests on four relatively deep oil reservoirs have been carried out since 1982. Gaosheng reservoir is 1500 to 1700 m (4,921 to 5,576 ft) deep and the other three reservoirs are 1000 to 1300 m (3,281 to 4,265 ft) deep. Viscosity values of oils at formation temperature are 1000 to 10 000 mPa (1,000 to 10,000 cp). By the end of May 1985, 123 steamsoak operations had been carried out on 101 wells, with a cumulative oil production of 330X10/sup 3/ Mg (330,000 tonnes) and the corresponding amount of steam injected was 220X10/sup 3/ Mg (220,000 tonnes). These operations were carried out mainly in three oil fields in the Liaohe area. These three fields with reservoirs at 1000 to 1300 m (3,281 to 4,265 ft) were almost nonproductive before, but generally a peak production of 100 to 200 Mg/d (100 to 200 tonnes/D) per well was obtained after steamsoak. Although low-quality steam was injected in the wells in the Gaosheng oil fields, good stimulation responses were still obtained. Physical modeling and mathematical simulation on the wellbore heat transfer show that steam injection is feasiblemore » in the four oil fields by use of heat insulation techniques in the wellbores, and also feasible for long-term steamflooding. This paper presents the results of optimization of the steam injection parameters by physical modeling and mathematical simulation studies, e.g., steam quality, injection rate, and amount of steam injected in each cycle.« less

Tar Sand Research and Development at the University of Utah

The recovery of hydrocarbon values from the extensive tar sand deposits of North America has generally been approached by one of two methods: in situ thermal production of the bitumen or of a bitumen-derived liquid or surface mining of the deposit followed by processing of the mined ore. In either approach the produced hydrocarbon liquid must be upgraded to give a suitable feedstock for subsequent processing in a conventional petroleum refinery. The in situ thermal methods that have been applied to tar sands include steam soak, steam drive, and in situ combustion, all of which have been extensively used in enhanced oil recovery of heavy oils (^20 °AP1). The selection of the appropriate thermal method for a specific reservoir or deposit is based on established reservoir screening parameters, including viscosity and gravity of the reservoir fluid at the reservoir temperature and pressure, permeability and depth of the reservoir, geology and mineralogy of the reservoir, and the reservoir temperature and pressure. Surface mining-bitumen recovery methods all involve mining of the tar sand deposit, transportation of the mined ore from the deposit to the processing facility, separation of the bitumen from the sand substrate, disposal of the spent sand, and upgrading of the bitumen or bitumen-derived hydrocarbon liquid. The bitumen may be recovered by one of the following methods:

EXPLORATION AND EVALUATION OF THE ZUATA AREA, ORINOCO OIL BELT, VENEZUELA

Exploration activity in the Zuata area within the Orinoco Oil Belt in Venezuela has included the drilling of 161 wells and the recording of 3,000 km of seismic lines. Based on these results, a productive area of 9,200 sq. km has been defined, containing 79.3 B cu.m. (499 B brl)† of crude oil in‐place, with densities ranging from 1.021 to 0.934 g/cu.cm (7–20 °API).The principal productive sands are of the Tertiary Officina Formation, deposited during a transgression which occurred in the Miocene. A distinctive feature of the productive formation is its progressive onlap against older rocks (Cretaceous, Paleozoic or Pre‐Cambrian) in a southerly direction which, together with overlying shales, provide the trapping mechanism for the oil which migrated from the north. The productive sands were deposited in a fluvial to coastal plain with deltaic developments. The sands are unconsolidated and fine‐ to very coarse‐grained, with an average porosity of 34% and a permeability of 7μm2(7D). The structure is a monocline dipping 0.5° to 2° to the NE, and the trapping mechanism is principally stratigraphic. In the 134 producers, 300 tests were completed which resulted in an average production of 25 cu.m/d (160 b/d) per well by beam pumping without dilution or heat. Subsequently, a steam cycle of 5,000 metric tons was injected into 16 wells; production increased to some 200 cu.m/d (1,250 b/d) per well.For future development, a Priority Area has been selected: this Area covers 3,500 sq kin, and contains 40.5 B cu.m (255 B brl) of crude oil with a density range of 1.014 to 0.993 g/cu.cm (8–11°API). The oil is at an average depth of 610 m, and the average net oil‐sand thickness is 60 m. The oil‐sand is generally divided into three zones separated by shales, and the gross productive thickness is some 110 m.Similar to Maraven ‘s experience in the oilfields of the Bolivar Coast in Western Venezuela, it may be expected that reservoir compaction will occur, and will be efficiently activated by steam‐soak or “huff and puff’. Based on core compressibility measurements, a recovery factor from compaction drive and solution gas treatments could reach 12 % of the oil in‐place. Under this premise, the Priority Area could have a potential recovery of 4.9 B cu. m. (30.6 B brl), which could support a production of 160,000 cu.m/d(1MM b/d) for 100 years. Any follow‐up steam drive can be assumed to recover at least an additional 10% of the oil in‐place.A Conceptual Development Plan based on clusters, inclined wells (due to the shallow depth) and steam soak has been proposed, and will be validated by a pilot test consisting of a seven‐well cluster.

Geological Evaluation of San Diego Norte Pilot Project, Zuata Area, Orinoco Oil Belt, Venezuela

The San Diego Norte Pilot Project consists of twelve inclined wells (7 producing wells 300 m (984 ft) apart, plus 5 observation wells) drilled from a cluster, to study the production and compaction behavior under steam soak (huff and puff) of the Tertiary heavy crude oil reservoirs of the Zuata area. This area is located within the Orinoco Heavy Oil belt of Venezuela. A geological model was needed as a base for the reservoir studies and to understand the geological setting. This model was constructed from extensive log information, seismic lines, well samples, and cores. The reservoir sands are friable with an average porosity of 34% and permeabilities ranging from 1 to 7 µm2 (1 to 7 darcys). The sands were deposited in meander belts that stacked up forming multistory bodies. Point bars and channel fills account for 80-90% of the total sand. These sands are internally heterogeneous, sinuous and elongated, and larger than the 1 km2 area covered by the project. The topmost two productive sands, which together average 22 m (72 ft), show the best porosities and permeabilities and are isolated by thick clays that make them suitable for selective steam injection. In the project, the oil has a density of about 1.0 g/cm3 (10° API) and fills all the sands down to the oil-water contact. The depth of this contact is controlled by regional faults. Based on core compressibility tests, compaction is expected to be the principal production mechanism that could increase the expected primary recovery of 4 to 12% by huff and puff steam injection, leading to a possible recovery of 0.64 × 106 m3 (4 million bbl) in six years with four cycles of steam injection.

Steamflooding

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Steamflooding has become an established recovery technique within the last20 years. This overview discusses its evolution, methods for selecting and designing steamfloods, constraints, and possible improvements. The term steamflooding is used here in a general sense. The discussion includes steamsoak (cyclic steam injection) and steam drive. For additional information the reader should refer to Farouq Ali and Meldau. Early Developments: Steam Soak There are records of steam injection into a Texas oil reservoir as far back as 1931. Steam drive on a sustained basis, however, did not begin until 1959–60 when Shell affiliates undertook steamflood pilots in Schoonebeek, the Netherlands, Mene Grande, Venezuela, and Yorba Linda, CA. Steaming operationsstill under way at Schoonebeek and Yorba Linda are discussed later. Venezuela. The steamdrive pilot in Mene Grande led to development of the steamsoak process. While attempting to relieve the formation pressure by opening a steam injector to production, oil was produced surprisingly at a rate of 100 to 200 B/D. produced surprisingly at a rate of 100 to 200 B/D. This was the first steamsoak well. This process underwent considerable development in both Venezuela and the U.S. Most of the oil produced by steam from 1960 to 1970was by this process. Typically, steam is injected for several weeks and then the well is closed in (soaked) until the steam has condensed, A pump then is run and the well is placed on production. When oil production falls to a lowlevel, the cycle is repeated. Thermal production in Venezuela is still almost entirely (95%) from steam soak. Compaction of these thick, unconsolidated sands together with solution-gas drive is leading to satisfactory oil recovery atvery high ratios of oil recovered per barrel of steam used. The Netherlands. One of the first large-scale steam drives began at the Schoonebeek field in The Netherlands in 1960. Recovery of the moderately viscous oil (180 cp) was quite successful. This encouraged additional fieldtrials of steam drive in the U.S. and in Venezuela. Coring showed that steamwas achieving low residual oil saturations of the order of 8%. The residual oilin the zone swept only by hot water was about 35%. Later tests at Schoonebeek were carried out at high pressure and high temperature. Under these conditionsCO2 and H2S are generated in situ. Consequently, new alloys had to bedeveloped. Thus, Schoonebeek led to pioneering along both reservoir andmetallurgical lines. U.S. Commercial steamflooding began in the U.S. in 1960 in the Yorba Lindafield, CA. JPT p. 237

Zone 1 Steam Project, Coalinga Field

Summary This paper discusses thermal development, both steam soak and steam drive, of the Temblor Zone 1 reservoir in Coalinga field, Fresno County, CA. Zone 1 is a thick, multilayered; steeply dipping reservoir. It contains a 12 degrees API (973 kg/m3) oil and its viscosity averages 3,000 cp (3 Pa.S) at reservoir conditions. Zone 1 has been producing on primary since the early 1930's, but cumulative production has been very small as a result of low reservoir pressure and high crude viscosity. Attempts at thermal production were made in the 1960's and early 1970's, but they were unsuccessful. Results of recent activity indicate that both steam soak and steam drive are applicable to the Zone 1 reservoir at Coalinga; however, it appears that a combination of steam drive and steam soak is the most desirable process. The reservoir now is being developed as a full-scale steam drive project. Introduction The Coalinga field is midway between Los Angeles and San Francisco. It has been producing since the 1890's and to date almost 700 MMbbl (111 × 10 to the 6th m3) of comparatively light [20 degrees API (934-kg/m3)] oil have been recovered from its Zone 2 reservoir. Large volumes of heavy oil in the Zone 1 and Etchegoin reservoirs have been produced only recently. This paper refers to the Zone 1 formation underlying a productive area of approximately 300 acres (121 ha) in Sections 29, 30, and 32 as shown in Fig. 1. Zone 1 is a shallow marine deposit. It is productive at various locations in the Coalinga field. It is about 300 ft (91 m) thick; however, the lowermost third of the section is tightly cemented and considered nonproductive. The reservoir rock averages about 200 ft (61 m) in thickness with net pay up to 150 ft (46 m). The reservoir is a layered system containing up to five distinct members separated by silts or diatomites. Fig. 2 shows a composite type log from a typical well in Section 29. The productive reservoir ranges in depth from 800 to 1,700 ft (244 to 518 m) and dips at 21 degrees (0.37 rad) to the southeast. It is limited by a depleted zone updip and an oil/water contact downdip. The accumulation is separated from the overlying and underlying formations by shales. It outcrops to the northeast, but is thought to be sealed completely by crushing, folding, and inspissation. Zone 1 subcrops to the northwest and appears to be continuous into Section 31. It is estimated that there are 50 MMbbl (8 × 10 to the 6th m3) of oil currently in place on Sections 29, 30, and 32. Fig. 3 shows a net pay isopach of Zone 1 and the wells completed in it. Table 1 lists some of the pertinent reservoir rock and fluid properties. Previous Recovery Attempts Primary development began during the 1930's but with very poor results caused by the highly viscous nature of the crude. Cumulative primary production has amounted to 1.7 MMbbl (0.27 × 10 to the 6th m3) from 52 wells. Attempts at both steam soaking and steam driving Zone 1 were made during the 1960's and early 1970's. During early 1961, a 1 1/2-acre (0.61 -ha) inverted five spot steam drive pilot consisting of one injector, three producers, and four observers was begun. The pilot responded in the dip direction with both increased temperature and increased oil production. No production or temperature increases were seen in the strike direction. Cumulative production as of Jan. 1, 1980, amounted to 65 Mbbl (10 × 10 to the 3rd m3) at an oil/steam ratio of 0.34. On the basis of pilot results. it was decided to try a full scale pilot, but with a line drive pattern. Unfortunately, this second pilot was placed in a then unknown depleted zone and was a complete failure, producing no additional oil. It was run during 1963 and 1964. During the early 1970's, four steam soak wells were completed in Zone 1. They were completed in the lowermost 50 ft (15 m) of the productive Zone 1 interval and given 10,000-bbl (1600-m3) soaks. JPT P. 511^

Influence of Silt Zones on Steam Drive Performance Upper Conglomerate Zone, Yorba Linda Field, California

Influence of Silt Zones on Steam Drive Performance Upper Conglomerate Zone, Performance Upper Conglomerate Zone, Yorba Linda Field, California This paper describes steam drive and production performance in California's Yorba Linda field where silt layers are discontinuous and create localized barriers to vertical permeability. Improved recovery was obtained by selection of proper injection and production points with respect to the position of silt layers within the reservoir. position of silt layers within the reservoir. Introduction The Yorba Linda field is located on the eastern edge of the Los Angeles Basin, approximately 30 miles southeast of central Los Angeles (Fig. 1). It is producing 12 to 15 deg. API gravity oil from Pliocene submarine fan channel turbidites. Production is from five separate reservoirs, ranging in depth from 400 to 2,500 ft (Fig. 2). The Upper Conglomerate, located at the top of the section, has more than 70 percent of the reserves and produces the lowest API gravity oil. Net pay averages 300 ft with porosity approximately 30 percent and permeability 600 md. The present structure is a gentle homocline with beds dipping from 10 to 15 deg. to the southwest. The beds steepen to the north and outcrop within a short distance from the field. The oil reservoir is bounded by a tilted oil/water transition zone downdip and is overlain by a low-pressure desaturated (air) zone. The reservoir contains essentially no gas and gravity drainage is the producing mechanism. The Conglomerate zone was discovered in 1954 and developed by primary drilling through 1959. Because of the high viscosity of the oil, ultimate primary recovery was estimated at only 5 percent of the original oil in place. However, with development of steam soak place. However, with development of steam soak operations in 1961, the expected recovery efficiency was increased to 35 percent. During the 1960's, several steam drive pilot tests were conducted. These indicated that conversion from a steam soak to a steam drive operation at an optimum time based on heat communication in the reservoir resulted in a recovery ranging from 45 to 55 percent of the oil in place. In 1971, a pilot Upper percent of the oil in place. In 1971, a pilot Upper Conglomerate steam drive was initiated and was expanded in 1973 and 1974. Today, there are 16 permanent injectors in the Upper Conglomerate. In contemplation of a drive expansion throughout the entire Upper Conglomerate zone, a study was made to determine better the reservoir continuity. One of the most striking geological features in the field is the discontinuons nature of the silt zones. These zones were mapped and studied in relation to production performance of nearby wells. It became apparent that the silt layers greatly influenced fluid and steam migration and thus well performance. Some guidelines were established to improve well completion practices with relation to the silt zones. Silt Zone Distribution Within the Reservoir The Conglomerate zone consists of an assemblage of silts, sands, and conglomerates deposited on the eastern edge of a deep Pliocene submarine basin. A close source rock resulted in a large-size range of sediments, ranging from conglomerates to silts, being brought into the basin. The sediments are interpreted to have been carried and deposited through a submarine fan channel system that trends from northeast to southwest. The silt layers are believed to be fill deposits in abandoned channels. They are generally lenticular and discontinuous. The major silt breaks range to more than 100 ft thick and extend over one-third of the producing field. P. 1397

The M6 Steam Drive Project Design And Implementation

Abstract The M-6 steam drive project is located in the Tia Juana field, Bolivar Coast, Venezuela and is scheduled to go on stream towards the end of 1977. Primary production started in 1948 followed by a period of stea1n soak from 1969 onwards. Steam soak is favoured by the compaction process. At the start of steam drive it is estimated that the remaining reserves by compaction is some 4% STOIIP compared to a total recovery by comparison of some 20% STOIIP. The past performance amt the prediction of future performance will be discussed on the basis of the results obtained from an earlier, smaller scale steam drive project, laboratory investigations on physical models and compaction drive theory. During 1975 and 1976 an extensive programme of data gathering in the field and special production/ injection tests in wells were carried out, and a detailed geological/petrophysical study is being made. In three inverted seven spots steam is being injected continuously, the first hexagon started in November 1975 and the other two in July and August 1976. Tracers in the gaseous and aqueous phase have been injected to detect preferential flow. The results of these tests a1'e discussed. Introduction The heavy oil fields on the eastern coast of Lake Maracaibo (see Figure 1) - known as the Bolivar Coast -initially contained some 33.8 billion barrels of oil-in-place, of which only about 11% can be recovered by primary means; this figure represents an average which comprises 0% recovery for the very viscous crudes (up to 50,000 cp) in North Tia Juana, 6–7 %, in the Upper Lagunillas Heavy and up to 20% in the coastal areas. The current proven and possible reserves by primary and steam soak production is on average 18% STOIIP, therefore leaving in the ground some 28 billion barrels of oil as a vast potential for additional recovery methods. Since 1959 various methods have been tested, such as steam drive 1,3, in-situ, combustion2 and steam soak.4,5. Reservoir compaction is the main production mechanism in the Bolivar Coast reservoirs. It is proposed to make full use of this natural source of energy by applying the steam soak process. When compaction reserves are exhausted, other drive processes will be applied; the most appropriate being steam drive based on pilot tests. The M-6 steam drive is intended to evaluate the application of this recovery method on a large scale as the follow-up process for the Bolivar Coast after steam soak. Based on the results of laboratory experiments and the performance analysis of the C-3/C-4 steam drive test, discussed below, the large scale M-6 steam drive project has been designed. LABORATORY MODEL EXPERIMENTS Physical model studies were undertaken in 1971 in the Koninklijke/Shell Laboratorium. Rijswijk, the Netherlands, to obtain additional technical information on the steam drive process under Bolivar Coast heavy oil reservoir conditions. The investigations took place in one twelfth of an inverted seven spot proto-type (closed hexagon) with a distance of 230 m from corner well to centre injection well.

Geological Factors in Steam-Soak Projects on The West Side of the San Joaquin Basin

More than 10 years' experience in steam-soak operations on the west side of the San Joaquin Basin has disclosed that at least three geological factors are important in such projects. Understanding these factors is necessary for such things as deciding well spacing, selecting the completion zone, and selecting proper completion and workover practices. Introduction There is sometimes a tendency to underestimate the importance of geology in steam-soak projects. Such projects are often carried out in old fields where the limits projects are often carried out in old fields where the limits of the reservoir, the structure, and the correlation, to some degree, have already been resolved by old primary wells. At least this is the case in most of Shell Oil Co.'s steam-soak projects on the west side of the San Joaquin Basin of California. Why, then, do we need to study the geology to convert old wells to steam soak or to infill at closer spacing with soak wells? We cannot use the reasons used for drives of any type where we must assure ourselves through detailed geological studies that the injectors are indeed connected to the producers, for in a soak project the injectors are the producers. After more than 10 years of steam-soak experience on the west side of the San Joaquin Basin, it has been found that several geological factors are important in such projects. An understanding of these factors can aid in deciding on the most efficient well spacing for the project, selecting the completion zone for each well if project, selecting the completion zone for each well if there are several sands present, and determining the length of the interval to be completed if the reservoir is thick enough so that this is a problem. It can also help in predicting how a zone will react to steaming as well as in selecting the proper completion and workover practices. practices.Important geological factors are (1) the environment of deposition - not for that fact in itself, but how that will affect the vertical and lateral transmissibility; (2) the structure and type of trap being dealt with; and (3) the internal features of the rock. To illustrate how knowledge of these geological factors have aided in various steam-soak projects, three different formations that have been steamed are reviewed. The geological factors known about these formations are discussed, as well as how this knowledge has been used in the projects. In order not to be distracted from this purpose, little of the reservoir or production data normally reported for such projects have production data normally reported for such projects have been included. Tulare Sands - West Side, San Joaquin Basin One formation steamed on the west side of the San Joaquin Basin is the Tulare sands of Pleistocene age. Heavy oil shows are reported in almost all the Tulare sands encountered in this area. Attempts to produce these by steam soak have ranged from complete failure to good commercial oil wells. Woodring et al. established that the Tulare sands were nonmarine in origin, having been deposited in and around a large fresh-water lake that covered most of the San Joaquin Valley. Fig. 1 is a map of the different depositional environments that existed around the lake during Tulare time. It is based on paleontological and log studies by Clifford and similar work by the author. As illustrated on the west side, two general environments existed. Farthest to the west and adjacent to the Temblor Range an alluvial plain developed. The Temblor Range was not greatly uplifted, so large alluvial fan deposits like the Kern River series on the east side did not develop. JPT P. 741

Operation and Performance of the Slocum Thermal Recovery Project

As a result of a steam-injection process that uses the underlying water layer, impressive quantities of oil have been recovered from a reservoir that previously yielded only marginal production. Although many difficulties have reduced the profitability, it is expected that by applying recent technology and field experience, the oil-steam ratio, and hence the economics, will be significantly improved. Introduction and History The Slocum field is in southern Anderson County in northeast Texas. Production of 19 degrees API oil, ranging in viscosity from 1,000 to 3,000 cp is from the shallow Carrizo formation (500 to 600 ft). The oil accumulation is anticlinal bounded on the north by a fault and elsewhere by the oil-water contact. (See Fig. 1.) Although the sand is generally very clean, and has a permeability of about 3,500 md, the viscosity of the oil at the reservoir temperature of 75 degrees F allows only marginal primary recovery. Since the discovery of the field in 1955, numerous exploitation attempts have recovered only 300,000 bbl of oil, or about 1 percent of the original oil in place. A typical primary well produces only 1 to 2 BOPD. primary well produces only 1 to 2 BOPD. The viscosity-temperature behavior of the oil is such that its viscosity is reduced by a factor of more than 100 when the temperature is increased to 350 degrees. (see Fig. 2), which suggests that the oil might be produced successfully with thermal recovery produced successfully with thermal recovery processes. Other favorable conditions for such a process processes. Other favorable conditions for such a process are the shallow depth of the accumulation, the high oil saturation (65 percent), and the availability of high-quality, fresh water for generating steam or hot water. However, the absence of natural reservoir energy eliminates the possibility of a steam soak, and the high viscosity of the oil precludes a direct steam drive in the oil column. Initial reservoir pressure is only 110 psig with no significant gas saturation. Preliminary field tests indicated that although these Preliminary field tests indicated that although these processes would recover additional oil, they would not processes would recover additional oil, they would not be economical. Thus, merely reducing oil viscosity in the reservoir is not sufficient. If the oil is to be successfully unlocked, a more efficient recovery process must be used. process must be used. The reservoir geometry provides the means for such a process. Throughout the field, a water sand underlies the oil sand. (See Fig. 3 for type log.) If steam were injected into this sand, heat would be introduced into the reservoir faster, and would be placed in contact with a much greater portion of the placed in contact with a much greater portion of the oil than by injection into the oil zone. To test this steam-injection process, a 1/4-acre pilot was conducted in 1964–1965. It consisted of a normal five-spot pattern with four injectors, a central producer, and a temperature observation well equipped producer, and a temperature observation well equipped with a thermocouple. Approximately 40 percent of the oil in place within the pilot area was produced. Encouraged by this favorable recovery, Shell Oil Co. started a full-scale 7-pattern project in 1966–1967. Designated as Phase 1, it consisted of 5.65-acre, 13-spot patterns elongated in a NE-SW direction. (See Fig. 4.) The elongation was expected to compensate for a NE-SW preferential flow that had been observed during primary and pilot operations. Both production and injection wells were completed a few production and injection wells were completed a few feet into the water sand. P. 402

Experimental Investigation of Steam Soaking In a Depletion-Type Reservoir

Scaled experiments with a physical model show that the production performance of a steam-soaked well is somewhat insensitive to the performance of a steam-soaked well is somewhat insensitive to the injection rate and soak time over a wide range of values. Stimulated oil productions are proportional to the drawdown, and the increase in productivity index is higher when the viscosity of the oil is higher. productivity index is higher when the viscosity of the oil is higher. Introduction In the 11 years since its discovery, steam soaking has developed into a powerful stimulation technique. The process involves the cyclic injection of limited amounts of steam into a well, alternated with the production of hot oil from the same well. The steam production of hot oil from the same well. The steam heats the reservoir in the vicinity of the wellbore, and thus causes a reduction in the oil viscosity where the converging oil stream experiences the highest resistance to flow. This effectively increases the oil production rate. A significant improvement, however, will production rate. A significant improvement, however, will be obtained only in reservoirs where sufficient primary energy is available to drive the oil towards the well. Whether a well will respond to steam soak can readily be determined in the field. The well's performance for different injection and production policies can be resolved only in the long run. So we have made this the subject of a laboratory study using scale-model experiments, where the reservoir properties of the Bolivar Coast fields have been used as a general guide for the design of the model. The results of these experiments provide information on how such operating various as slug size, cycle length, steam injection rate and length of the soak period affect the production of a single well and that of a project with many wells. Different values of initial reservoir pressure, oil viscosity and layer thickness have been used. For our purposes, the effect of formation stratification was not considered, and wells were assumed to have no skin. Although this information is indispensible when determining optimum development schemes in the field, we do not deal here with optimization because it depends largely on economic factors, which vary widely with local conditions. Experimental Setup and Operating Procedure The model represents a cylindrical, bounded part of a depletion-type reservoir with a well in its center. The sand layer is horizontal; its thickness and permeability are constant. The model is provided permeability are constant. The model is provided with cap and base rocks. The production mechanisms (rock compaction, oil expansion, solution-gas drive, etc.) are accounted for by an increased effective oil compressibility, which is assumed to be constant. Because of the symmetry of the prototype, the model has to represent only a sector of it (Fig. 1A). The glass side walls wore insulated with polystyrene to minimize lateral heat losses. Model studies of steam soak in depletion-type reservoirs require the scaling of both the depletion process and the effect of the steam. The process and the effect of the steam. The steam-injection scaling rules are discussed in Appendix A. They determine the model values of permeability, viscosity, and quality of the injected steam. If we combine these requirements with those for the simulation of the depletion process, it appears that the compressibility of the model oil must be 50 to 100 times as high as that of the prototype oil. P. 1006

A Dynamic Programming Model of the Cyclic Steam Injection Process

Because cyclic steam injection is a multistage-decision process, dynamic programming -characterized by a criterion function to be satisfied, a programming -characterized by a criterion function to be satisfied, a number of stages in time and space, and decisions to be made at each stage to satisfy the criterion function - may be used to predict an optimum operating policy for the specific injection project. Introduction The cyclic steam injection process has become the most widely applied and most successful thermal recovery technique in use today. Normally, steam stimulation is repeated several times during the life of a project. The problem is to select the optimum number and size of steam treatments so that the profits realized over the entire life of the project are profits realized over the entire life of the project are maximum. Obviously, operating costs rise directly with the frequency and amount of steam injection. Operating efficiency, on the other hand, can be adversely affected if the amount and frequency of stimulation are insufficient. Thus arises a multistage decision problem; that is, a decision must be made at each sub-period (day, for example), as to whether steam should be injected, and, if so, how much. It is desirable that these decisions be made in such a way as to secure maximum net profit before taxes. This can be achieved by dynamic programming. To use dynamic programming, we must be able to predict not only the production rate-time curve predict not only the production rate-time curve resulting from a given simulation, but also how changes in stimulation policy will affect this curve. In this study, the effect of steam injection on well performance is estimated on the basis of a simple model performance is estimated on the basis of a simple model that takes into account both steady-state and transient flow. Oil production rate is calculated for both types of flow, and the larger of the two values is used. This allows the calculation to change to radial steady-state flow at such time as this mechanism becomes more effective than the transient mechanism. We propose to show how dynamic programming can be used to optimize the steam soak process with respect to net profit. For this, a mathematical representation of the steam soak technique is necessary. A further objective, therefore, is the formulation of a mathematical model capable of realistically simulating the physical process. Oil Production Response Model The advantage of using a mathematical model is its generality and case of manipulation. However, the model must be an accurate representation of the physical process, for a solution derived from a model physical process, for a solution derived from a model can be no better than the model itself. The question now arises as to how well the model should be expected to simulate reality. In general, the simplest model should be tried first, for additional accuracy is apt to require additional cost and time. Also, the search for a high degree of accuracy may yield only greater complexity and difficulty without yielding significantly better results. With this in mind, we kept our model as simple as possible, yet generally representative of the actual possible, yet generally representative of the actual physical process. The number of state variables is physical process. The number of state variables is limited to three, and stochastic variations in the parameters are ignored. As a consequence, use of parameters are ignored. As a consequence, use of this model should be restricted to cases in which the underlying assumptions are not severely violated. JPT P. 1582

A Mathematical Model of Repeated Steam Soaks of Thick Gravity Drainage Reservoirs

Certain equations have been used to predict the performance and heat requirements of steam soaks applied to gravity drainage reservoirs. Good agreement has been obtained between calculated and observed performance. Introduction The steam soak process is the most widely applied and most successful thermal supplemental recovery process in use today. This process, which consists of injection of steam in various quantities into a well that is subsequently used as a producer, can be repeatedly applied to the same well. The treatment, if successful, will increase the production rate of the well for a given period. For this reason, the steam soak process should be considered primarily as an acceleration method rather than as a method for producing oil that could not be recovered by primary means. However, application of this process to reservoirs containing viscous crude may produce oil that otherwise would have zero present value or would be produced at such low rates by primary methods that it would not be profitable. A major necessity for the successful application of the steam soak process is a source of natural energy. This source of energy may exist in one or more of the following forms: expansion of fluids, compaction, gravity drainage. This study was undertaken to determine the effect of gravity drainage on steam soak production and recovery and to develop a method for predicting production rates, ultimate recovery, and heat requirements when applying this process to a reservoir in which the primary driving mechanism is gravity drainage. (For additional discussion of some of the factors that affect recovery of viscous oils by the steam soak process, see Ref. 5.) Model The model developed for analyzing the performance of the steam soak process in gravity drainage reservoirs is a modified form of that developed by Matthews and Lefkovits. The model used in this study consists of two concentric cylindrical volumes of productive formation with cap and base rock of impermeable material. The inner cylinder, extending from the radius of the wellbore to some predetermined radius, is referred to as the hot zone; and the outer cylinder extending from the exterior boundary of the hot zone to the outer drainage boundary will be referred to as the partially heated zone. Fig. 1 is a schematic cross-section of the model, indicating its thermal properties. Horizontally the reservoir is divided into two regions, the upper region having a high gas saturation and residual liquid saturation, and the lower region containing a high liquid saturation. The boundary between these two regions is referred to as the free surface, which drops and changes shape as fluid is produced from the reservoir. The model was used to analyze the steam soak process by applying the following assumptions: The horizontal formation is composed of one ormore homogeneous noninterconnected layerscontaining incompressible fluids. Each layer is treatedseparately. The hot zone is heated by the initial soak and ismaintained at the steam temperature correspondingto atmospheric pressure by resoaking. The height of the free surface at the producingwell is at all times zero (producing well is pumpedoff). JPT

A Review of Steam Soak Operations in California

Thermal stimulation of oil producing wells by cyclic steam injection accounts for over 13 percent of the current oil production in California. Here is a description of some of the more important steam soak operations currently being conducted in 29 California oil fields through June, 1967. Introduction The tremendous upsurge in thermal stimulation of heavy oil producing wells by steam soak operations in recent years has reversed the 9-year decline trend of the total oil production rate in California. By the end of June, 1968, some 14,000 wells were actively involved in steam soak operations and over 139,000 B/D of additional oil were being credited to this thermal stimulation process. The total state production has increased from 795,238 B/D in Feb., 1962, production has increased from 795,238 B/D in Feb., 1962, to 1,026,000 B/D in June, 1968. The substantial increase in oil production in turn created a widespread search for projects that could benefit from steam soak operations. This review was conducted to determine those areas in the state where steam soak operations were being successfully applied, and to recognize, if possible, which type of heavy oil reservoir had responded most favorably to this stimulation method. It was hoped that the results of the review would provide some practical guidelines to be used along with theoretical considerations in selecting future steam soak projects. History The following summarizes very briefly the active steam stimulation projects in the State of California from the inception of this process in 1958 until June, 1968.1958 -- Shell Oil Co. began steam soak operations on a pilot basis in the Yorba Linda field.1961 - The success of the Yorba Linda experiment was evident and Shell expanded their steam soak operations to include properties in the Coalinga field. During this year, Tidewater Oil Co. started hot water injection in the Kern River field.1962 - Beiridge Oil Co. began steam soak and steam displacement operations in the South Beiridge field.1963 --A total of 29 steam projects were in operation.1964 - A total of 111 steam projects were in operation.1965 -By December of this year, there were 284 steam projects in California, of which 17 were steam displacement and 267 were steam soak or "huff and puff" operations.1966 -- By June of this year, there were a total of 339 steam projects in California, approximately 90 percent of which were cyclic steam soak operations. percent of which were cyclic steam soak operations.1967 - By June of this year, the number of projects had declined to 256.1968 - By June of this year, the number had further declined to 242. Table 1 summarizes these projects by fields as of July 1, 1967. All data are from C.C.O.P. records except for the number of generators in use. These figures were taken from miscellaneous published articles. The estimated additional oil production from steam stimulation was about 120,000 B/D by the end of June, 1967. Approximately 408 generators were in use at this time, so that the additional production amounts to 295 B/D/generator. JPT P. 25

Early Results of the First Large-Scale Steam Soak Project in the Tia Juana Field, Western Venezuela

Well inflow performance and production mechanisms are discussed for a 74-well steam soak project in a reservoir containing 10 to 14 deg. API oil On the basis of the results obtained so far, a significant increase in ultimate recovery is expected for injection of relatively small amounts of steam. Introduction In view of their size and favorable characteristics, Shell's heavy-oil fields on the eastern coast of Lake Maracaibo, Venezuela-known as the "Bolivar Coast" - are obvious candidates for the application of thermal recovery methods. During the last decade various methods have been tested, such as steam drive, steam soak and in-situ combustion. Steam soak was discovered as a promising production method rather accidentally in 1969, during early steam drive testing in the Mene Grande Tar Sands. When steam erupted at the surface due to breakdown of the overburden, the injection wells were backflowed to relieve the reservoir pressure. This resulted in high oil production rates, all the more impressive because the reservoir is unproducible by primary means. It was concluded that injection of limited amounts of steam might be a very effective method for stimulation of heavy-oil wells. To obtain information that would be more widely applicable, testing of the process was continued in the eastern part of the Tia Juana field (Fig. 1). Here even more favorable results were obtained in Mene Grande. This created sufficient confidence to prompt a large-scale project, which was considered essential for an adequate evaluation of ultimate recovery, steam requirements, mechanical problems and economic prospects. To obtain an early answer on the ultimate recovery a fairly depleted area was selected in the western part of the same field ("A" in Fig. 1). The first steam was injected in March, 1964. This paper describes the performance until the end of 1966. The production mechanism and well inflow performance are discussed in some detail. In view of the favorable results obtained so far, steam soak operations have expanded considerably since the start of this project. Presently, five other projects are under way, of which two are about the same size as the one under discussion, with further extensions being programmed. Description of the Project Reservoir Data Shell's part of the Main Tia Juana reservoir has a proven area of 8,800 acres and an average net oil sand thickness of 130 ft, It contained an initial quantity of 2,750 million bbl of stock tank oil (STOIIP), with an API gravity ranging from 10 to 15 deg. API and a viscosity of 100 to 10,000 cp (at 122F). As a geological unit it is known locally as the Lower Lagunillas member of the Lagunillas formation, which is early Miocene in age. The sand bodies are believed to be distributary channel sands deposited in a lower coastal plain. Most of the channel sands have lateral and some vertical communication. The field was developed mainly in the period from 1936 to 1950. The ultimate primary recovery is estimated at 18.1 percent of STOIIP, of which 12.5 percent STOIIP had been produced by the end of 1963 from some 540 wells. JPT P. 101ˆ

Prediction of Anhydrite Precipitation in Field Water-Heating Systems

Abstract A key step in feed water treatment for generating wet steam for thermal oil recovery is the removal of calcium and magnesium hardness by cation-exchange series softening. Knowing the solubility of any scale-forming salts in brines at elevated temperatures is necessary for fixing the level to which the feed water must be softened. Such calcium sulfate solubility data, previously not available above 392F, were determined by the authors in a flow equilibrium apparatus and will be reported elsewhere. These data were used to develop a method for predicting the solubility of anhydrite in hot water or steam droplets for saturated steam pressures as high as 2,000 psig (637F). (The calcium sulfate solubility product is represented by a combination of two factors, one reflecting the effects of ionic strength and the other accounting for the effects of complex ion formation in either calcium-magnesium-rich or sulfate-rich brines.) The method is applied to a calcium-magnesium-rich brine of moderately high salinity from a pilot hot-water flood, and to several sulfate-rich, low-salinity feed waters and blowdown (cooled steam droplets) samples from steam soak operations. The predicted calcium hardness levels corresponding to the calcium sulfate solubilities agreed reasonably well with the results of laboratory solubility determinations run on the field samples. Further testing of the method is needed for brines of other composition classes. Existing field cation exchange softeners in the cases tested are performing adequately since all the samples were found to be undersaturated with respect to calcium sulfate at their operating temperatures. Introduction Prevention of scaling caused by precipitation of calcium sulfate (anhydrite) is of considerable concern in connection with thermal recovery processes using wet steam or hot water. To avoid anhydrite precipitation in a heated system, an engineer must keep the product of the calcium and sulfate concentrations in the water or steam droplets below the value of the solubility product of anhydrite for the temperature and brine composition in question. Usually it is most practical to keep the concentration product lower than the solubility product by keeping calcium low in the presence of high sulfate, or by keeping sulfate low in the presence of high calcium. This can be done by a choice of combinations of natural waters and water treatment processes (such as series cation exchange softening to remove calcium). Until recently, few anhydrite solubility data, particularly for solutions containing other salts, were available for temperatures above 392F (211 psig steam); Marshall, Slusher and Jones studied the CaSO4-NaCl-H2O system up to 392F and surveyed the work of previous investigators. To model natural brines, one needs to study the solubility of anhydrite in aqueous solutions of sodium chloride. sodium sulfate, calcium chloride, magnesium chloride and their mixtures. Since steam pressures as high as 2,000 psig (637F) may be involved in thermal oil recovery projects. a solubility study was conducted between 482 and 617F. Discussed in this paper is the application of these data to the prediction of anhydrite precipitation in some practical steam soak and hot-water injection projects. Any simple method for predicting the solubility of an inorganic compound over a wide range of temperatures and solution compositions must be based on some assumptions, and therefore must yield approximate results. On the one hand, natural brines contain too many ionic species for all to be included in a simple scheme; on the other hand, there is no adequate theoretical basis for the exact prediction of solubility in even simple solutions of mixed electrolytes. However, it is possible at a given temperature to base a reasonable prediction scheme on two phenomena: the increase in solubility with increasing total concentrations of all ions (as measured by the ionic strength; see the Appendix). and an increase due to formation of complexes between calcium ions and sulfate ions and between sulfate and magnesium ions. Stiff and Davis developed such a scheme for predicting the solubility of gypsum (CASO4 * 2H2O) in brines at temperatures up to 212F. However, for the higher temperatures of present interest, the stable solid phase is anhydrite (CaSO4). This study involves a two-part method for predicting anhydrite solubility products. First, one predicts a value K, for a given ionic strength I and a given temperature T corresponding to mca/mso4= 1 from data of the CASO4- NaCl-H2O system. Second, one determines a group of factors F = F(Ca) * F(Mg) * F(SO4). where the individual factors account for increases in the solubility product due to complex formation by high concentrations, respectively, of calcium, magnesium and sulfate. Combining the two parts, one obtains the solubility product in molalities as

A Mathematical Model of Reservoir Response During the Cyclic Injection of Steam

Abstract A mathematical model of reservoir behavior during one cycle of the intermittent steam injection process is presented in this paper. A cycle of the process is considered to be composed of three stages: injection, condensation and production. The model concentrates on behavior during the production stage. The influence of several parameters on production improvement is described, using the results obtained with a numerical equivalent of the model. Reservoir system parameters considered are thickness, reservoir thermal conductivity, oil viscosity, solution gas-oil ratio and the change in oil effective permeability with temperature. Operating parameters investigated are heat injection rate, steam temperature and cumulative injection time. In the face of considerable uncertainty, the model appears to give a fair prediction of the behavior observed during an actual test. This makes the model a useful means of selecting projects. It is shown that the model may also be utilized to select an optimum set of operating conditions for a particular project. Results of this study show the extent to which production improvement depends on each of the parameters investigated and give an indication of the range of system conditions within which the process would be effective. INTRODUCTION In recent years the intermittent steam injection or steam soak process of oil recovery has become a popular method of improving recovery in reservoirs bearing high-viscosity hydrocarbons. Production improvement due to the process results from heating the reservoir near the wellbore. The process is applied on an individual well basis and is executed in a series of cycles, each consisting of three stages: injection, condensation (the soaking period) and production. During the injection stage, high-pressure steam is injected into the reservoir surrounding the wellbore. This study assumes that injection is carried out over the entire vertical section of the reservoir rock that can be exposed to fluid injection. The condition of steam entering the reservoir is considered to fall within the following limits:steam pressures less than 1,000 psig,steam temperatures between 300 and 700F andsteam quality less than 90 percent. The last restriction is due to equipment limitations. Normally, injection is maintained for less than 3 weeks. After termination of injection, the condensation stage begins. The well is shut in for several days, supposedly to make certain that the injected steam condenses. This condensation would insure the retention of injected heat. The production stage is initiated when the well is opened again. Reservoir response during this stage determines the effectiveness of the process (response is defined as the oil production rates, the water production rates and the wellbore temperatures observed during the entire production stage). The immediate response of the reservoir is sometimes quite good. Sets of case histories by Long1 and by Owens and Suter2 give some typical figures for response. Duration of the production stage is equal to the time needed for the oil production rate to decline to some predetermined value. This usually requires 4 to 6 months. Termination of the production stage coincides with the start of the next cycle. The process is continued, cycle by cycle, until it becomes unprofitable to continue.

Casing Temperature Studies in Steam Injection Wells

Abstract The key to realistic casing stress analysis in thermal recovery installations is accurate knowledge of the temperatures involved. Much information leading to prediction of heat losses from tubing string to wellbore has been published. This same information permits calculation of casing temperature under certain conditions. This paper reviews the basis for most of the published work, the line sources solution to the diffusivity equation and examines some of its application criteria in the light of unsteady-state conditions. An alternate finite differences method is presented for correlation, and experimental data pertaining to the heat transfer mechanism in the annulus is reported. In the light of the information presented in the paper, it appears that the assumption of a line source for the tubing-wellbore system is valid even for reasonably short periods of heat flow, such as "steam soak" operations. The empirically modified equation presented earlier matches computer derived results of the finite differences approach for periods as short as 50 hours. Previously predicted casing temperatures and the associated stress levels are thus verified based on these correlative computations and the reported experimental information. Fall-out from the computer output resulting in some studies of the influence of insulating cement properties on casing temperature, and experimentally studied effects of nitrogen placed in the annulus at various pressures, are described. Introduction Generally speaking, predictions of average casing temperatures have been based on an idealized model involving a centralized tubing string at uniform constant temperature radiating energy towards the casing under steady-state conditions. Heat is transferred away from the casing to the formation by unsteady-state conduction across thermal barriers consisting of cement and the mud sheath., Heat balances written on the casing permit prediction of instantaneous casing temperatures. During early periods of injection, casing temperature varies appreciably as a function of time; however, for long injection times this variation decays as heat flow from the wellbore to the formation stabilizes, and it becomes virtually negligible as conditions surrounding the wellbore become quasi-steady-state (Fig. 1). Carslaw and Jaeger describe a solution to the diffusivity equation for a line source (Fig. 2). A constant supply of heat is introduced into the medium from the line placed into the origin of the x-y coordinate system and parallel to the z-axis. Heat spreads outward in the infinite cylindrical solid and the temperature increase on a line going through point (x, y) parallel to the z-axis at a distance r can be predicted by: .....(1) JPT P. 1157ˆ

Case History of Steam Soaking in the Kern River Field, California

Abstract Crestmont Oil Co.'s 42-acre May Fee property is located in the Kern River field, and consists of eight wells in the China Grade zone and seven wells in the Kern River zone. The average well declined from an initial production of 70 to 4 BOPD in seven years, while recovering only 9 per cent of the oil in place. A thermal recovery program was initiated using the steam soak method of injecting, soaking, and then producing. After injecting an average of 10,000 bbl of water as 80 per cent quality steam in six of the 15 wells, production increased from 1,635 to 13,374 bbl/month. The eightfold increase in production can be accounted for by the fact that these zones are ideally responsive to steam stimulation, due to the large decrease in viscosity realized by small increases in temperature and the large amount of 12.5 deg. gravity oil remaining at relatively shallow depths. Introduction Primary production from the seven- and 15-year-old wells on the 42-acre property had declined to 2 to 6 BOPD/well, even though only 9 per cent of the original oil in place had been produced. Late in 1962 Crestmont Oil Co. decided to investigate various methods of thermal recovery to see if the remaining oil could be economically recovered. The purpose of this paper is to present the reservoir conditions prior to steam injection, describe equipment used and the method of injection, tabulate the results before and after the wells were steamed, and tabulate techniques and conclusions regarding steam injection. Geological Description The Kern River zone contains 190 net ft of oil sand from 700 to 1,000 ft. There are several strata of shale throughout the zone, with a 60-ft interval occurring at 850 ft. The formation has 35 per cent porosity, 20 per cent connate water, and a 1.05 formation volume factor. The viscosity of the oil at the ambient reservoir temperature of 80F is 7,000 Saybolt-seconds. The gravity averages 12.6 at 60F. The Kern River zone contains approximately 1,900 bbl of oil/acre-ft. A zone of fresh water, identical to the produced water, exists from just below the surface to the top of the Kern River zone. Fig. 1 shows a composite log of the Kern River and China Grade zones. The China Grade zone contains 20 ft of oil sand in Te 35 ft from 1,200 to 1,235 ft. The China Grade zone exhibits a more uniform vertical homogeneity than the Kern River zone. The ambient temperature, viscosity and gravity are closely related to the Kern River zone. JPT

Review of Thermal Recovery Methods Applied to California Reservoirs: ABSTRACT

The number of thermal recovery projects in California has had a spectacular increase during the last year. Current emphasis is on the work, but this does not seem to be the ultimate answer for the majority of California reservoirs. Steam and in situ combustion appear to hold the greatest promise for thermal recovery in low-gravity California oil sandstones. With steam, there is the soak and the flood, whereas with in situ combustion, there are forward and reverse burning techniques. To date most steam work has utilized the soak technique and all commercial in situ combustion work has utilized the forward burn. For the most part, a single thermal recovery technique has been used on a sandstone or reservoir. It now appears that more sophisticated approaches should be used, with the object of combining the best of several techniques. This will allow benefiting from the unique advantages of each technique. Good detailed geology is very important to the future success of thermal projects. Too often in the past this has been overlooked. The future success of California thermal projects will necessitate the close cooperation between the geologist, the engineer, and the field operating personnel. This paper will review the advantages and limitations of steam and in situ combustion processes. End_of_Article - Last_Page 1084------------