Steam Injection Rate Research Articles

Steam distillation of a single component hydrocarbon liquid in porous media

Steam distillation of a single component hydrocarbon liquid in a one-dimensional porous medium of infinite domain was studied both theoretically and experimentally. Theory was developed to describe the spatial distributions of the hydrocarbon concentration in the vapor phase, and of the liquid hydrocarbon and water saturations. A similarity solution was obtained for the case of a single component hydrocarbon where the steam quality and injection rate were constant. The characteristic velocity of the distillation zone was found to depend on the residual saturation of the hydrocarbon liquid, and the thermodynamic properties of water and the hydrocarbon liquid. The scaling between the lengths of the mass transfer zone and the variable water saturation region was characterized by appropriate dimensionless parameters. In addition to verifying the analytical predictions, experimental results allowed the determination of the mass transfer coefficient which was found to increase linearly with the saturation of the liquid hydrocarbon.

A Statistical Analysis Of The Early Peace River Thermal Project Performance

Abstract A statistical correlation of well performance indices with geology is described for the steam soak phase of the Peace River Expansion Project (PREP), a thermal recovery project operated by Shell Canada Ltd. As expected from a confirmed, permeability-dominated steam underride through a basal lean bitumen zone, well performance correlates only with geology of the lean zone, and not at all with that of the overlying rich bitumen zone during this stage. However, the existence of extensive cross-correlations among the geological parameters, which in at least one instance has introduced a spurious correlation for calendar day oil rate, suggests that log analysis techniques need to be optimized in studies of this kind. In additionto the conventionally calculated bulk fraction shale volume Vsh)from logs, the introduction of other shale parameters is advantageous, and is discussed. Introduction In recent years there has been a growing interest in statistical studies of oil well performance indicators. Apart from the most common analyses, dictated by the need to reduce large data sets to some manageable size, statistical correlations of productiondata against geological parameters might be used to test theories of reservoir depletion that are provided by modelling. This work is intended to test a depletion theory, with the use of public data from the thermal Peace River Expansion Project (PREP), operated by Shell Canada Ltd. in northwestern Alberta. The PREP Project Shell Canada Ltd. has been operating the Peace River Expansion Project since 1986, following a very successful pilot which, as of October 1989, has recovered 53% of oil-in-place by a pressure cycle steam drive process(1). The project recovers bitumen from the 30 m thick Bluesky/Gething sands which have a thin basal zone of relatively low oil saturation (50% of pore volume) and high permeability. This lean pay zone, varying in thickness from 0.3 m to 7 m, allows injection of stream at high rates below fracture pressure in all but eight wells. All wells are perforated in this zone, except in Pads 12 and 15, where shale in the basal zone forced perforation in the rich zone, Thus, a permeability-dominated steam underride(2) permits heating or the richer zone from below(3). The operating strategy and facilities at the Peace River project have been described on several occasions(4–8); in essence it consists of alternating periods of high steam injection and low production rates (pressure-up) with periods of low or no steam injecrion and high production rates (blowdown). Figure 1 shows the well patterns at the Shell Peace River Project. To the west lies the original well cluster of the pilot (PRISP) project, consisting of seven inverted seven spots, Four clusters of thirteen patterns each represent the expansion project which will be considered in this paper. The small irregular "Multisoaks" pattern remains from a previous cyclic steam pattern. While the three eastern wells of this pattern have been incorporated into cluster A, they will be excluded owing to their prior operations history.

Influence of Geology on the Design and Maintenance of Steam-Assisted Thermal EOR Projects in the Southern San Joaquin Basin, California, USA

California, the fourth largest oil producing state and the largest steam assisted thermal EOR (SAT EOR) producing region in the United States, produced 350.7 MMBO in 1990. SAT EOR accounted for 180.8 MMBO (52%) of which 163.9 MMBO (91%) came from fields in the southern San Joaquin Valley. SAT EOR production began in California in 1960 and, over the past 30 years, geologic studies have proved crucial in all successful projects. Most project failures, either economic or technical, can be traced to a lack of adequate geologic input during either the initial design/implementation or subsequent reservoir management stages. Reservoirs range from structurally and/or stratigraphically simple to highly complex. Detailed geologic study is essential to define the external shape of a target reservoir for subsequent engineering design. Further study of internal details of the reservoir can anticipate potential clay or sanding problems, identify possible internal fluid barriers, and catalog other reservoir inhomogeneities. After initial project implementation, a second geologic review is recommended to incorporate new well data and modify the original interpretation. Once on-line, continuous monitoring of the target reservoir for temperature variation and fluid movements is essential to maintain peak efficiencies, time adjustments to steam injection rates, and fine-tune reservoirmore » performance. Although such reservoir management is primarily an engineering function, geologic input is critical to understanding internal reservoir inhomogeneities and barriers affecting fluid and heat movement. Case studies from Kern River, Midway-Sunset, and Cymric fields provide examples of how proper geologic studies can reduce capital investment, increase recovery efficiency, and maximize profitability.« less

"An Optimization Study For A Steam-Foam Drive Process In The Bodo Reservoir, Alberta"

Abstract An optimization study for a steam-foam drive process in the Provost Upper Mannville B Pool (Bodo Reservoir) located in east-central Alberta was conducted using the Alberta Research Council (ARC) foam transport model. The optimization was done with respect to the foam injection strategy and the concentration of the foaming agent (surfactant). A "discounted net profit" due to foam injection was maximized. Within the scope of this study, oil recoveries of all steam-foam processes investigated were better than the steam-only baseline process. However, not all foam processes were economically viable, optimal processes were dependent on the heavy oil prices. Over a range of heavy oil prices of US$62.90/m3 to US$125.80/m3 [US$10/bbl to US$20/bbl], the single foam slug process with a total foam injection period of 2 to 3 months and a surfactant concentration 0.5% to 1% by mass in the liquid phase of the injected fluids appeared to be the most profitable. Introduction The process of adding foaming agent (surfactant) aqueous solution to the injected steam to form foam in situ has been recognized as a promising technique in recovering heavy oil from underground reservoirs. Foam is well known as a selective blocking agent which can optimize reservoir conformance and minimize steam channelling and gravity override. This paper will demonstrate the necessity of choosing a suitable foam injection strategy for steam-foam drive field applications. Using the foam transport model developed at the Alberta Research Council by Law et al.(1,2), an optimization study for a steam-foam drive process in the Provost Upper Mannville B Pool (Bodo Reservoir) located in east-central Alberta was conducted. In the optimization study, it was impossible to examine all of the operation variables. The objective of this study was to investigate the advantage of using a steam-foam drive process instead of a steam-only drive process. The search for an optimal steam-foam drive process was made by permuting operation variables such as foam injection schedule (single or multiple foam slug process), total length of the foam injection period and surfactant concentration. Other operation variables such as steam injection rate and steam quality were kept constant. Optimization of the steam-foam drive process was performed by maximizing a ""discounted net profit" due to surfactant injection. Foam Transport Model Detailed descriptions of the ARC foam transport model have been given by Law et al.(1,2). Only a very brief review of this model will be given in this paper. The foam transport model, which is based on the physical properties of an alkylaryl sulphonate surfactant (Sun Tech IV), is a fully implicit multicomponent thermal reservoir model having the ability to handle five components and three phases. The five components are water, heavy oil, surfactant and two additives (non-condensible gases or volatile hydrocarbon components). The three phases are the aqueous phase, the oil phase and the gaseous phase. Conservation of mass of all components is governed by Darcy's law and is solved implicitly together with conservation of energy.

Coupling Of A Fracture Mechanics Model And A Thermal Reservoir Simulator For Tar Sands

Abstract This paper describes a new technique for dynamic coupling of a fracture mechanics model which predicts the growth of a fracture from a steam-injection well, with a general reservoir simulator which predicts the well injection/production behaviour. The approach of partial coupling of the fracture model with a reservoir thermal simulator is described. This approach provides computational efficiency and great flexibility. The method accounts for the dynamic fracture behaviour both during injection fracture growth) and production and can be used in conjuction with any conventional simulator. The key elements of the method are the dynamic enhancement of transmissibilities in the fracture plane, and a concept of pseudoized relative permeability. Verification of the technique and examples of field-scale thermal simulations using two different simulators are given. Introduction Injection of hot water or steam in oil sands results in complex interactions of several mechanisms, notably the fracture initiation and growth, the soil mechanics of the uncemented porous matrix and the resulting poroelastic and thermoelastic stress-strain behaviour, and fluid now and heat transfer in porous media. In the past, these major components were considered independently, and the attention was focussed in petroleum engineering mostly on the thermal multiphase flow models. For the study of the recovery mechanisms, the now models for consolidated media were Used(1–9) and when found inadequate, they were modified to account in some way for the fracture and soil mechanics aspects. Currently, the awareness of the importance of geotechnical aspects in reservoir engineering is glowing. On the other hand, geotechnical engineers are more interested in situ problems(10). A practical approach of partially decoupled modelling, which combines reservoir, fracture and stress models, was conceptually described(11). The details of the coupling of soil mechanics with reservoir flow were described for the isothermal case(12) and for the thermal case(13). This paper describes a method of coupling a fracture mechanics model with a thermal simulator. The coupled model retains the dynamic character of the fracture and at the same time results in a flexible and practical simulation system which can use existing thermal models. The work reported here is part of the over-all research of developing a comprehensive, modular modelling system outlined(14). Modelling of Fractures in Oil Sands Fracturing is one of the essential requirements to achieve a reasonable rate of steam injection into unconsolidated tar sand formations. Thus, rigorous representation of a fracture plays an important role in reservoir simulation. To date, a fracture in oil sands was represented in reservoir simulators in a simplified fashion using stationary or pressure-dependent change of transmissibililies. Fracture propagation and fluid flow in the fracture cannot be simulated accurately in this fashion. Coupling with Fracture Mechanics Realistic simulation of fractures requires a model of fracture extension, which is either fully coupled or partially coupled with reservoir flow model. As discussed(10), the partially coupled system a number of advantages. In particular, it allows fracture mechanics and reservoir flow problems to be treated on different scales which are natural to the problem.

An experimental study of steam injection into a uniform water flow through porous media

An experimental study of steam injection into a porous media was carried out in a 2-dimensional plane porous channel. The steam was injected into a uniform downward water flow in a vertically aligned porous channel. The steam-water interface was carefully observed to understand the underlying physics. Two steam injection rate bounds were found for a given water flow rate and water subcooling. The upper bound is the steam flow rate at which the steam zone grows without limit and the lower bound is the steam flow rate at which a steam zone is just initiated. The bounds were determined experimentally for a porous channel with different permeabilities and thermal conductivities. For large particle size, chaotic oscillation of steam water interface was observed. The oscillation is believed to enhance heat and momentum transfer mechanisms. The steam zone size and shape were measured to evaluate heat transfer characteristics. The average Nusselt number is presented in terms of steam and water Reynolds numbers and the Stefan number.

Steamflooding in a Waterdrive Reservoirs Upper Tulare Sands, South Belridge Field

Summary A steamflood project in the strong edgewater-drive Upper Tulare reservoir at South Belridge recovered about 31% of the original oil in place (OOIP) at a cumulative steam/oil ratio (SOR) of 2.7 vol/vol. Seven years of downdip steam injection depressed water influx and created an oil bank updip from the injectors. Response continued under the influence of returning aquifer water and heat scavenging after the injectors were shut down. Numerical reservoir simulation of the historical steamflood performance indicated that the high production/injection capacity (P/I) ratio induced early water encroachment and partial quenching of the growing steam zone. Restarting downdip steam injection at much higher rates after 6 years without injection was shown to recover more oil than continuing the steamflood with either a seven-spot or inverted nine-spot pattern. An efficient steamflood operating policy in an edgewater-drive environment involves overproducing in the oil column to reduce reservoir pressure combined with high-rate downdip pumping of the aquifer to reduce water inflow during steam injection. Downdip steam injection rates greater than 100 B/D-acre and P/I ratios of about 1.4 STB/STB emerged as reasonable operating parameters in several projects.

Steam bubbling regimes and direct contact condensation heat transfer in highly subcooled water

Experiments are reported on the growth of vapor—liquid interfaces dominated by both intertial and thermal effects. The system involved supplying saturated steam, at steady rates, to a 5 mm diameter nozzle submerged in water at 15–20°C. Discrete bubbles were released at steam injection rates below 1.6 gs −1 or 2.56 (10 −3) m 3 s −1. Between 1.9 and 6.1 gs −1 axisymmetric jets periodically evolved from ellipsoidal cavities above the orifice. Continuous two-phase jets from rapid disintegration of the vapor stream were not achieved at rates as high as 6.7 gs −1 or 6.72 (10 −3) m 3 s −1. In the transition between unstable and continuous jets, the interface evolved alternately to detach large bubbles from axisymmetric jets and small bubbles during “tip streaming” from tapering sinuous jets. At all steam rates, the periods of cavity growth to bubble detachment were less than 3 ms and the maximum cavity volumes were about 400 mm 3. The vapor—liquid boundaries were highly irregular due to spontaneous turbulence. The turbulence and temperature elevation at the boundaries promoted local desorption of gas from the water. The tiny bubbles formed persisted and were convected as discrete but axially dispersing clouds in the plume. Detached vapor bubbles disintegrated and collapsed completely within less than three nozzle diameters from the orifice. Convective heat transfer coefficients at the evolving vapor—liquid interfaces varied with the bubbling regime and with the stage of interface growth, and were as high as 2.4 MWm −2 K −1 without the pool of water being agitated.

Steamflood Material-Balance Applications

Summary A simple steamflood material balance derived from a two-zone reservoir model is presented. Alternative forms of the material balance include the effects of an initial hydrocarbon gas saturation, PV compressibility, and a hot-water zone. In example applications, the material balance is used to calculate the amount of fluid migration from a 16-pattern steamflood pilot and the steam injection rate within a regular five-spot pattern.

Numerical Modelling Of Cyclic Steam Stimulation In Cold Lake Oil Sands

Abstract Prior to start-up of the Wolf Lake Project in the Cold Lake oil sands, two-dimensional areal simulation studies were conducted using a fully implicit thermal simulator, with the objective of optimizing the operating strategies/or the different well spacings used in the project. Fractures, required to achieve reasonable steam injection rates in the field, were modeled by a line of thin grid blocks with high transmissibility in the preferred fracture (on-trend) direction. Single well optimization studies determined steam slug sizes and production period lengths for eight cycles of operation. Using the single well operating strategies, multiple well studies were conducted. These indicated that interactions among neighbouring wells significantly affected the recovery process. Fractures linking injection and production wells cause high water production. Pressure support via matrix communication results in increased production rates in wells not linked by fractures. Introduction The Wolf Lake Project (1,2), jointly owned by Petro-Canada and BP Resources Canada Limited and operated by the latter, is a small-scale commercial project designed to produce bitumen at an average rate of 1100 m3/d for a period of 25 years. The project is located in northeast Alberta on BP's Marguerite Lake lease (Fig. I). Approximately 1100 hectares of the lease will be developed. Also shown in Figure 1 is the location of the Phase A pilot(2,3). Phase A results justified commercial development and the pilot is currently being operated to collect data to Justify the incorporation of oxygen combustion into the Wolf Lake Project in the early 1990s. Bitumen is produced from the Lower Cretaceous Clearwater Formation(4) at a depth of approximately 460 m. Cyclic steam stimulation is used to heat and recover the highly viscous bitumen. Steam is injected above formation fracture pressure in order to attain reasonable injection rates. Wolf Lake Project wells are expected to undergo six or seven injection and production cycles. Before start-up, 224 wells were drilled from twelve central pads, or satellites(5). To maintain or exceed the target production rate of 1100 m3/d, new wells will be drilled as they are required. The average number of operating wells required tosustain production after the initial start-up period is expected to be around 250. Steam required for the stimulation process is generated at a central plant and distributed to the satellites and individual wells. The bitumen, gas and water production from the wells will flow through pipelines to the central plant where the bitumen is separated. The satellite layout and pipeline routing is shown in Figure 2. Figure 3 shows the well location on the east side of the project area. Wells are predominantly in 220 m by 100m 5-spot configurations, although 330m by 80 m 5-spot, 270m by 120m 5-spot and 220 m by 50 m rectangular well spacings are also being tested. Future pads will utilize the optimum well spacing. A pre-start up simulation program was conceived in early 1983 to assist in the design of the operating strategy for the project.

Steam-Assisted Gravity Drainage Model Incorporating Energy Recovery From A Cooling Steam Chamber

Abstract A new calculation procedure has been developed which allows the prediction of the effects of varying steam injection rates, pressures, and the duration of injection cycles on heavy oil recovery by gravity drainage. Previous models assumed maintenance of a constant steam chamber pressure and temperature. The model uses an approximate mathematical method to obtain the heat transfer to the receding oil bank and to the overburden. The heat injected is balanced against the total losses from the system and surplus and deficiencies cause variations in the temperature and pressure within the steam chamber. Modelling results indicate that considerable increases in cumulative oil-steam ratios are to be gained by stopping steam injection before the recoverable reserves in a pattern have been completely produced. It is also found that higher injection pressures and rates accelerate production and do not reduce the cumulative oil steam ratio significantly. Little benefit was found to result from multiple injection cycles within the same production pattern. These results should be of practical importance in the application of this process in the field. Introduction Steam-assisted gravity drainage in heavy oil recovery is a production method which exploits the tendency of oil heated by injected steam to flow from the top to the bottom of the reservoir. Steam injected into a reservoir rises to the top due to gravity differences between the steam and the natural reservoir fluids. The heat concentration at the top of the reservoir reduces the oil viscosity in the vicinity of the steam. The mobile oil flows to the base of the reservoir driven by gravity. Gravity drainage is likely responsible for much of the oil produced in conventional heavy oil production methods(4). In horizontal steam-assisted gravity drainage, steam is injected along the length of and above a horizontal production well which is at the base of the reservoir and parallel to it. Esso Resources Canada Limited has chosen to use vertical steam injection wells spaced along the length of horizontal producers temperin some pilot experiments at Cold Lake, Alberta, where steam-assisted gravity drainage to horizontal wells is being tested in the Clearwater formation(5,6). For application to the recovery of bitumen from tar sands deposits, such as those that exist in the Cold Lake, Athabasca and Peace River deposits in Alberta, steam can be introduced into the reservoir by the creation of a fracture(1,5). The bitumen cannot be displaced because it is not mobile at reservoir conditions. The assumption of an initial vertical fracture extending from the injection well to the top of the reservoir is convenient to the modelling process because it avoids the difficulties associated with instabilities of a steam chamber rising vertically counter-current to a flow of oil(1). In a large-scale, horizontal-well, gravity drainage system, groups of injection and production wells would be placed in parallel rows so that steam chambers growing from adjacent patterns would eventually encounter each other and merge.

A Comprehensive Simulation Study of Steamflooding Light-Oil Reservoirs After Waterflood

Summary Steamflooding, the most successful among enhanced recovery methods, has been applied mainly to heavy-oil reservoirs. This paper presents a comprehensive simulation study on the use of steamflooding after waterflood in light-oil reservoirs. Some important observations are made on this new application of the process. Guidelines are developed not only for selecting reservoir candidates for steamflooding, but also for designing and operating steamfloods in watered-out reservoirs. Relative importance of key mechanisms to oil recovery is also discussed. Introduction The use of steamflooding as a tertiary recovery method for light-oil reservoirs after waterflood has been of interest in recent years. Although steamflooding applied to heavy-oil reservoirs has been a fully proven method, the technology of applying it to light-oil reservoirs, especially those that have been watered out, is still in its infancy. This paper will answer the following questions that remain about steamflooding.Can watered-out light-oil reservoirs perform as well as heavy-oil reservoirs under steamflooding?What kind of reservoirs will be suitable for steamflooding after waterflood?How would one design and operate a steamflood once a reservoir is chosen?What are the main recovery mechanisms in this process? Several authors have made simulation studies on steamflooding light-oil reservoirs. Aydellote and Ramesh studied steamflooding economics with variations in oil composition, permeability, depth, pattern type, well spacing, and steam injection rate. A uniform fluid saturation was used at the start of the steamflood. Hanzlik improved on this work by preceding the steamflood with a waterflood that generates a nonuniform fluid saturation before steamflood starts. Both waterflood and steamflood were considered to take place in the same 5-acre [2.0-ha] five-spot patterns. He studied the effects of oil composition, reservoir thickness, and steamflood timing on steamflood performance. Hongs studied steamflooding the light-oil reservoir at Buena Vista field, CA, using a uniform fluid saturation at the start. This work starts with a 40-acre [16.2-ha] waterflood that is later converted to steamfloods with smaller patterns. A three-dimensional multiphase thermal recovery simulator with nine-point finite-difference formulation was used so that the grid orientation effect was greatly reduced in the simulation of steamfloods in five- and nine-spot patterns. A large number of reservoir oil and rock properties and also a large number of steamflood design and operating variables were considered. The following were developed: general observations on the process, guidelines for selecting candidates for steamflooding after waterflood, guidelines for designing and operating steamfloods, and relative importance of the various key mechanisms to oil recovery.

Steamflood Strategies for a Steeply Dipping Reservoir

Summary A computer simulation study was conducted to determine the best steamflood strategy for a steeply dipping (20° [0.35-rad]) reservoir. A compositional steamflood simulator was used with both two-dimensional (2D cross section) and three-dimensional (3D) models of the reservoir. The study showed that gravity drainage of the heated oil is the main production mechanism in steamflooding steeply dipping reservoirs. Consequently, oil production is strongly affected by injector and producer locations. The best steamflood strategy for this type of reservoir, therefore, involves judicious selection of injector and producer locations, reducing steam injection rate and shutting in wells selectively at appropriate times, and injecting a noncondensable gas to prevent steam cycling in the depleted updip portion of the reservoir. This paper compares oil production performances and steamflood efficiencies for nine different operating strategies and recommends the best strategy for a steeply dipping reservoir.

An Improved Model for Predicting Heat Losses and Pressure Changes in Steam Injection Wells—Part 2: Model Evaluation

The improved model developed in Part 1 for predicting heat losses and pressure changes in steam injection wells is evaluated. It shows good agreement with limited field data. The improved model is used to predict the effects of steam injection time, rate and pressure, well depth and tubing diameter on heat losses, bottomhole pressure and downhole steam quality. A design example is presented to illustrate the solution method for a common field operations problem.

Steamdrive Performance in a Layered Reservoir—A Simulation Sensitivity Study

Summary This paper describes the use of a thermal reservoir simulator to study steamdrive in a reservoir consisting of noncommunieating sand layers. The simulator was used to determine basic design parameters for steamdrive operations in the South Belridge field, Kern County, CA. Sensitivity runs were made to investigate the effect of various parameters—such as spacing, steam quality, and steam injection rate—on performance. Comparisons were made of the performance of a layered system with no communication between layers and that of an identical system with vertical communication.

Heavy Oil From Kentucky Tar Sands By Using a Wet Combustion Process

Summary The size of the heavy oil or tar sands resource base in western Kentucky is currently estimated at 3.4 × 10- bbl [0.54 × 10 m3] of heavy oil or bitumen in place. Westken Petroleum Corp. constructed a 1-acre [4047-m2] inverted seven-spot pattern in the summer and fall of 1981 to produce heavy oil from the Big Clifty formation tar sands on a 19,000-acre [76.9 × 106-m2] lease in Edmonson County, KY, which contains more than 400 × 10 bbl [63.6 × 10 m3] of heavy oil in face (OIP). Through March 1983, 6,005 bbl [955 m ] of 10API [1.0-g/cm3] oil were produced from this pilot, representing 22.5% of the original oil in place (OOIP) on the 1-acre [4047-m2] pattern. Very satisfactory production rates and air/oil ratios (AOR's) were achieved. production rates and air/oil ratios (AOR's) were achieved. Ultimate recovery with this improved wet-combustion technology is estimated at approximately 50% of the OOIP. Heavy-oil production costs, including investment amortization and interest of $12 to $16/bbl [$75.50 to $101/m3], are projected for production of heavy oil from Kentucky tar sands with this approach. Reservoir characteristics The heavy oil or tar sands in this area exist in three different clean, well-consolidated sand formations:an uppermost deposit in the Caseyville sandstone, which outcrops in the area,a deposit in the Hardinsburg sandstone at a depth of about 150 ft [45.7 m], anda deposit in the Big Clifty or Jackson sandstone at a depth of 350 to 450 ft [106.7 to 137.2 m]. Table 1 gives a general summary of the characteristics of the reservoirs in the Edmonson County area based on analysis of more than 60 core holes in the area. Crude-Oil Quality and Processing The quality of the heavy oil from the Edmonson County deposits is compared with other heavy oils in Table 2 and Fig. 1. Table 2 shows that although the oil from the Big Clifty tar sands is a heavy crude, it is significantly better than the oil in the Utah tar sands and only somewhat more viscous than the commercially produced California Midway-Sunset crude. Estimated refining yields from the crude based on fluid coking and catalytic cracking processing are listed in Table 3. Economic processing of the crude to high yields of gasoline and middle distillate will require high bottoms conversion refining capacity. Extraction Processes Previous work on in-situ extraction processes for these Previous work on in-situ extraction processes for these Kentucky tar sands includes the work of Gulf Oil Co., who carried out a fireflood in the Caseyville formation with a small test pattern in 1959. Gulf reported a 54% recovery of the OIP during a dry fireflood following a hydraulically propped fracture of the formation. In 1969 Sunset Petroleum, with the assistance of Tejas Petroleum Engineers,* initiated a test operation in the Big Petroleum Engineers,* initiated a test operation in the Big Clifty. This test was successful in producing oil but was discontinued before technical results were available. Pilot Field Test Pilot Field Test For the Big Clifty project, Westken consulted with the Tejas Petroleum Engineers and elected to use a forward wet combustion preceded by a steam preheat to establish good communication with the producing wells. Westken designed, constructed, and operated the 1-acre [4047-m2] inverted seven-spot pilot facility (Fig. 2). The equipment included a 25 × 10 -Btu/hr [26.37-kl/h] oilfield boiler to produce 80% steam and an 800 × 10 -scf/D produce 80% steam and an 800 × 10 -scf/D [22.65 × 10 -std m3/d] electric-driven, reciprocating air compressor. All fluids were produced by flowing the producing wells. Flue gas and the produced liquids were producing wells. Flue gas and the produced liquids were separated at the surface. No downhole pumps were used. The reservoir properties in the 1-acre [4047-m2] pattern are summarized in Table 4. Steam Preheat Pilot Results The first step in the pilot operation was a steam preheat operation. High-pressure steam was injected down the injection well to establish a hot path to each of the producing wells, thereby facilitating the movement of the oil and producing wells, thereby facilitating the movement of the oil and flue gas in advance of the flame front on initiation of burn. Because the oil was highly viscous, the initial mobility of the formation was low. However, as the steam-heated area increased, the formation mobility improved markedly. The rate of steam injection is shown in Fig. 3. With steam pressures up to 550 psi [3.792 MPa], steam rates increased until rates exceeding 800 B/D [127.2 m3/d] were achieved. Based on the pilot data and on computer analysis, a heat input (net of losses) of about 25 % of the theoretical heat required to bring the entire pattern to steam temperature is needed to establish the hot paths with this technique. JPT P. 2083

A mathematical modeling of the iron blast furnace II: The effects of changes of operating conditions

Abstract On the basis of the mathematical model presented in the previous paper, the effects of changes in operating conditions on the production rate of pig iron, the value of carbon ratio and the softening‐melting zone level have also been studied. The operating conditions considered are top pressure, size of iron ore, flow rate of blast, blast temperature, steam injection rate, oil injection rate and pre‐reduction of iron ore.

Limitations on the Oil/Steam Ratio for Truly Viscous Crudes

Summary Scaled physical model studies have yielded results that suggest very viscous crude oils with a viscosity somewhat greater than that of San Joaquin Valley crudes cannot be economically recovered by an unassisted steamdrive. Introduction Steamdrive has been used successfully for almost two decades for the economic recovery of viscous crudes. One of the large targets for steamdrive has been implicitly assumed to be the large accumulations of very viscous crudes with a gravity less than 10API [1 g/cm 3]. Some of the early scaled physical model studies of the steamdrive indicated that the viscosity of the oil at steam temperature had a significant effect on the efficiency of the steamdrive. The experimental work indicated that the growth of a steam zone was not independent of the viscosity of the reservoir fluid, contrary to the implicit assumption made in the Marx-Langenheim analysis of the steamdrive. This raised questions about whether the steamdrive could be successful in recovering very viscous crudes and bitumens. Some investigators point out that other factors, such as pattern size, optimal injection rates, etc., limit the application of the steamdrive. However, most of these factors are controllable and can be adjusted before the steamdrive is started. Further, some investigators have concluded from laboratory and field results that the hot-water drive associated with steam injection made a significant contribution to recovering viscous crudes. There can be little question that the viscosity of the crude is a factor in water-drive efficiency. Even assuming that the viscosity of the crude will not affect its ultimate residual saturation to a water drive, the efficiency of a water drive in terms of the number of PV's required to reach the residual must be significantly affected by the oil viscosity. Therefore, the hot-water-drive components of steamdrive cannot be expected to contribute significantly in attempts to recover very viscous crude oils. A series of scaled physical model studies was undertaken to elaborate on the effect of viscosity on steamdrive. Preliminary results have been reported earlier; but in view of the important issues raised by the findings of this work, the completed study is reported here. Experimental Procedure The use of scaled physical models and the procedures used for modeling steamdrive have been described already. To achieve the goal of this work, the models were saturated with prototype crudes that had a range of viscosities at 100F [38C] from 3 cp to more than 100,000 cp [0.003 to 100 Pa s]. The initial oil saturation was 85 to 92 % in a uniform, confined 6-acre [145 687-M2], five-spot pattern. The model simulated one quarter of a confined 6-acre [ 145 687-m 2], five-spot pattern with a uniform porosity of 35%. In most of the pattern with a uniform porosity of 35%. In most of the experiments the prototype reservoir thickness was 73.5 ft [22 m] and the absolute permeability in the range of 1 to 2 darcies. A few experiments also were conducted with a model that corresponded to a reservoir only 27 ft [8 m] thick. In all experiments the steam initially coursed through the model at the top of the reservoir-i.e., it overrode the oil column either fortuitously or by initially establishing a gas saturation amounting to 1 to 3% of the reservoir volume. In actual oilfield operations, the steam may or may not enter initially at the top of the reservoir, depending on the reservoir lithology and the distribution of the saturating fluids. However, in a steamdrive the steam eventually does reach an upper barrier to its further flow, and the overall performance of the steamdrive will approach the performance of a reservoir in which the steam did enter initially at the top. Because initial entry in these experiments was always at the top, a measure of consistency in the various experiments was introduced. To make a valid comparison between all the runs, the rate of steam injection was standardized at a value that had been determined earlier as optimal for prototype crude oils with a viscosity at 100F [38C] in the range of 1,000 to 5,000 cp [ 1 to 5 Pa s] (San Joaquin Valley crudes)-130 to 150 B/D [21 to 24 m3/d] of water (converted to steam) per acre. The viscosity of the crudes at the prototype steam temperatures varied from 0. 15 to 85 cp [0.00015 to 0.085 Pa s]. Finally, various runs of steamdrives were compared by use of the "stable" oil/steam ratio that developed following steam breakthrough (see Fig. 1). JPT P. 1123

Calculation Methods for Linear and Radial Steam Flow in Oil Reservoirs

Abstract The flow of oil and water in a reservoir as a result of steam injection is related to the shape of the growing steam zone. Analytical formulas describing the approximate shape of this zone have been derived both for linear flow in horizontal and dipping formations and for radial flow around injection wells in a horizontal formation. The theory is based on segregated-flow principles such as those previously used by Dupuit,1 Dietz,2 and others. The formulas take into account gravity overlay of steam zones and have been checked against results of scaled laboratory experiments, steam-injection projects in the field, and calculations with a numerical reservoir simulator. From the good agreement with the new calculation method it would seem that the shape of a steam zone is controlled mainly by one group of parameters including steam-injection rate, pressure, and effective formation permeability to steam. The equations can be used to analyze and explain field observations, such as the position of steam/liquid contacts in injection wells, estimates of effective permeability to steam in steam zones, and steam-zone thickness as noticed in observation wells. This paper shows, for example, how a cumulative oil/steam ratio for oil displaced from a steam zone depends on steam-zone pressure, injection rate, and time. With increasing oil viscosity, more bypassing of oil by steam owing to viscous forces will occur, leading to more overlay of steam zones and eventually to narrow tonguing in a lateral direction. The calculation methods provide an evaluation tool for steamdrive and steam-soak processes to reservoir engineers engaged in field operations, project design, and research.

The Influence of Oil Viscosity and Thickness on the Steam Drive

Summary A correlation of steamdrive efficiency, based on model studies, predicts that it will fall as the viscosity of the crude at steam temperature increases. Sensitivity to viscosity results from the overlay of steam, which also mitigates the influence of reservoir thickness. High efficiency, expected of frontal displacement, is realized in the recovery of high-gravity crudes. Introduction Physical scaled models of the steam drive have reproduced many features of field operations. One of the most pronounced features of the steam drive is the overlay of steam above the oil column and its subsequent stratified flow to the producing well. This is in contrast to frontal displacement that was assumed in early analytical models. The effects of various reservoir and operational parameters therefore may be different from those originally deduced on the basis of frontal advance concepts. Three important parameters used to assess the feasibility of steamdrive operations are (1) rate of injection of steam and its quality, (2) viscosity of the crude oil, and (3) reservoir thickness. The most frequently used analytical model and its modification do not attribute any effect of the crude oil viscosity on the efficiency of the steam drive. Steam zone growth and the corresponding depletion of oil are based exclusively on the way in which heat is distributed within the reservoir. The quality of the steam and its injection rate are both shown to be important, with the resulting oil/steam ratio monotonically increasing with each. On the other hand, field and model studies have indicated that there is an optimal rate of steam injection to attain a maximum oil/steam ratio. The analytical models predict that the efficiency of the steamdrive process as measured by the oil/steam ratio will vary directly with a function of reservoir thickness, whereas results obtained from field operations in which steam stimulation did not contribute significantly to the overall performance suggest that thickness may not have the pronounced effect that is predicted. The purpose of this work was to elucidate the role of oil viscosity and reservoir thickness in steamdrive operations in which gravity segregation of the steam and its stratified flow dominate the process. Steamdrive Analysis Based on Stratified Steam Flow Steam initially enters a viscous oil reservoir through a depleted or wet interval, a fracture, or a fluidized interval. If the initial entry is not at the top of the oil section, the steam rapidly migrates upward because of the strong gravitational gradients imposed by the marked difference in density between the steam and the reservoir fluids. The rate of upward migration depends on vertical permeability and viscosity of the crude oil at steam temperature - that is, the concurrent drainage rate of the heated crude oil. JPT P. 291^