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Preliminary Study of In-situ Combustion in Heavy Oil Field in the North of Thailand

  • Bumi Resources Minerals

Abstract and Figures

A small oil field in the north of Thailand has medium viscous and low gas-content heavy oil. Since conventional production methods are ineffective, thermal recovery is potentially suitable to enhance oil recovery for this reservoir. In -situ combustion is a complex EOR process used for medium to heavy crude oils. The process involves the multi-phase fluid flow through porous media with chemical and physical transition of the crude oil components under high temperature and pressure conditions. The simulation results with STARS were investigated by conducting a number of sensitivity studies with varying the parameters like gridblock sizes, air-injection rates, oxygen concentrations, and injected air temperature. The 0.5m-block size was chosen due to the optimum running time with acceptable accuracy. From the results, it can be concluded that changing injection rate from 100 Mscf/d to 400 Mscf/d does not significantly affect cumulative oil production – less than 6% incremental recovery. Increase oxygen concentration from 29% to 100% shows an increase in 40.67% oil production. Moreover, if the injected fluid temperature is increased from 80˚F to 500˚F, total oil production increases 97.14%. Furthermore, optimal operating conditions to enhance recovery of oil were also studied.
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Procedia Earth and Planetary Science 6 ( 2013 ) 326 – 334
1878-5220 © 2013 The Authors. Published by Elsevier B.V.
Selection and/or peer review under responsibilty of Institut Teknologi Bandung and Kyushu University.
doi: 10.1016/j.proeps.2013.01.043
International Symposium on Earth Science and Technology, CINEST 2012
Preliminary Study of In-Situ Combustion in Heavy Oil Field in The
North of Thailand
Metsai Chaipornkaew
, Kantapong Wongrattapitak
, Wiwan Chantarataneewat
Thanapong Boontaeng
, Svein Tore Opdal
and Kreangkrai Maneeintr
PTT Exploration and Production Plc. Bangkok10900,
Department of Mining and Petroleum Engineering, Faculty of Engineering, Chulalongkorn University, Bangkok 10330,
A small oil field in the north of Thailand has medium viscous and low gas-content heavy oil. Since conventional production
methods are ineffective, thermal recovery is potentially suitable to enhance oil recovery for this reservoir. In -situ combustion is a
complex EOR process used for medium to heavy crude oils. The process involves the multi-phase fluid flow through porous
media with chemical and physical transition of the crude oil components under high temperature and pressure conditions. The
simulation results with STARS were investigated by conducting a number of sensitivity studies with varying the parameters like
gridblock sizes, air-injection rates, oxygen concentrations, and injected air temperature. The 0.5m-block size was chosen due to
the optimum running time with acceptable accuracy. From the results, it can be concluded that changing injection rate from 100
Mscf/d to 400 Mscf/d does not significantly affect cumulative oil production less than 6% incremental recovery. Increase
oxygen concentration from 29% to 100% shows an increase in 40.67% oil production. Moreover, if the injected fluid temperature
is increased from 80˚F to 500˚F, total oil production increases 97.14%. Furthermore, optimal operating conditions to enhance
recovery of oil were also studied.
1. Introduction
Owing to the high demand of oil recently, the prices of oil are increasing and the light oil reserves are declining.
Therefore, unconventional oils such as heavy oil and bitumen are of primary interest as new sources of energy in the
future. Although the resources of unconventional oils in the world are more than twice those of conventional light
crude oil (Dusseault, 2001), many current technologies cannot satisfy their efficient production even with high oil
The main challenge of heavy oil production is the high viscosity of the oil. The conventional methods for this
kind of oil are not suitable. Accordingly, effective technology used for heavy-oil production nowadays is thermal
recovery such as cyclic steam stimulation, steam flooding, steam assisted gravity drainage (SAGD) and in -situ
combustion (Lyons and Plisga, 2005).
* Corresponding author. Tel.: +662-218-6854 ; fax: +662-218-6920 .
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Metsai Chaipornkaew et al. / Procedia Earth and Planetary Science 6 ( 2013 ) 326 – 334
In-situ combustion is a thermal process in which thermal energy is generated in the reservoir by combustion.
Recovery mechanisms include viscosity reduction from heating, vaporization of fluids, and thermal cracking. In the
heating and combustion that occur at high temperature up to 1100 °C (Farouq Ali et al., 1997), the lighter
components of the oil are vaporized and move ahead. Depending on the temperature attained, thermal cracking may
occur, and light hydrocarbons from this reaction also move downstream. Part of the oil is deposited as a coke-like
material on the reservoir rock, and this solid material serves as the fuel in the process. Thus, as oxygen injection is
continued, a combustion front slowly propagates through the reservoir, with the reaction components displacing
vapor and liquids ahead toward production wells. An example of this method is shown at Mehsana (Doraiah et al.,
1986) and Bellevue Field Project (Long and Nuar, 1982). An application of in-situ combustion is Toe to Heel Air
Injection (THAI) technology developed by Petrobank Energy and Resources Ltd. This is a very new and
experimental method that combines a vertical air injection well with a horizontal production well in a single system
However, a major problem of in-situ combustion is the control of the movement of the combustion front (Lyons
andPlisga, 2005). Depending on the reservoir characteristics and fluid distributions, the combustion front may move
in a non-uniform manner through the reservoir, with resulting poor volumetric sweep. Also, if proper conditions are
not maintained at the combustion front, the combustion reaction can weaken and cease completely. The process
effectiveness is lost if this occurs.
The parameters such as air-injection rates, oxygen concentrations, and injected air temperature play a significant
role for in-situ combustion process because they can control the sustainability of the combustion front. Therefore,
the objectives of this work are to investigate the effects of those parameters on the production of heavy oil, as well
as to find the optimal conditions to enhance the efficiency of oil production by using reservoir simulation.
1.1. Characteristics of Reservoir and Heavy Oil
Characteristics of heavy oil from the north of Thailand can be concluded as shown in Table 1 (Sirisawadwattana
et al., 2012). This formation is unconsolidated sandstone formation with permeabilities averaging 500 md containing
medium heavy oil with viscosity around 54 cP. In-situ combustion is one of the candidates for effective oil
production for this type of reservoir as its properties are within the recommended range suggested by Taber et al.
Table 1. Characteristics of reservoir and fluid
Characteristics of Oil and Reservoir
Porosity (%)
Permeability (md)
Initial oil saturation (%)
Initial reservoir pressure (psia)
Initial reservoir temperature (
Oil gravity (
Oil viscosity at reservoir conditions (cP)
2. Simulation Model
STARS, one of the simulators widely used for thermal process modeling today, is selected to simulate this system
for in-situ combustion. The mathematical description of the model is based on an in-situ combustion model
developed by Coats (1980). The formulation is considered general because it can be used with any number and
identities of components, distributed in any phases (water, oil, gas and solid). Furthermore, this model does not use
any assumptions regarding degree of oxygen consumption. The oxygen concentration is calculated throughout the
reservoir. It also simulates the effects of oxygen bypassing caused by kinetic-limited combustion.
The comparisons of the model results with the experiment from Smith and Perkins (Coats, 1980) were also
studied. The simulations have shown consistency with the experimental results. Therefore, a simple vertical tube
model will be applied to study the effect of parameters for in-situ combustion for this work.
328 Metsai Chaipornkaew et al. / Procedia Earth and Planetary Science 6 ( 2013 ) 326 – 334
2.1. Verification of Simulation Model
A simple vertical model as mentioned above is applied to use with the data of this reservoir as shown in Figure 1.
The result showed the applicability of the model to create the in-situ combustion at different stages in this reservoir.
Furthermore, a sector of reservoir was set to investigate further as presented in Figure 2. It can be explained from the
figure that a reservoir with 50m-length and 5m-height (164ft x 16.4ft) was used as a simple, homogeneous 2D
model with constant porosity and permeability. The blue layers at top and bottom of the model were specified as
zero porosity representing shale layers. Each shale layer was 60cm. (1.968 ft) high. The producer and injector were
in the left and right side, respectively. The model developed the temperature profile of combustion from the
reservoir. It was shown in Figure 3 that the dark blue grids represented the lowest temperature, the reservoir
temperature of 140ºF. The light blue-green grids showed where the first ignition took place and the temperature at
these blocks was about 1,000 ºF.
Figure 1. A simple vertical
Figure 2. Applied model for whole range of
Metsai Chaipornkaew et al. / Procedia Earth and Planetary Science 6 ( 2013 ) 326 – 334
Figure 3. Temperature distribution for combustion developed from
3. Simulation Results and Discussion
From the model, sensitivity studies of the parameters were studied. The parameters were grid size, air -injection
rates, oxygen concentrations and injected air temperature.
3.1. Effect of Grid Size
Grid size played an important part in simulation result in term of time-consumption and accuracy. The smaller
grid size, the more accurate results can be obtained but the more computation time consumed. At this point, 1m,
0.5m and 0.25m-grid size were investigated and, as presented in Figure 4, the result showed that the grid size of
0.5m and 0.25m provided results of cumulative production close to each other with less than 8% difference. But a
grid size at 1m offered less amount of production for 85% compared to that of 0.25m-grid size. One more interesting
fact is that the 0.5m-grid size model used less time-consumption for 83% compared to that of 0.25m-grid size.
Consequently, the model of 0.5m-grid size was selected to study further for other parameters due to acceptable
accuracy at less running time.
Figure 4. Effect of grid size on cumulative
3.2. Effect of Injection Rate
The air injection rates used for this study were 100, 200 and 400 Mscf/d. The effects of air injection rate on
cumulative oil production and ignition time presented in term of temperature profile and position of ignition were
330 Metsai Chaipornkaew et al. / Procedia Earth and Planetary Science 6 ( 2013 ) 326 – 334
illustrated in Figure 5 and 6, respectively. From Figure 5 it can be concluded that injection rate has little effect on
the cumulative production because production can increase very little, up to 6%, corresponding to position of fire
ignition in the reservoir presented in Figure 6. Higher injection rate provides more oxygen to react with oil. In this
case it takes less time for reservoir to reach the auto-ignition temperature, but together with faster movement of
oxygen front the ignition positions are relatively the same. The air injection rate at 100 Mscf/d is, then, used for
further investigation.
Figure 5. Effect of air injection rate on cumulative oil production
a.) b.)
Figure 6.Temperature distribution at different air injection rate a.)100 Mscf/d b.)200 Mscf/d c.)400 Mscf/d
Metsai Chaipornkaew et al. / Procedia Earth and Planetary Science 6 ( 2013 ) 326 – 334
3.3. Effect of Oxygen Concentration in Injected gas
For this study, the oxygen concentration in injected gas varied at 4 different values, 29 (air), 50, 75 and 100%.
The results of this parameter were presented in Figure 7 and 8. As shown in Figure 7, the cumulative oil production
can be enhanced significantly with the increase of oxygen concentrations because higher oxygen content gave
higher amount of oxygen molecules to react with the oil, leading to more energy released from the reaction. This
meant that the reservoir temperature will reach the auto-ignition temperature early. For this model, normal air,
containing 29% of oxygen, is too low to generate the ignition at early time. According to Figure 8, the ignition
occurred near the producer instead of injector causing limited amounts of improved oil. Compared to 50%, 75% and
100% of oxygen, where the ignition took place near the injector, thus resulting in increased improved oil recovery
beyond the combustion front to be produced.
Figure 7. Effect of oxygen concentration in injected air on cumulative
Figure 8.Temperature distribution at various oxygen concentration a.)29% b.)50% c.)75%
332 Metsai Chaipornkaew et al. / Procedia Earth and Planetary Science 6 ( 2013 ) 326 – 334
3.4. Effect of Injected Air Temperature
Temperatures of injected gas were studied at 80, 300 and 500 ºF in order to determine how preheating process
affected combustion underground. The results were presented in Figure 9 and 10. It was obvious that temperature of
injected air had a significant effect on ignition and oil production as shown in Figure 9. In addition, increasing
temperature of the injected air reduces ignition time. Normally, without preheating, increasing the reservoir
temperature to auto-ignition temperature will take time and ignition will occur at some distance beyond the injector.
Figure 10 exhibited the distance where the auto-ignition occurs for 80, 300, 500ºF. For injected fluid at 80ºF, the
ignition took place at middle of the model whereas at higher temperature ignition can start near injection well.
Therefore, preheating of injection air is required to control the initial location of ignition, especially when the
reservoir temperature is low like in this field.
Figure 9. Effect of injected air temperature on cumulative production
Figure 10.Temperature distribution at different injected air temperature a.)80ºF b.)300ºF and c.) 500ºF
Metsai Chaipornkaew et al. / Procedia Earth and Planetary Science 6 ( 2013 ) 326 – 334
3.5. Optimal Operating Conditions
From previous results, adjusting parameters were required to obtain optimal operating conditions.
Because injection rate has minor effect on cumulative production, decreasing 50% of injection rate after ignition
was selected. High injected fluid temperature was required to reduce ignition time. However, it was not necessary to
maintain high temperature at all time. Injected fluid temperature was reduced from 300 ºF to 80 ºF after ignition had
started. Moreover, oxygen concentration was the key of combustion process in that the smaller number of oxygen
molecule reacted, the lower heat will be released.
Figure 11 shows the comparison between base case and test cases for optimized conditions by changing injection
rate, injected air temperature and oxygen concentration. Although the recovery was not as fast as in the base case,
decreasing injection rate from 100 Mscf/d to 50 Mscf/d and injected air temperature from 300 ºF to 80 ºF after
ignition did not change the total oil production. This is because the combustion reaction rate, even in these test
cases, was already at its maximum limit. Higher injection rate and temperature beyond these points would not
improve the results.
Decreasing oxygen concentration from 50% to 29% after ignition, in contrast, resulted in lower cumulative
production. The reason is that heat released from combustion reaction was less, as clearly displayed in Figure 12.
Figure 11. Cumulative production of base & test cases
a.) b.)
Figure 12.Temperature distribution on optimization conditions a.) Maintain oxygen concentration at 50% all over injection
b.) Decrease oxygen concentration to 29% after ignition
334 Metsai Chaipornkaew et al. / Procedia Earth and Planetary Science 6 ( 2013 ) 326 – 334
4. Conclusions
Production of medium-heavy oil in the North of Thailand can be predicted by using preliminary study.
Conventional methods cannot produce oil effectively with this type of oil. In -situ combustion process seems to fit
with medium to heavy crude oils. The process had to deal with the multi-phase fluid flow through porous media
with chemical and physical transition of the crude oil components under reservoir conditions. The simulation with
STARS investigated the effects of parameters such as block sizes, air-injection rates, oxygen concentrations, and
injected air temperature. The 0.5m-block size was selected owing to the optimum running time with reliable
accuracy. From the results, it can be concluded that an injection rate increase from 100 Mscf/d to 400 Mscf/d does
not significantly affect cumulative oil production less than 6% incremental recovery. Increased oxygen
concentration from 29% to 100% caused an increase in 40.67% oil production. Furthermore, the injected fluid
temperature increase from 80˚F to 500˚ F, caused a total oil production increase to 97.14%. In addition, optimal
operating conditions were adjusted to enhance recovery of oil production. The optimum production can still be
obtained as long as the process is at the maximum limit of combustion kinetics.
The authors would like to thank ChonpatinPhaiboonpalayoi for his help in CMG software usage.
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the 1982 SPE/DOE Third Joint Symposium on Enhanced Oil Recovery of the Society of Petroleum Engineers, Tulsa, Oklahoma, April
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... These are described by material balance equations, Darcy's law, relative permeability correlations, capillary pressure equations, and phase equilibrium equations [Bakyani et al., 2018;Abbas et al., 2020;Cheng et al., 2019;Bekbauov et al., 2015]. Literature reports pertaining to EOR flooding simulation with CMG is not very extensive, and only a few studies are useful in explaining the defining thought process [Chaipornkaew et al. 2013;Rai et al., 2015]. In this thesis, the reservoir model and flooding phenomena were modeled with the aid of CMG-STARS, and experimental recovery results were corroborated with the CMOST technique. ...
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Gemini surfactant-based nanoemulsions and foam fluids (stabilized by polymer/nanoparticle assemblies) are characterized by improved stabilization, favorable rheology, and salt/temperature tolerance as compared to conventional displacing agents. Gemini surfactant EOR has favorable applicability in heterogeneous reservoir formations with variable pore-throat regions, wherein conventional tertiary methods are not feasible and can no longer be used from functional points of view. Great strides have been made in the field of bio-based gemini surfactants, tailor-made for different purposes. Therefore, it is pivotal to address the issue of sustainability and detrimental effect on environment, which can be mitigated by the implementation of eco-friendly, natural resource-derived systems with promise for EOR application. The thesis covers topics related to the development and implementation of gemini surfactant systems. Initially, the synthesis and characterization properties were studied. Thereafter, their suitability in EOR operations were predicted with the evaluation of different injection strategies involving aqueous solutions, nanoemulsions and foams. Physicochemical properties were investigated in terms of thermal stability, salt tolerance, interfacial tension, crude oil miscibility, wettability alteration, adsorption and rheology. Experimental oil displacement results were studied by core-flood investigations in the laboratory, and subsequently history-matched with simulator tool to understand rock-fluid interactions and determine the EOR performance of gemini surfactant-based EOR systems. A prospective study pertaining to sunflower oil-derived gemini surfactant was filed for patent, and serves to motivate future researchers to venture into novel, eco-friendly routes to beneficial EOR.
... Although it was not certain from the outset, the hope was that the tabular input would be able to handle all four flow regimes if necessary. Best of our knowledge, few articles have been published using STARS (CMG) software till now (Santos et al. 2011;Chaipornkaew et al. 2013). Several research works based on the modeling of chemical flooding using different simulation techniques have been published since 1970s. ...
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The world's two largest oil deposits are the heavy and extra heavy oil deposits of Venezuela and Canada. These deposits have many similarities and some differences; however, the general similarity in geological disposition and history, in reservoir and fluid parameters, and in other factors, is striking. Extensive technological developments in Canada in the period 1985-2000 have resulted in several new heavy oil exploitation technologies, and new ideas continue to be generated. This innovative thrust has developed in part because of the great exploitation difficulties experienced in Canada and the greater maturity of the sedimentary basin: to maintain oil production, it was necessary to move toward heavy oil and oil sand development sooner than in Venezuela. The technologies of SAGD, CHOPS and PPT have been the major directions of technical activity in Canada, whereas in Venezuela, more favorable reservoir conditions allowed the use of multilateral horizontal wells. The article reviews technical developments and deposit properties in the two countries, and points to a vast potential in the application of technologies developed and perfected in Canada to the vast resources in Venezuela. Not only will this be of value in specific projects and areas, it will also benefit and stabilize world oil supplies in the long term. Introduction There are vast heavy oil deposits (defined herein to be all the liquid petroleum resource less than 20 °API gravity) in Venezuela and Canada. In both cases, these resources are found largely in unconsolidated sandstones with roughly similar geomechanical and petrophysical properties. This article will attempt a comparison of the Faja del Orinoco deposits in Venezuela (Figure 1) with the Heavy Oil Belt and Oil Sands deposits in Alberta and Saskatchewan (Figure 2). The term "unconsolidated" is used to describe the high porosity sandstone reservoirs in both Canada and Venezuela. It is analogous to the term "cohesionless" in the soils or rock mechanics sense: it is meant to convey the fact that these sandstones have no significant grain-tograin cementation, and that the tensile strength is close to zero. This turns out to be an important attribute in technology assessments. The magnitude of the resources in the two countries is vast, probably on the order of 3.5-4 trillion barrels of oil in place (bbl OOIP), but its scale deserves a few comments. Conservation authorities, through the use of geophysical logs and cores to analyze and examine the oil-bearing strata, determine a "total resource in place". This depends substantially upon a choice of "lower cutoff" criteria, below which an individual stratum is not included in the resource base. For example, any bed less than 1.0 m thick may be excluded from resource calculations, no matter where it is found. If a thin bed (e.g. 1.5 m) is separated by more than several m from superjacent or subjacent oil saturated beds, i.e. if it is "iolated", it may be excluded from the resource base, no matter what value of oil saturation (S o) it possesses. Furthermore, any bed with a low oil saturation, such as S o < 0.4, may be excluded.
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The in situ combustion project operated by Getty Oil Company in the Bellevue Field, Bessier Parish, Louisiana, has expanded from a single pilot pattern in 1963 to a full-scale operation with more than one hundred patterns in 1981. Originally discovered in 1921, the field produced for about ten years under primary production methods. The field remained relatively dormant until Getty Oil Company conducted a successful in situ combustion pilot which commenced in 1963. The project is now pilot which commenced in 1963. The project is now producing about 2900 barrels daily of 19.50 API gravity producing about 2900 barrels daily of 19.50 API gravity crude from 350 producing wells. Pattern sizes and configurations have varied during the eighteen year project. Wet and dry combustion methods have been used in the field and a combination of the two methods is used today depending on the stage of burn the pattern is experiencing. Several water-air injection ratios have been tried with varying degrees of success. In this paper, Getty's Bellevue project is traced from its inception to the present. Response to various methods used in the field as well as operational problems are discussed. Ultimate production forecasts problems are discussed. Ultimate production forecasts are also presented for the field. HISTORY Discovered in 1921, the Bellevue Field produced about five percent of its oil in place under primary production. The field is located about eighteen production. The field is located about eighteen miles northeast of Shreveport in Bessier Parish, Louisiana. Initially the field experienced rapid development with more than one hundred shallow wells being drilled. Peak primary production occurred during 1923. The high viscosity of the crude and low reservoir pressure contributed to the rapid decline of the production. By 1931, diminished oil production together with increased water rates resulted in a general abandonment of the field. In the years that followed air and water injection, steam stimulation, solvents, and bottom hole heaters were used in an attempt to increase oil recovery. None of these methods increased production enough to be adopted by the company as a long term recovery method. In 1961, Getty Oil Company (then Tidewater Oil Company) initiated a coring program to evaluate the feasibility of a thermal recovery project. The results of this program were encouraging. Extensive air injection tests were conducted in early 1963 and an in situ combustion pilot was begun in September, 1963. After operating for 21 months the pilot pattern was converted from an inverted five-spot to pattern was converted from an inverted five-spot to an inverted nine-spot pattern. The eight wells in the pilot produced an average of 115 barrels of oil per day during the following year. Eventually the per day during the following year. Eventually the pattern was extended with the drilling of four pattern was extended with the drilling of four additional wells. By the end of 1966, the pilot pattern was producing 145 barrels of oil daily. pattern was producing 145 barrels of oil daily. Cumulative oil production from the pilot at the end of July, 1969, was 184,000 barrels and at the end of 1981 was 372,000 barrels. The success of the pilot warranted expansion in the years which followed its development. Four additional patterns were added in 1968 and growth of the project continued with large expansions in 1972, 1977, 1979, and 1980. Availability of compressed air was a major factor in the timing of these expansions. At least two more major expansions are planned by Getty in 1982 and 1983. planned by Getty in 1982 and 1983. P. 481
Pru Krathiam (PKM) is a small onshore, unconsolidated sandstone reservoir in Thailand containing medium heavy oil with viscosity of approximately 50 cp. Fluvial channels supplied sediments to form mouth bar sands in lake with sand thickness of 1 to 3 meters. In its 25 years of natural depletion, the field has achieved merely 1.7% recovery factor. The difficulty in production has been attributed to aquifer support combined with unfavorable mobility, and sand production. Secondary and tertiary recovery methods have been investigated, with the assumption that sufficient sand-control could be implemented. Basic EOR screening reveals that thermal and chemical methods could be appropriate for this challenging field, in addition to infill drilling. Further investigation by means of a history-matched full-field reservoir simulation model indicates that chemical flooding has the advantage over cyclic steam stimulation (CSS) in this type of reservoir and reservoir fluids. Polymer flooding using high molecular weight polyacrylamide gives significant recovery improvement. Its implementation will give an extra benefit to the field which has high initial water cut as polymer solution contacts the unswept regions of the reservoir. The oil recovery appears relatively insensitive to rock-polymer properties, i.e. adsorption, inaccessible pore volume, and residual resistant factor. Further study shows that adding alkaline and surfactant can increase oil recovery beyond polymer flooding. Generic properties of oil/water/ASP system e.g. interfacial tension and surfactant adsorption were used. ASP flooding performance seems sensitive to these properties, so extra care must be taken when designing the process. The fundamental constraint of polymer flooding and ASP flooding operation is the cost of implementation. CSS, on the other hand, still faces up severe problems with reservoir heterogeneities and high initial water saturation. Reservoir heterogeneities cause steam to disperse unevenly, leading to poor heat distribution. High water saturation results in much of the heat being absorbed by water. Mobility improvement by viscosity reduction is small for medium heavy oil and is slightly overcome by the effect of steam condensation. Introduction Pru Krathiam (PKM) is one of the fault-bounded dip closures located on the eastern flank of Phitsanulok Basin. The discovery well, PKM-A01, encountered viscous oil with 17–19 oAPI in Lan Krabu formation. Lan Krabu formation was deposited in the fluvio-lacustrine environment: fluvial sediments were transported from the east, and were deposited as mouth bar sands in the lake to the west. Evidences from grain size distribution and fossil indication match the notable characteristics of fluvio-lacustrine sediments, which are low energy aqueous deposition and the absence of marine fauna. In some areas, features such as levee, back swamp, coal and rootlets can be found. These are indications of shallow lacustrine deposits with frequent variations in the water level. Cyclicity of the deposition results in alternating lamina of clay and organic matter. Sand body size is in the range of 700 to 1100 meters in width and length, and 1 to 3 meters in thickness. The net-to-gross is in the range of 15 to 20%.
This paper describes a numerical model forsimulating wet or dry, forward or reverse combustionin one, two, or three dimensions. The formulation isconsiderably more general than any reported to date.The model allows any number and identities ofcomponents. Any component may be distributed inany or all of the four phases (water, oil, gas, andsolid or coke.The formulation allows any number of chemicalreactions. Any reaction may have any number ofreactants, products, and stoichiometry, identifiedthrough input data. The energy balance accounts forheat loss and conduction, conversion, and radiationwithin the reservoir.The model uses no assumptions regarding degreeof oxygen consumption. The oxygen concentration iscalculated throughout the reservoir in accordancewith the calculated fluid flow pattern and reactionkinetics. The model, therefore, simulates the effectsof oxygen bypassing caused by kinetic-limitedcombustion or conformance factors.We believe the implicit model formulation resultsin maximum efficiency (lowest computing cost), andrequired computing times are reported in the paper.The paper includes comparisons of model resultswith reported laboratory adiabatic-tube test results.In addition, the paper includes example field-scalecases, with a sensitivity study showing effects on oilrecovery of uncertainties in rock/fluid properties. Introduction Recent papers by Ali, Crookston et al., andYoungren provide a comprehensive review of earlierwork in numerical modeling of the in-situcombustion process.The trend in this modeling has been toward morerigorous treatment of the fluid flow and interphasemass transfer; inclusion of more components, morecomprehensive reaction kinetics, and stoichiometry;and more implicit treatment of the finite differencemodel equations.The purpose of this work was to extend thegenerality of previous models while preserving orreducing the associated computing-time requirement.The most comprehensive or sophisticated combustionmodels described to date appear to be thoseof Crookston et al. and Youngren. Therefore, wecompare our model formulation and results here withthose models.A common objective of different investigators'efforts in modeling in-situ combustion is developmentof more efficient formulations and methods ofsolution. This is especially important in thecombustion case because of the large number ofcomponents and equations involved. For a given numberof components and reactions, computing time pergrid block per time step will increase rapidly as theformulation is rendered more implicit. However, increasing implicitness tends to allow larger timesteps, which in turn reduces overall computingexpense. To pursue the above objective, then, authorsshould present as completely as possible the details oftheir formulations and the associatedcomputing-time requirements.The thermal model described here simulateswet or dry, forward or reverse combustion in one, two, or three dimensions. The formulation allowsany number and identities of components and anynumber of chemical reactions, with reactants, products, and stoichiometry specified through input products, and stoichiometry specified through input data. SPEJ P. 533
Screening criteria are useful for cursory examination of many candidate reservoirs before expensive reservoir descriptions and economic evaluations are done. We have used our CO2 screening criteria to estimate the total quantity of CO2 that might be needed for the oil reservoirs of the world. If only depth and oil gravity are considered, it appears that about 80% of the world's reservoirs could qualify for some type of CO2 injection. Because the decisions on future EOR projects are based more on economics than on screening criteria, future oil prices are important. Therefore, we examined the impact of oil prices on EOR activities by comparing the actual EOR oil production to that predicted by earlier NatI. Petroleum Council (NPC) reports. Although the lower prices since 1986 have reduced the number of EOR projects, the actual incremental production has been very close to that predicted for U.S. $20/bbl in the 1984 NPC report. Incremental oil production from CO2 flooding continues to increase, and now actually exceeds the predictions made for U.S. $20 oil in the NPC report, even though oil prices have been at approximately that level for some time. Utilization of Screening Guides With the reservoir management practices of today, engineers consider the various IOR/EOR options much earlier in the productive life of a field. For many fields, the decision is not whether, but when, to inject something. Obviously, economics always play the major role in "go/no-go" decisions for expensive injection projects, but a cursory examination with the technical criteria (Tables 1 through 7) is helpful to rule out the less-likely candidates. The criteria are also useful for surveys of a large number of fields to determine whether specific gases or liquids could be used for oil recovery if an injectant was available at a low cost. This application of the CO2 screening criteria is described in the next section. Estimation of the Worldwide Quantity of CO2 That Could Be Used for Oil Recovery The miscible and immiscible screening criteria for CO2 flooding in Table 3 of this paper and in Table 3 of Ref. 1 were used to make a rough estimate of the total quantity of CO2 that would be needed to recover oil from qualified oil reservoirs throughout the world. The estimate was made for the IEA Greenhouse Gas R&D Program as part of their ongoing search for ways to store or dispose of very large amounts of CO2 in case that becomes necessary to avert global warming. The potential for either miscible or immiscible CO2 flooding for almost 1,000 oil fields was estimated by use of depth and oil-gravity data published in a recent survey.2 The percent of the fields in each country that met the criteria in Table 3 for either miscible or immiscible CO2 flooding was determined and combined with that country's oil reserves to estimate the incremental oil recovery and CO2 requirements. Assuming that one-half of the potential new miscible projects would be carried out as more-efficient enhanced secondary operations, an average recovery factor of 22% original oil in place (OOIP) was used, and 10% recovery was assumed for the immiscible projects. A CO2 utilization factor of 6 Mcf/incremental bbl was assumed for all estimates. This estimated oil recovery for each country was then totaled by region, and all the regions were totaled in Table 8 to provide the world totals.3 The basis for the assumed incremental oil recovery percentage and CO2 utilization factors and other details are given in Ref. 3. Economics was not a part of this initial hypothetical estimate. Although pure CO2 can be obtained from power-plant flue gases (which contain only 9 to 12% CO2), the costs of separation and compression are much higher than the cost of CO2 in the Permian Basin of the U.S.3–5 For this study, we assumed that pure, supercritical CO2 was available (presumably by pipeline from power plants) for each of the fields and/or regions of the world. Table 8 shows that about 67 billion tons of CO2 would be required to produce 206 billion bbl of additional oil. The country-by-country results and other details (including separate sections on the costs of CO2 flooding) are given in Ref. 3. Although not much better than an educated guess with many qualifying numbers, our estimate agrees well with other estimates of the quantity of CO2 that could be stored (or disposed of) in oil reservoirs.3 Although this is a very large amount of CO2, when the CO2 demand is spread over the several decades that would be required for the hypothetical CO2 flooding projects, it would reduce worldwide power-plant CO2 emissions into the atmosphere by only a few percent per year. Therefore, more open-ended CO2 disposal methods (such as the more-costly deep-ocean disposal) will probably be needed if the complex general circulation models of the atmosphere ever prove conclusively that global warming from excess CO2 is under way.6,7 However, from the viewpoint of overall net cost, one of the most efficient CO2 disposal/storage systems would be the combined injection of CO2 into oil reservoirs and into any aquifers in the same or nearby fields.3,8 By including aquifers, this potential for underground CO2 storage would be increased significantly, and the quantity sequestered could have a significant impact on reducing the atmospheric CO2 emissions from the world's power plants. Impact of Oil Prices on EOR Major new EOR projects will be started only if they appear profitable. This depends on the perception of future oil price. Therefore, the relationship between future oil prices and EOR was a major thrust of the two NPC reports.9,10 These extensive studies used as much laboratory and field information as possible to predict the EOR production in the future for different ranges of oil prices. Now, it is possible to compare the NPC predictions with actual oil production to date. These comparisons were made recently to see how oil prices might affect oil recovery from future CO2 projects.3 We have extended these graphical comparisons and reproduced them here as Figs. 1 through 3. In general, the figures confirm that EOR production increases when prices increase and EOR production declines when prices fall, but not to the extent predicted. There is a time lag before the effect is noted. Figs. 1 and 2 show that total EOR production did increase in the early 1980's when oil prices were high. This was in response to an increase in the number of projects during this period when prices of up to U.S. $50/bbl or more were predicted. Although the rate of increase slowed in 1986 when oil prices dropped precipitously, EOR production did not decline until 1994, after several years of low oil prices (i.e., less than U.S. $20/bbl).11
  • W C Lyons
  • G Plisga
  • Standard Handbook
Lyons, W C and Plisga, G, Standard Handbook of Petroleum & Natural Gas Engineering Vol. 2, 2nd ed., Gulf Publishing Co., Houston, Texas (2005).
  • Farouq Ali
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Farouq Ali, S M, Jones, J A and Meldau, R F, Practical Heavy Oil Recovery (1997).
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Taber, J.J., Martin, F.D., and Seright, R.S.: " EOR Screening Criteria Revisited: Part 2 – Applications and Impact of Oil Prices, " SPERE (August 1997).