Steam Zone Research Articles

Qarn Alam; the design of a steam-injection pilot project for a fractured reservoir

In July 1996 a steam-injection pilot project was initiated in the Qarn Alam field in Oman. The objective is to test the steam-enhanced gas-oil gravity drainage of the heavy oil remaining in the matrix of the fractured carbonate Shuaiba reservoir. This paper presents the results of reservoir simulations that were conducted to investigate design and future interpretation of the steam pilot. Different simulation techniques were applied to describe the complexity of thermal processes and multiphase flow in a densely fractured reservoir. Pilot performance and areal advance of the steam zone were investigated. The possibility of oil rim lowering, prior to injecting steam, and of injecting steam in two different local crests, were also investigated but rejected on the basis of simulation results. Finally, locations for steam injection wells and pilot observation wells are proposed and requirements for pilot monitoring deduced.

Mathematical model of water injection into a geothermal steam-saturated reservoir

A mathematical model of the process of water injection into a geothermal high-temperature steam-saturated reservoir is proposed. The steam and water zones are separated by a moving interface (phase transition front) whose location is determined in the process of solving the problem. It is shown that for low permeabilities the solution contains a thermodynamic contradiction expressed as supercooling of the steam ahead of the interface. Critical curves bounding the regions of existence of the frontal solution are constructed.

The effect of steam quality on the electrical behavior of steam‐flooded sands: A laboratory study

Laboratory measurements of the effects of steam injection on the electrical conductivity of sands can aid in the interpretation of electrical surveys used to monitor subsurface steam‐injection projects. The effect of variations in injected steam quality was measured in the experiments presented here. The injection of low‐quality steam, boiled from a 0.01 mol/L NaCl solution, into clean sand saturated with 0.01 mol/L NaCl, resulted in a net decrease in conductivity and a constant equilibrium conductivity in the steam zone. The injection of high‐quality steam, using the same saturating and injection salinities, caused the conductivity to first drop to a minimum and then to increase to an equilibrium value similar to that seen in the low‐quality injection. The local conductivity minimum deepened with time and traveled with the steam front. The appearance of the conductivity minimum at the steam front can be attributed to the formation of a dilution bank, which temporarily decreases the local salinity. The extent of the dilution increases with time, resulting in the decrease of the conductivity over time. The conductivity then increases as injected salt moves through the sand. The steam quality controls the appearance of this minimum because it determines the relative speeds of the steam front and the steam liquid: a minimum will not occur if the steam front moves more slowly than the steam liquid.

Enhanced Steam-assisted Gravity Drainage: A New Horizontal Well Recovery Process For Peace River, Canada

Abstract A new horizontal well recovery process, developed for application in the Peace River tar sands of Alberta, Canada, has shown sufficient technical and economic potential to warrant a field test which commenced operations in November 1993. The new process is an enhanced version of the steam assisted gravity drainage(1,2) (SAGD) process which is currently being field tested by Alberta Oil Sands Technology and Research Authority (AOSTRA) together with a consortium of industry members at the Underground Test Facility (UTF) located in northern Alberta(3–5). The SAGD well configuration, which consists of two parallel and superposed horizontal wells, with continuous steam injection occurring in the upper well and liquid and gas production from the lower well, is also utilized in the Enhanced Steam Assisted Gravity Drainage (ESAGD) process. A performance enhancement to the SAGD process is obtained through the application of a small pressure differential between adjacent pattern steam chambers. The gentle "steam drive," which occurs once sufficient bitumen mobility has been obtained between steam chambers, is observed to be tolerant of reservoir heterogeneities. Additional benefits include accelerated steam zone growth and bitumen production, up to 50% improvement in ultimate recovery efficiency, and no impairment to the thermal efficiency relative to the SAGO process. The surface access 'ESAGD field test currently underway in Peace River is described. The Peace River oil sands are 10caEed in northwestern Alberta (Figure I). Following the oil sand deposit discovery in 1949, Shell Canada began testing a variety of in situ recovery processes, including steam soak tests in 1962. steam drive and in situ combustion testing in 1965–66, followed by steam injectivity and productivity tests in 1973–74(6,7). A 31-well pilot (Peace River In Situ Pilot - PRlSP; see Figure 2) began operations in 1979, testing the pressure cycle steam drive process(7–9). Pilot operations ended in 1992 at a cumulative recovery efficiency of 65% and cumulative oil steam ratio of 0.25. In 1986, Shell Canada commenced operations in [he Peace River Expansion Project (PREP). the only commercial project in [he Peace River oil sands, with a target production of 1,600 m3/day of bitumen from 163 producers(10). The need to improve production economics by reducing production costs was the motivation behind the Peace River horizontal well study, which began in early 1991. The use of horizontal wells in a pattern steam drive was shown via numerical simulation to result in poor recovery and thermal efficiency due 10 poor steam conformance. This led to the numerical simulation study of SAGD (1,2). SAGD without any performance enhancements did not appear to yield the desired performance uplift in Peace River. Further study ultimately led to the development of the ESAGD process. Geological Description The Peace River oil sand deposit covers an area of approximately 6,200 square kilometres and contains some 12 billion cubic metres of bitumen. The productive horizon is found in the Bullhead member of the Cretaceous Bluesky/Gething zone at an average depth of 600 m, and is geologically equivalent to the shallower. productive McMurray sands in Northeastern Alberta(11).

Surface hydrothermal alteration and evolution of the Te Kopia Thermal Area, New Zealand

The Te Kopia Thermal Area has surface manifestations that extend over an area of about 3 × 1.2 km along the Paeroa Fault Zone. Steaming ground, fumaroles, mud and acid sulphate pools are present on both the upthrown and downthrown blocks of the Paeroa Fault, but near-neutral pH chloride-bicarbonate springs discharge up to 2 km west of the fault trace. The host rocks comprise mainly Quaternary ignimbrites that dip gently (∼7°) eastwards but are vertically displaced by the fault by several hundred metres. Hydrothermal alteration is widespread, and the present thermal activity is now producing kaolinite, alunite, silica residue, hematite and cristobalite. This assemblage occurs both in the otherwise unaltered ignimbrites, as well as overprinting the products of earlier hydrothermal activity. Evidence for changes that have occurred in the nature and extent of thermal activity at Te Kopia include: (1) The widespread overprint of a kaolinite-alunite-cristobalite assemblage upon hydrothermal minerals (including adularia, quartz and mordenite) produced by alkali-chloride, bicarbonate-chloride, and heated groundwaters. (2) The occurrence of silica sinter which deposited from alkali chloride springs that discharged about 3000 years ago. This is now a steam zone. (3) Areas of cold ground that were once hot, as demonstrated by the presence of hydrothermal minerals. (4) The presence of euhedral quartz crystals at the surface on the upthrown fault block. Fluid inclusions in these crystals from two places homogenise at 188 ±15° C and 196 ±11° C. The trapped fluids have apparent salinities between 0.2 and 0.4 wt % NaCl equivalent. The quartz crystals thus grew at depths of at least 120 m below the water table. Vertical movements along the Paeroa Fault totalling at least 300 m have uplifted these crystals to their present positions. The surface geology and alteration provide evidence that thermal activity at Te Kopia has been long lived, possibly as long at 120 000 years. However, the hydrology of the system and its thermal regime have changed greatly during its lifetime, mainly in response to movements along the Paeroa Fault.

Electrical resistivity measurement through metal casing

Methods using dc electrical arrays to measure formation resistivity through casing have relied on approximate forms for the current and potential distributions to derive a simple relationship between the formation resistivity and the transverse resistance calculated from measurements of the potential and its second derivative inside the casing. We have derived a numerical solution for the potentials and their derivatives to examine the accuracy of the approximate forms for casing of finite‐length, annular zones of varying radius, and for vertical discontinuities such as layers or abrupt changes in annular zone radius. For typical conductivity contrasts between the casing and formation, the approximate relationships may be off by as much as 60 percent for long casing and may show variations of 20 to 30 percent as the electrode array moves along the casing. In principle an iterative scheme could be devised to correct the readings if high accuracy was required. The numerical results show that to first order the current flow from the casing is radial, and that all the analytic expressions based on this assumption for evaluating layer resolution and the effects of annular layers are valid. An interesting byproduct of this study has been the discovery that the distortion of the potentials in a nearby well by an annular disk (e.g., an injected steam zone) surrounding the current injection well is greater if the injection well is cased. Crosswell resistivity surveys appear feasible if one of the wells is cased.

Post Core Analysis to Determine the Steam Flow Path In the McMurray Oil Sands

Abstract Core analysis was performed on core material extracted from three post-recovery core holes drilled at distances varying from 12 to 20 m from a wellbore that had experienced eight cycles of steam injection/production (I/P). The objective was to evaluate the success of cyclically steaming the McMurray oil sand by ascertaining steam placement and the effect of steam on the reservoir mineralogy. Post core-hole analysis was compared to the original core of the centrally located I/P well using standard techniques plus a number of special core analyses. X-radiography, connate water analysis, tracer analysis, absolute and effective permeability measurements, petrographic analysis, in addition to selected open-hole and cased-hole logs were included in these special studies. Results showed that reduction in oil saturation over the oil sand interval was attributed to steaming and/or a combination of condensed steam invasion and drilling mud invasion. The actual steam-invaded zone was shown to be a lesser portion of the total oil sand pay which could be correlated with the special core analyses and with temperature logs. This paper describes the procedures used to assist in determining steam zones and includes an interpretation of the data as well as a critique of the analyses. Introduction In-situ bitumen recovery from the Athabasca oil sands, the largest oil sand reserves in the world, has not yet been commercialized. Successful steam recovery processes such as cyclic steam at Cold Lake(1) or steam drive at Peace River(2), have had limited success when applied in the McMurray oil sands formation at PCEJ(3,4) and GLISP(5). A number of factors have been recognized which make in-situ recovery from this resource more difficult:Lower reservoir temperature and pressure, higher bitumen viscosity, and sand migration prevent primary production. Typical reservoir properties in the PCEJ Hangingstone lease are presented in Table 1.Shallow depth of burial and low initial breakdown pressures(6) combined with very high bitumen saturation, limits leak-off of the injected steam and encourages fracturing. Less placement of heat near the wellbore results in lower calendar day oil rates (CDOR).A combination of vertical and horizontal fractures(3,7,8) ("T" Fractures) tend to make bitumen recovery schemes more complicated and less productive. A ("T" fracture is shown in Figure 1 as an initial vertical fracture climbing at 45 degrees from the perforations up into the shaley oil sand above, where it turns horizontal and can even travel back to the well, but at a shallower depth. Horizontal fractures in the upper shaley oil sand do not characteristically produce much bitumen even though it may hold up to 40% of the total injected steam. TABLE 1: Typical properties of McMurray oil sand (Hangingstone). (Available in full paper) Steam injection fractures were utilized to heat the formation at the PCEJ Hangstone Pilot Project located 45 km south-west of Fort McMurray. Different steam placement strategies were rested in individual cycles and in various isolated wells in an attempt to keep the heat within the rich oil sand. This was done by controlling injection rates, quality and volume injected.

Analytical model of steam zone propagation in porous media

Steam injected into oil-bearing porous media forms a steam zone which propagates in three-dimensional space. The injected steam forms the condensation front bounding the seam zone. Simultaneous mass and the energy transfers take place through this moving boundary, between the rocks and fluids inside and outside the steam zone. The energy transfer is by conduction and convection. A new mathematical model describes the propagation growth of the steam zone subject to initial and boundary conditions, and is applicable in a general case of heterogeneous steam zone of arbitrary geometry. The model is based on the simultaneous analytical solution of the coupled overall mass and energy balance equations for a multi-phase steam zone, and is presented here for the first time. The resulting nonlinear integral equation does not have an analytical solution for a general case. The exact solution is found for a cylindrical homogeneous steam zone. For a special case of a one-dimensional, two phase steam zone, this solution shows excellent agreement with available experimental data.

Development history of the Tiwi geothermal field, Philippines

Commercial production of electricity from the Tiwi geothermal system began in 1979. In 1982, Tiwi became the world's first water-dominated system to produce more than 160 MWe. Today the field supplies about 11% of Luzon's electricity. Initially, the reservoir was single-phase liquid with a small, shallow steam zone on the east side. Temperature reversals in the first wells showed the east to be an outflow zone. As production began, reservoir pressure declined, two-phase conditions developed, and groundwater entered the reservoir from the east. As many production wells cooled, brine production increased and generation decreased from about 280 MWe in 1983 to about 190 MWe in 1986. Improvements to surface facilities and new wells drilled farther west raised generation to about 280 MWe by mid-1993. Separated brine was first injected into the reservoir, but this lowered steam production; injection is now outside the field.

A Steam Assisted Gravity Drainage Model For Tar Sands: Radial Geometry

Abstract This paper presents a new model for oil production during steam assisted gravity drainage (SAGD) in tar sands in radial geometry e.g., around vertical wells. The model assumes that the steam zone is an inverted cone, the temperature profile in the oil declines exponentially with distance away from me steam/oil interface, and the viscosity depends on the temperature through a power law. An energy balance is used to determine the latent heat injection fate for steam to expand the steam zone and balance eat losses. The energy balance and oil production fate equations are combined to estimate the steam-oil ratio for this process. Results obtained with this model suggest that SAGD in radial geometry is a promising recovery process. Additional studies of the process are recommended. Introduction One of the few successful oil recovery methods for tar sands is steam injection. The high temperature of the steam lowers the itumen viscosity allowing it to flow toward production wells. During steam injection, the density difference between the injected steam vapor and the oil induces gravity segregation of the phases in the reservoir. The steam vapor rises to the top of the formation, while the heated oil drains to the lower parts of the reservoir. Steam Assisted Gravity Drainage (SAGD) in linear geometry along horizontal wells has received considerable attention and a number of models for this process have been developed(1–5). SAGD in radial geometry around a single, vertical well has not received as much study, but may also become an important recovery process. During this process, steam is injected into the reservoir through a vertical well and fluids are produced from the bottom of the formation. Experimental studies of the SAGD process in radial geometry have shown that the steam zone shape around the injection well is roughly an inverted cone with the vertex at the bottom of the well. In this paper, a conic steam zone shape will be used in developing a model for the SAGO process in radial geometry. A conic steam zone shape has also been used in modeling team injection in lower-viscosity, heavy-oil reservoirs(6–7). One proposed application of the SAGD process in radial geometry is the Single-Well Injection/Production Steamflood (SWIPS) or vertical HASDrive process(8–9). SAGD in radial geometry is also expected to be important around a vertical injection, while in the horizontal well HASDrive process(10), In the SWIPS process the vertical well can be dually completed as an injector at the top and a producer at the bottom, while in the horizontal well HASDrive process, the fluids are pushed from the vertical injection well along a heated horizontal well at the bottom of the formation to a separate production well. Model Derivation The oil flow rate in the bitumen along the steam zone interface from gravity drainage can be found using Darcy's Law. If qo is the oil drainage rate at a given height, the oil flow rate can be expressed as Equation (1) Available In Full Paper where is the hydrostatic potential difference between the steam and oil along the steam zone interface,

Steam Injection Into a Slow Water Flow Through Porous Media

Steam injection into a slow water flow (Darcy flow) was studied analytically for steady-state conditions. The continuity, momentum, and energy equations for both water flow and steam flow were solved subject to interface conditions. The governing equations were transformed using stream function and velocity potential coordinates to simplify the calculation domain. The resulting energy equation was converted to a simultaneous ordinary differential equation by an integral method. The unknown steam-water interface shape and location were determined through an optimization process. Temperature distribution on the water side, local condensation rate along the interface, water and steam flow fields and pressure distribution were found numerically. Comparison with experimental measurements showed that the average steam zone size could be fairly well predicted only when dispersion effects were incorporated into a modified thermal conductivity model.

The Evalua1Ion Of Cyclic Steam Sltimulation Of An Oil Sand Reservoir Using Post-Steam Core Analysis

Abstract A post-steam core was recovered from a Cold Lake area oil sand reservoir subjected to cyclic steam stimulation. The objective of the program war to recover competent core from a steamed portion of the reservoir and, via detailed core analysis, determine the effect of steam injection on the deteriorating productivity levels experienced at the pilot test wells. The core was successfully retrieved by sidetracking from an existing expendable wellbore which had received four cycles of steam injection. The coring program was accomplished at a cost considerably less than that of a new well. Core recovery war satisfactory at 84%, considering the approach used. Mineralogical analyses performed on the recovered core provided an improved understanding of the recovery mechanisms involved in steam stimulation of the reservoir, Some of the major findings were: 1. Vertical sweep efficiency was determined to be 60%. 2. Mineral reactions were confirmed and found to be a factor responsible for decreased absolute permeability. 3. The dissolution of feldspar may have contributed to suppressing the degree of swelling clay formation. 4. Thin impermeable calcite layers within the reservoir contributed to steam confinement within specific zones. These observations helped to explain the production performance recorded at the test wells and the knowledge was adapted to the development of future thermal operations at the pilot. Introduction Reservoir sweep efficiency is an important parameter to determine when evaluating a cyclic steam process. Conventional methods generally used to estimate sweep efficiency include observation wells, temperature logging, seismic profiling and post-recovery coring. Observation wells can be risky because they may not intersect the steamed zone. When the steam zone reaches an observation well, vertical sweep efficiency can be estimated from temperature logs run in the well, Temperature logs, however, have been shown to overestimate the thickness of the steam swept zone as a result of profile smearing(1). Seismic profiling can provide 3-dimensional seismic images which can be used to track the movement of induced heat fronts(2). This technology is relatively new and very expensive; these aspects tend to preclude its use in thermal projects. The most accurate method of determining vertical sweep efficiency is by extracting post-steam core(s) from a steamed portion of the reservoir. This is the only method that can provide tangible evidence which accurately reflects the portion of the reservoir actually swept by steam. Another important factor associated with cyclic steam stimulation is the effect of steam injection on the mineralogy of the reservoir(3–6). Perhaps the greatest benefit of obtaining a post-steam core is the opportunity to provide unequivocal mineralogical evidence concerning the defects of steam injection on the reservoir mineralogy. Such information could also provide a valuable test for geochemical models that utilize produced fluid compositions from thermal recovery projects to monitor mineral reactions occurring in situ(7, 8). This paper will deal with how a post-steam core program was used to provide the evidence necessary to help understand deteriorating productivity levels observed at an experimental cyclic steam pilot in the Cold Lake area of Alberta. A proprietary steam additive designed to control the swelling of smectitic clay minerals formed during steam injection was also being tested at the pilot in all attempt to limit reservoir damage that was believed to be occurring. Recovery and examination of post-steam core was necessary to confirm that reservoir damage had

The effects of steam injection on the electrical conductivity of an unconsolidated sand saturated with a salt solution

The spatial and temporal variation of electrical conductivity in saturated sands during steam injection has been measured and modelled. Experiments consisted of introducing steam into one end of a tube filled with sand saturated with a slightly saline solution. A steam condensation front formed, separating the mixed‐phase steam zone from the liquid zone. Measurements of electrical conductivity were made at 10 locations along the tube using a four‐electrode technique. Results show that conductivity starts at a constant value, decreases before the steam front arrives and then, immediately prior to the steam front arrival, goes through a maximum before dropping by a factor of about 25. These variations can be explained by first, a dilution of the interstitial solution causing the initial drop in conductivity; second, an increase in temperature of the solution immediately prior to the arrival of the steam front causing the conductivity maximum; and finally, the large drop in conductivity due to the combined effects of a decrease in saturation and dilution of the residual liquid in the two‐phase zone. Mathematical solutions of a set of differential equations that take into consideration all of these effects are presented. These solutions reproduce the significant features of the conductivity data. This study suggests that the measurement of changes in the subsurface conductivity field during steam injection operations may indicate the location of ionic concentration, temperature, and steam saturation fields.

A Steam-Assisted Gravity Drainage Model For Tar Sands: Linear Geometry

Abstract This paper presents a new predictive model for gravity drainage in tar sands during steam injection in linear geometry, e.g. along horizontal wells. The model has been validated against published experimental data. The model assumes that the steam Zone shape is an inverted triangle with the lower vertex fixed at the production well. The temperature profile in the oil is assumed to decline exponentially with distance away from the steam/oil interface, but unlike previously published models, the temperature decline is independent of position on the interface. An energy balance is used to determine the latent heat injection rate for steam to expand the steam zone, preheat the formation ahead of the steam zone, and balance heat losses to the overburden. The energy balance and oil production rate equations are combined to yield the steam-oil ratio for this process. Introduction Oil recovery from tar sands is limited to the very high viscosity of the oil (bitumen). Injecting steam to lower the viscosity is one of the few in situ methods for recovering this resource. The most widely used process is cyclic steam injection, but because this process can only contact a small fraction of a reservoir, the amount of oil it can recover is limited. Steam drive is a proven recovery method for reservoirs having a lower oil viscosity, but is unreliable In tar sands because the high bitumen viscosity inhibits communication between the injection and production wells. Recent developments in horizontal well technology now make new methods to recover oil from tar sands feasible. One promising new process is the Steam-assisted Gravity Drainage (SAGO) process. [0 this process, steam is injected into the formation through a horizontal well and oil drains into a separate, parallel, horizontal well located below the injection well. A variation on this recovery process is to inject steam into vel1.ical wells and drain the oil to a lower horizontal well. The driving force for oil production in the SAGO process is the density difference between the steam vapour and the bitumen. Two now regimes for gravity drainage are possible, depending on how the steam is injected: (I) where the steam fingers upward into a cold reservoir and oil flows downward in counter current flow (1–3), and (2) where oil drains downward along the interface or a laterally expanding steam zone(4–6). This paper presents a new model for the latter process. Steam Zone Model During steam injection, the steam zone will grow laterally as oil drains along the steam/oil interface to the production well. The steam zone near the overburden will widen, while near the bottom it will remain essentially fixed at the production well. The resulting steam zone cross section will be roughly an inverted triangle, as shown in Figure l. For this configuration, assume a coordinate system fixed to the moving steam/oil interface, with coordinates εand η, perpendicular and parallel to the interface, respectively. Oil will drain along the interface, with the drainage rate (velocity) being dependent upon the local viscosity (temperature), which in turn is dependent upon the distance from the interface.

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.

Forward in situ combustion: oil recovery and properties

A series of forward combustion experiments was performed at a maximum pressure of 1020 kPa, oxygen enrichment up to 35 vol% and a range of water-gas injection ratios. The purpose was to investigate the effect of each of these variables on the recovery and properties of the produced oil. The oil production history revealed that lower operating pressure and higher oxygen concentration in the injected gas favour early commencement of oil production. Similar behaviour was obtained with water injection, but only in cases where the injection begins soon after the combustion has stabilized. With continuous water injection, the water cut remains relatively constant at its peak value during wet combustion. This is in contrast to the production pattern during dry combustion, in which the water cut shows a general decline from the peak value. Both the rate of oil production and the overall recovery increased significantly with increasing water injection rate, but decreased with increasing pressure. A small increase in oil recovery was obtained with 35 vol% oxygen enrichment compared with air. In all cases, the oil produced exhibited a more than 20% increase in API gravity, with corresponding viscosity reduction greater than 60%. The observed effects of the process variables on the oil recovery and properties are due mainly to their influence on the size and velocity of the steam zone.

Seismic reflection amplitude versus angle variations over a thermally enhanced oil recovery site

In recent years it has become increasingly important to develop a capability for monitoring enhanced oil recovery (EOR) processes as they are occurring within any reservoir. An amplitude‐versus‐angle (AVA) analysis over a steam injection location showed encouraging results and established that seismic reflection methods, when well designed and carefully processed, can be used to map the invaded steam zones in steam stimulation EOR operations. The results are imaged on a new type of display called ARPA (amplitude‐ratio for partial angle), which illustrates reflection zones with low or high Poisson’s ratio or equivalently high or low gas saturation with a CMP stack section plotted as the background. A seismic experiment consisting of three reflection lines was carried out by Esso Resources in February, 1984 over a steam injection site near Cold Lake, Alberta. Analysis of the field data showed that large variations in reflected scattered energy were a function of angle of incidence in areas affected by the steam zone.

The Design of a Modern Steamflood in a Thick, Dipping, Heavy Oil Reservoir

In 1988, Mobil completed the design phase of a new steamflood project. This project is in a thick, moderately dipping, unconsolidated heavy oil reservoir. The design takes advantage of the gravity drainage recovery mechanism in the thick reservoir, allowing vertical steam zone expansion with minimal steam breakthrough. The steamflood was designed to be economic in the late 1980's period of low oil prices. The design was completed with an interdisciplinary teamwork approach using concurrent studies for expediency. This paper was first presented at the 1989 California Regional Meeting in Bakersfield. The presentation for this meeting will conclude with an update of project performance since 1989.

Simple interpretations of chemical transients in multi-feed, two-phase geothermal wells: examples from philippine geothermal fields

The main process responsible for the extreme variations in chloride concentrations in the water discharged by selected multi-feed, two-phase geothermal wells in the Philippines is steam addition brought about by fluid flashing in the formation or by a shallow and distinct steam zone. Correlation of enthalpy with chloride data over a span of seven years for well 106, Tongonan field, revealed the entry of reservoir fluid from the hotter portion of the field as the well responded to exploitation. Using a plot of discharge enthalpy versus total chloride, the deep chloride near well OP-3D, which is drilled at the periphery of the Bacon-Manito field, has been determined at about 8700 mg/kg. This is somewhat higher than the inferred chloride level of 7000 mg/kg in the postulated main geothermal reservoir. The competing effects of returns of reinjected water and flashing in the formation on the observed chloride concentrations in the discharge water of well PN-20D, Palinpinon field, have been segregated using the technique described above.

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.