Thermal Recovery Methods Research Articles

Steam Distillation Drive-Brea Field, California

This process has been field tested in a steeply dipping reservoir containing 24 degrees API oil at a depth of 4,600 feet. The very stable steam drive showed little tendency for early heat breakthrough to downdip wells. Residual oil saturations of 8 percent were achieved and the produced oil gravity was increased by light components distilled from the produced oil gravity was increased by light components distilled from the oil remaining in the steam zone. Introduction Most thermal recovery methods have been applied in high-viscosity reservoirs with the objective of increasing, oil production by reducing oil viscosity. The primary objective of a steam distillation drive is not to reduce oil viscosity but to reduce the residual oil saturation below that obtainable by ordinary waterflooding. In addition to its improved displacement efficiency, steam drive yields high sweep efficiency when steam is injected updip in steeply dipping sands. The objective of the Brea steam drive was to test the feasibility of driving a relatively light (24 degrees API), low-viscosity (6 cp), volatile oil from updip injectors to down structure producers. Process Process In reservoirs containing volatile oils, very low residual oil can be obtained by a combination of steam displacement and steam distillation. In a steam distillation process (see Fig. 1), hydrocarbons are more readily vaporized because of a lowering of their partial pressures in the presence of steam vapor. partial pressures in the presence of steam vapor. The light components are distilled from the residual oil and transported to the steam front where they recondense and mix with the oil bank to form a solvent slug. As the steam zone advances, this solvent slug. is displaced and redistilled to further increase oil recovery. Residual oil saturations below those obtainable by steam driving nondistillable oils are possible. Other mechanisms attendant with this process possible. Other mechanisms attendant with this process that account for the recovery of additional oil beyond what is possible with waterflooding are: reduction in oil viscosity, which improves oil mobility; thermal expansion of the oil; and gas drive from the steam vapor phase. In addition to in capacity to reduce oil saturation, steam driving is a relatively stable displacement process in light oil reservoirs (i.e., little oil is process in light oil reservoirs (i.e., little oil is by-passed). This stability is enhanced by both fluid convection and thermal conduction effects. The first stabilizing influence is the higher volumetric vapor flow rates in the steam zone compared with the liquid flow rates ahead of the steam front. Application of Darcy's law to both sides of the condensation zone in a situation where the pressures are generally less than 1,000 psi and the oil has a low viscosity shows that the pressure gradient is higher on the steam side than on the liquid side. Except for irregularities in permeability, steam fingers have little tendency to permeability, steam fingers have little tendency to form. The second stabilizing effect, thermal conduction, tends to collapse irregularities at the front of the steam zone because of heat losses normal to the direction of fluid flow. Laboratory Experiments The mechanisms involved in the steam distillation process were studied in unconsolidated tubular process were studied in unconsolidated tubular sandpacks. The apparatus used in the high-pressure (2,000 psi) experiments is illustrated in Fig. 2. JPT P. 899

Analysis of a Steam Drive Project, Inglewood Field, California

This is the first reported California field data on the vertical extent and residual oil saturation of the steam swept zone. Field-derived data on reservoir heat distribution support the published theoretical data. Introduction The Inglewood field, discovered in 1924, occupies a faulted anticline along the Newport-Inglewood Fault System on the western edge of the Los Angeles basin (Fig. 1). The Upper Investment zone, UB sand, selected for this test is the shallowest producing reservoir in the field and lies about 1,000 ft below surface ( 650 subsea). The UB sand productive limit are defined by an updip sand pinchout, the Inglewood Fault, and by down-dip water. The UB sand is 40 to 60 ft thick, consists of fine- to coarse-grain sand with occasional pebbles, ranges from soft to unconsolidated, is overlain by a thick siltstone section and has bottom water. The reservoir properties are shown in Table 1, and electric log characteristics in Fig. 2. The air permeability ranges from 3.3 to 14.3 darcies in the top 40 ft of the reservoir, and porosity averages 39 percent. The primary producing mechanism is pressure depletion with primary producing mechanism is pressure depletion with water encroachment. Oil in place at start of project was 1,930 bbl/acre-ft. The Investment zone oil is asphalt base, 14 degrees API gravity with an in-situ viscosity of 1,200 cp. The high oil viscosity, low reservoir pressure, shallow depth and high oil saturation are all favorable for application of thermal recovery methods. Preliminary laboratory studies of steamflooding in Inglewood cores indicated that residual oil saturations of approximately 20 percent could be achieved with throughput of 1 PV of water converted to steam. Chevron Oil Field Research Co. and Standard Oil Co. of California, WOI conducted the Investment zone lost to learn if the low laboratory residual saturations could be obtained in the field and to determine the oil displacement efficiency in the project area. The test was designed to obtain data on vertical and areal coverage, heat losses, and rate of steam front advance, and to evaluate producing problems associated with continuous steam injection. Design Project Area Project Area Fig. 3 shows the steamflood pilot layout. It is an inverted six-spot containing 2.6 acres within the five first-line producing wells. The project area of the reservoir has essentially no dip. Injection Well 270 and Temperature Observation Wells 271, 272, 273 and 293, were newly drilled for the project. The location of Wells 304 and 304A, which were drilled specifically to obtain post-steam saturation, is also shown in Fig. 3. Well Completions The injection well was completed in only the top 40 ft of sand to avoid water and was perforated in a 30-ft interval 10 ft below the top of the sand. The four temperature observation wells were completed by cementing 3 1/2-in. tubing through the UB sand to surface. Observation Well 271 also was cored to establish presteam saturations in the pilot area. JPT P. 1141

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

A Method of Predicting Oil Recovery in a Five-Spot Steamflood

Abstract This paper presents a method of predicting the recovery and performance of a five-spot steam injection project. in which a realistic approach to pattern sweepout efficiencies is made. Published methods for radial systems were modified for the five-spot pattern by approximating the streamlines with straight lines radiating from the injection well and then converging to the producing well. In each radial segment, the position of the steam front and the temperature profile ahead of the steam front were determined by heat balance equations. which included an estimation of heat losses to surrounding formations. The location of the saturations behind the cold water front was determined from a Buckley-Leverett solution to the material balance equation. Results from this program show steamflood recovery in a five-spot pattern to be considerably less than that predicted for true linear or radial flow systems. For a specific reservoir containing 900-cp oil, a steamflood in a purely radial flow system was predicted to recover more than 75 percent of the original oil in place when 2 PV of water had been injected as steam. A fivespot steamflood with otherwise identical properties was predicted to recover 10 percent of the original oil in place when 0.15 PV of water had been injected as steam and to recover almost no oil thereafter. A cold water five-spot flood in this system was predicted to recover approximately 10 percent of the oil in place with 1 PV of water injected. For a five-spot pattern in an example reservoir with 10-cp oil, steam injection similarly showed lower ultimate recovery than water injection but no improvement in recovery rate. Introduction The thermal recovery method considered in this study is steam injection in a five-spot pattern. Pattern steam injection has been given little attention in the past, possibly because of some rather obvious disadvantages. Unless steam temperature is maintained throughout the entire swept area, the process will revert to simple waterflood with all heat being lost prior to reaching the oil bank. Also, the oil viscosity reduction takes place near the steam front and not around the producing wellbore, so that low producing rates must still be endured. This is the reason for the success of the steam stimulation, or cyclic injection, in which the fluids are produced from the same well used for injection. On the other hand, steamflooding can offer some advantages. Oil displacement is by four methods:mechanical displacement by the condensed water,viscosity reduction of the crude oil,swelling of the crude oil, anddistillation of the crude oil in the steam zone. Although dependent upon the crude, laboratory experiments have shown displacements up to 80 percent by steamflooding. In addition, steam is a good heat transport medium, since it is cheap and has a high heat content. Previous Investigations Previous publications have reported methods for predicting recovery in a steamflood for linear and radial systems. Since no pattern sweep efficiency is taken into consideration, the recovery even from a radial system must be greater than from more realistic geometries such as the very common five-spot patterns. Probably the broadest coverage is given by Willman et al., who reported experimental results and offered a method of predicting recovery for a radial flow system. They concluded that both hot water and steam injection recover more oil than an ordinary waterflood, and that steam injection could yield recoveries "as much as 100 percent greater than by water flood." They also concluded that both the heat requirements for a reservoir and the residual oil remaining in the reservoir after steam injection were independent of the amount of oil originally in place, that short exploitation times were desirable, and that a high percentage of net sand in the reservoir with a high initial oil saturation was desirable. The method assumes that the flood occurs in three concentric cylindrical zones:an inner steam zone,a central hot water zone, andan outer cold waterflood zone. Displacement in the steam zone is based on laboratory-determined residual oil saturations while the hot water and cold water zones use the conventional Buckley-Leverett equations. JPT P. 1050ˆ

What Direction Should Petroleum Engineering Education Take?

What Direction Should Petroleum Engineering Education Take?

Cost Comparison of Reservoir Heating Using Steam or Air

Abstract The relative costs of heating a reservoir by steam injection and by combustion have been examined. The comparison was based on a model similar to that proposed by Chu. The cost of boiler feed water, the price of fuel. pressure and plant capacity were parameters in determining the costs of air compression and steam generation. The analyses compare the cost of heating to the same radius by the two methods. Results suggest that the two primary factors for comparison are the price of fuel and the amount of crude burned during underground combustion. The cost of fuel has a greater effect on the cost of heat from steam than it does on its cost by combustion. As a result, analyses indicate that when the price of fuel is low, steam may be unequivocally cheaper than air. The influence of heat loss is such, however, that as the heated radius increases combustion becomes relatively more competitive depending upon the amount of crude burned. This implies that steam may be cheaper for small stimulation jobs (huff and puff) but combustion may be more economically attractive for heating large areas (flooding). Introduction Use of thermal methods of recovery is an accepted fact today. After an induction period of several years, processes are being widely used that involve reservoir heating to augment recovery. Of the several techniques, steam injection and forward combustion appear to be destined to dominate the field. Although the objectives of both are the same, the basic differences between generating heat in situ and injecting heat after surface generation influence the cost in different ways. This study compares the cost of heating a reservoir either by steam injection or by forward combustion. There has been no consideration of recovery. Presumably, recovery from the swept region would be high in either case. The sole consideration was the cost of heating to the same radial distance by either process. PROCEDURE THE MODEL The basis for comparison was a mathematical model similar to that used by Chu for combustion. The model simulates a radial heat wave in two-dimensional cylindrical coordinates. It includes heat generation, conduction and convection within the reservoir and conduction in the bounding formations. Thus, heat losses from the formation are considered. Three significant modifications were made. Equal logarithmic increments rather than equal increments were used for the mesh spacing in the r direction. By this technique large distances were simulated with relatively few mesh spaces. A backward difference approximation to the convection term was used to avoid troublesome oscillations which result from a central difference approximation when the convection term is large. The radial increments of the combustion zone motion were not necessarily uniquely related to the mesh configuration. The cumbersome step function introduced by the heat of vaporization of steam was circumvented by assuming the enthalpy of the steam to be a linear function of temperature between reservoir temperature and steam temperature. This is equivalent to assuming an average heat capacity numerically equal to the difference between the enthalpy of saturated steam and the enthalpy of water at reservoir temperature divided by the difference between the two temperatures. Heat losses obtained by this model are in essential agreement with those obtained by the analytical solution of Rubenshtein. A detailed description of the mode presented in the Appendix. Using the model, the times required to heat to particular radial distances were obtained as a function of injection rate and other physical parameters. For the steam case, injected fluid was assumed to be saturated steam at pressures of either 500, 1,000 or 1,500 psia. The corresponding temperatures are 467, 544 and 596F, respectively. Thickness ranged from 10 to 50 ft and injection rate ranged from 100,000 to 1 million lb/D. Reservoir and overburden temperatures at the injection well were assumed to be that of saturated steam at the injection pressure. The effect of maintaining the overburden temperature at the well at a different temperature (initial reservoir temperature) was examined with no significant change in behavior. The influence of wellbore heat losses for the steam case was determined in the following manner. The rates of heat loss as a function of time were estimated using an approach similar to that suggested by Ramey. The data were based on injection through 2 1/2-in. tubing in 7-in. casing. Integration of these data over the entire injection period yielded the total heat loss. Total heat losses were then corrected to their equivalents in steam (this number resulted from dividing the total heat loss by the latent heat). This was considered additional steam required to accomplish the reservoir heating and the total cost was increased accordingly. JPT P. 233ˆ

Effect of Temperature on Waterflooding

Abstract This paper describes laboratory experiments involving waterflooding atelevated temperatures using two refined oils and two crudes. The test core andinjection water were both held at test temperatures for the duration of theflood, thus eliminating the problem of thermal fronts. The findings reportedhere apply to waterflooding in general and thermal recovery in particular, asmost thermal recovery methods include a phase where "hot" water displaces "hot"oil. Waterflood tests were conducted at 75°F, 100°F, 150° F, 200°F, 300°F, 400°Fand 500°F using two refined oils: No. 5 white oil and No. 15 white oil. Twocrude oils were used in waterflooding at 75°F, 150°F and 300°F. The results show that residual oil saturation decreases with increasing temperature. Consequently, ultimate oil recovery increases with increasingtemperature and the relative permeability ratio is different for differenttemperatures. The magnitude of the temperature effect varies, but in most casesit is appreciable, especially for the crude oils. Crude oil waterfloodbehaviour in the laboratory tests differs significantly from refined oilbehaviour, because in crude oil waterfloods water breakthrough is earlier andsubordinate production is much higher. Consequently, predictions of field hotwaterfloods require displacement data at the actual field flood temperature, using reservoir materials. Introduction There is a great deal of current interest in thermal methods for recoveringcrude oil, especially the heavy viscous crudes. Many forms of thermal recoveryinclude a phase where hot water displaces oil. In such a process, two frontswill form a leading cold-water front and a hot-water front. Oil and waterviscosities decrease and the liquids swell as the temperature increases. These effects may influence fluid flow in a way not described by simple relativepermeability concepts. However, all processes involved in hot waterfloodingoccur slowly, and thermal equilibrium may be considered to prevail at everyspace-time point during the flood. Consequently, the relative flow rates of oiland water are determined by relative permeability ratios and viscosities, despite the complicating thermal effects mentioned above.

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------------

On the theory of hot-water drives

In this paper we are going to investigate a hot water drive in an oil-bearing rock formation. The hot-water drive is one of several thermal recovery methods EI~, [21, [81 a) used by the petroleum industry to produce the residual oil in a reservoir. (The essential phenomenon all such methods are based on is that by heating the reservoir the viscosity of the oil is lowered and may be more easily produced.) A disadvantage of this process is that initially cold oil must be displaced, unless of course there is ample stratification or pore-space in the formation for the hot water to flow through. There have been a number of theoretical hot-water drive studies made previous to this one. Most assume a piston like displacement by the encroaching water; however, they differ on the modes of heat transfer. SCI~UMANN [31, KLINKENBERG [41, and WALTER [51 have studied a model in which the heat is transfered by (1) convection of hot liquids, and (Model A) (2) heat exchange between the solid matrix and liquids which are at different temperatures.

Field Results of South Belridge Thermal Recovery Experiment

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 236–244. Abstract Results of a field research project on the thermal recovery of oil by movement of a combustion front are presented. This field test was conducted in the South Belridge field, Calif. The test pattern was a single 2.5-acre five-spot pattern in the 700-ft deep Tulare sand. Results of this project indicate the technical feasibility of producing high viscosity, low-gravity crude oils by thermal means. It was demonstrated that heavy oils could be moved rapidly over considerable distances by thermal drive, and that high percentage recoveries of oil could be effected. The bulk of the oil recovery came after arrival of the burning front at a production well. However, rapid corrosion and high-temperature failure of conventional pipe and equipment both below and above surface occurred. Stainless steels gave more satisfactory performance under these conditions than did conventional steels. Oxygen was seldom observed in gas from wells ahead of the burning front, and it appears that the front was continuous throughout the life of the experiment. Introduction During late 1953 and early 1954, industry-wide attention was focused on the thermal recovery of oil by movement of a combustion front through an oil zone. Two separate Oklahoma field tests were described in publications by. Kuhn and Koch, and Grant and Szasz. To obtain basic information needed for making engineering and economic appraisals of commercial recovery of heavy oil by this thermal recovery method, a new field research project was started May 31, 1955. Twelve oil companies contributed to this project with General Petroleum Corp. as operator. Since combustion recovery experiments with heavy oils in other areas had been conducted In small patterns, an important purpose of this test was to determine whether the process could be operated in a pattern of near-commercial well spacing. The South Belridge field, located 30 miles north of Taft, Calif., was chosen because its oil sands are similar to many heavy oil sands which typically have low primary recovery and leave a large amount of oil in place. Such fields are not particularly suited for common secondary recovery methods.

The Conduction of Heat Incident to the Flow of Vaporizing Fluids in Porous Media

Published in Petroleum Transactions, AIME, Volume 204, 1955, pages 282–284. Introduction and Purpose Problems relating to thermal methods of oil recovery have been given increasing attention during the past year. The nature of the physical and chemical processes underlying thermal recovery are not yet well understood. The need for pertinent basic information is recognized generally. One of the processes involved is the transfer of heat by conduction in oil reservoir rocks containing moving reservoir fluids. This technical note deals with heat conduction in a laboratory sand column filled with a moving hydrocarbon and therefore should be contributory to the presently inadequate fund of knowledge on the over-all subject. In an analysis of the flow of vaporizing propane through a horizontal column of sand, one of the present authors demonstrated correspondence between the measured values of pressure along the length of the column and those predicted by a theory which postulated that the enthalpy of the propane was invariable along the length of the column. This postulate was implied as a deduction from the principle of conservation of energy but the details of the deduction were not given. The specific purpose of this technical note is the presentation of these details both as an adjunct to the earlier analysis and to supply some additional details on the processes involved in this type of flow. Results disclose that rates of heat transfer by conduction, in the direction of fluid motion, generally would be small for systems of the type studied. Fundamental Energy Equation The principle of conservation of energy may be applied to a section of the porous material on the basis that heat transfer, like fluid flow, is possible in the x direction only. Transfer of heat in the y and z directions is prevented by suitable insulation or by taking the medium as infinite in directions perpendicular to the x axis. For steady state heat conduction and conditions of steady fluid flow the principle of conservation of energy specifies that any reduction in the enthalpy rate increases the flow of heat in the same proportion.

Development of an Underground Heat Wave for Oil Recovery

Introduction During 1947, a Sinclair research team was assigned to investigate thermal methods of oil recovery. The assignment was recommended by a survey of possible research approaches to increase the amount of oil that ultimately can be recovered from oil producing reservoirs. The use of heat to stimulate, oil production rates by the melting of paraffin deposited in well bores can be traced back to within one or two decades of the drilling of the Drake well. The application of heat on a larger scale has been discussed by generations of oil producers. Shortly after the turn of the century, one intrepid operator is reported to have injected steam into a Pennsylvania property. After a few weeks, he apparently became discouraged and terminated his experiment. Subsequently, the literature contains references to several well-developed techniques for supplying heat to a producing well bore to melt paraffin or to reduce the viscosity of oil contained in. the formation immediately around the well bore. Some early references discuss procedures to furnish heat to the reservoir, with the injection well as the heat source, thus obligating the process to maintain the entire rock mass at a temperature above that at which the desired improvement in oil recovery would occur. Another approach to reservoir heating was reported by a group of Russian technologists in 1935. They definitely demonstrated that combustion can occur within the porous structure of an oil-bearing sandstone. Their field experiments, however, relied less on combustion within the rock than on heat furnished by combustion of oil supplied to the injection well bore. Ignition of the air-oil mixtures in the well bore was found very difficult, and the field tests were carried on for only short periods of time. Publication of the Russian work spurred at least one independent operator in this country to try firing an air-gas injection well. on for only short periods of time. Publication of the Russian work spurred at least one independent operator in this country to try firing an air-gas injection well. The Brundred Oil Corp. reportedly obtained combustion in the sand immediately around the injection well bore, but the experiment was abandoned because of interference with normal production schedules. Injection capacity of the experimental well was greatly reduced by firing. The well was reshot and pieces of sand showing partial fusing of the quartz matrix were recovered.