Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Chemical Methods For Heavy Oil Recovery
Thomas, S. (PERL Canada Ltd.) | Scoular, J.R. (Saskatchewan Research Council) | Verkoczy, B. (Saskatchewan Research Council) | Ali, S.M. Farouq (Saskatchewan Research Council)
Abstract Many mobile heavy oil reservoirs in Saskatchewan and Alberta are unsuitable for the application of thermal recovery methods, such as steam injection, for a number of reasons including formation thicknesses less than 10 m. Oil recovery from such reservoirs can be accomplished by the use of non-thermal methods, among which chemical flooding has considerable importance. This paper discusses recent laboratory results using chemical flooding techniques. At the same time, limitations of such methods, limited field experience in heavy oil formations, and possible improvements are also considered. Among the chemical flooding methods, alkaline and surfactant flooding techniques are more important, partly because the chemicals involved are less expensive, and also much has been learnt from past experience in laboratory and field. The laboratory studies discussed consisted of surfactant floods and huff n'puff of two Lloydminster heavy oils. The recoveries in the floods were as high as 33%. The other recovery method discussed involved cyclic stimulation using these chemicals. Oil recoveries as high as 12% were achieved. Though low, such an approach can be cost-effective in special circumstances. Introduction Much of the heavy oil in Saskatchewan and Alberta is mobile under reservoir conditions to the extent that primary production and waterflooding is economically feasible, although the recovery factors are low, 5 to 10% in most cases. Furthermore, the formation thickness is small (85% of the oil in Saskatchewan occurs in formations less than 5 m thick), so that larger spacings are needed, which makes the application of thermal methods, notably steamflooding, doubly unattractive. Non-thermal recovery methods, such as chemical recovery processes and immiscible carbon dioxide WAG (Water-Alternating-Gas) process can be economically viable in such reservoirs, even though the recovery factor is low. This paper discusses primarily the more promising non-thermal chemical flooding methods, selected laboratory and field results, and their limitations. Results of a few experiments involving chemicals with hot water are also added. PRINCIPLES OF OIL RECOVERY The two important concepts involved in oil recovery are Mobility Ratio, M, and the Capillary Number, N,. Mobility ratio, M, is usually defined as the mobility ฮปing (=k/ ยต, where k is effective permeability and ยต is viscosity) of the displacing fluid divided by the mobility ฮปedof the displaced fluid (assumed to be oil in this discussion). If M>l, the displacing fluid will flow past much of the displaced fluid, displacing it inefficiently. Thus the mobility ratio influences "displacement efficiency", i.e. the (microscopic) efficiency of oil displacement within the pores. For M> > 1, the displacing fluid will channel past oil ganglia. This is often called "viscous fmgering". For maximum displacement efficiency, M should be โค1, usually denoted as "favourable" mobility ratio. If M>1 (unfavourable), then, in the absence of viscous fingering, it merely means that more fluid will have to be injected to attain a given residual oil saturation in the pores.
- North America > Canada > Saskatchewan (0.68)
- North America > Canada > Alberta (0.45)
A Laboratory Study On Near-Miscible CO, Injection In Steelman Reservoir
Dong, M. (Saskatchewan Research Council) | Huang, S.S. (Saskatchewan Research Council) | Srivastava, R. (Saskatchewan Research Council)
Abstract Miscible flooding is considered unsuitable for some reservoirs in southeast Saskatchewan because of high CO, minimum miscibility pressure or operating pressure constraints. Therefore, the effectiveness of near-miscible CO2 injection was assessedfor Steelmnn reservoir in a laboratory study. The minimum miscibility pressures (MMP) were estimatedfor Steelman reservoir fluids with pure CO2and CO-- hydrocarbon gas mixtures, the partially flashed reservoir fluids and the dead oils with pure CO2 The results of MMP studies demonstrated i) addition of ethane orpropane can reduce CO, MMP greatly; and ii) achieving a miscible CO2 flood in the Steelman reservoir could be possible at a lower operating pressure than the measured CO, MMP, by partially depleting the reservoir. Asphaltene flocculution tests showed that, after the onset point, flocculation increased linearly with gas concentration, but that the presence of brine had a negligible effect. Three tertiary CO, coreflood tests were conducted with Steelman reservoir fluids at the reservoir temperature. These results showed that the microscopic displacement efficiency during the CO, injection stage improved with the operating pressure in the near-miscible region, but no dramatic change in oil recovery was observed with a change in operating pressure. Introduction The Steelman pool, located about 200 km southeast Regina, Saskatchewan, was discovered in 1954. Covering approximately 370 km, the field was estimated to contain over 134 million m of light oil in the Frobisher and Midale beds located at about 1,400 meters. Most of the reservoirs in the Midale beds, which contain about 83% of the reserves of the pool, have been under waterflood for over 20 years and have nearly reached the estimated production limit by primary and waterflood.' For achieving additional oil recovery and consequent financial benefits, the development of tertiary enhanced oil recovery (EOR) techniques, such as CO, flooding, is essential. Miscible CO, flood is a proven enhanced oil recovery technique.' Over the last decade, CO injection has become the leading EOR process for light oil. In Canada, the industry interest in CO, flooding is evidenced by Shell Canada's CO, pilot tests, a Miscible CO, flood at Joffre field in Alberta, and the implementation of PanCanadian's Weybum CO, injection project.' Additional field applications are expected to be initiated in southeast Saskatchewan and other regions when CO, sources are available. Miscible CO2 displacement offers the greatest oil recovery potential but can only be achieved at a pressure greater than a certain minimum referred to as minimum miscibility pressure (MMP). The effect of solution gas on the development of miscibility is not well understood, as reflected by the lack of a consensus in the literature. Rathmell et al. found that CO2 MMP is related to the volatile and intermediate fractions ofthe oil. Yelling and Metcalfe found from their experimental study that, for a saturated reservoir oil, areal variation in gas-oil ratio (GOR) will result in an areal variation in the CO2 MMP.
- North America > Canada > Alberta > Red Deer County (0.25)
- North America > Canada > Alberta > Lacombe County (0.25)
- North America > Canada > Saskatchewan > Regina (0.24)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Joffre Field > Alloway No. 12-21 Well (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Steelman Field > Midale Formation (0.98)
- North America > Canada > Nunavut > Arctic Platform > Frobisher Basin (0.89)
Gas Pressure Cycling For Thin Heavy Oil Reservoirs
Hutchence, K. (Saskatchewan Research Council) | Huang, S.S. (Saskatchewan Research Council)
Abstract A new enhanced oil recovery scheme, pressure cycling, is proposed. Numerical simulations indicate that it may be possible to recover a substantial additional amount of oil after primary and secondary production by this method. The pressure cycling scheme involves the injection of produced gas and water into a reservoir in order to re-energize it and to resaturate the oil. Injection is done through existing vertical wells; however, it appears necessary to drill infill horizontal production wells to attain good rates of production, particularly in quite thin reservoirs (5 m or less). The optimal amount of gas to inject is believed to be the amount required to re-saturate the oil when the reservoir is repressured by water to approximately original reservoir pressure. Introduction A substantial portion of Saskatchewan's petroleum resources is in the form of heavy oils, much of which occurs in rather thin reservoirs (4 to 6 m). Once primary production, and waterflooding where applicable, have been done in such reservoirs there is a major problem in finding an enhanced oil recovery (EOR) scheme that is practical. The thinness of the reservoirs effectively rules out thermal methods such as steam drive and SAGD because of high heat losses. It is conceivable that combustion techniques might be applied; however, the few field trials done to date have failed to ignite interest. The nonviability of thermal EOR methods for thin reservoirs compels the consideration of non-thermal methods. Preferable and practical non-thermal methods for thin heavy oil reservoirs will almost certainly be associated with low cost. Some of the lowest cost materials that could be injected in quantity would be water and produced gas. It is therefore natural to carefully consider all techniques that use these materials for EOR of heavy oil. THE PRESSURE CYCLING PROCESS The pressure cycling process had its origins in an examination by SRC researchers of a variation of the water alternating gas (WAG) process. A schematic of the arrangement of the wells is given in Figure 1. The area used for the new WAG study used four vertical wells and a segment of horizontal well between them For reasons of continuity with previous work the distance between vertical wells surrounding the horizontal well is 440 m rather than the more standard 400 m The simulation was based on the Senlac field, in that uniform average values from this reservoir were used in the simulation (4.8 m reservoir thickness, 1300 cp dead oil, 5600 kPa original pressure, no bottomwater). The WAG variation considered was one using a horizontal production well. This variation of WAG did not give attractive results. It was observed, however, that the horizontal production well, when viewed as an infill well, was considerably more productive after the reservoir had been repressured by water injection for the WAG scheme. The increase in production was not simply due to increased pressure. This was established by observing production after having pressured the reservoir up to a series of progressively higher pressures.
The Impact Of Changing Canadian Pipeline Bs&W Specifications: A Survey
Renouf, G. (Saskatchewan Research Council) | Ranganathan, R. (Saskatchewan Research Council) | Scoular, A.J. (Saskatchewan Research Council) | Soveran, D. (Saskatchewan Research Council)
Abstract The possibility of relaxing basic sediment and water (BS&W) limits in pipelines has been gaining the interest of some Canadian producers. Some of this interest was engendered by comparing pipeline regulations in Canada to those in the United States. Currently in Canada. crude oil to be pipelined must contain Less than 0.5% by volume of BS&W In the United States, however, BS&W Limits in crude oil vary with each pipeline company, usually from 0.5% to 3%. American companies were surveyed as to whether they experience any more pipelining or processing difficulties than do their Canadian counterparts. Canadian producers. pipeliners, and upgraders/refiners were surveyed about their separate targets for and concerns about water and solids in crude oil. In all. 55 representatives from 45 sites participated in the survey. This paper is a brief non-confidential excerpt from the contract report done for Husky Oil. Petro-Canada, Wascana Energy and Saskatchewan Research Council. BACKGROUND Crude oil must meet a number of specifications for pipeline transportation. Pipeline companies and refineries frequently set maximum limits on basic sediment and water (BS&W) and salt content. While maximum limits on solids and salt are necessary to prevent downstream problems for pipelines and refineries. stringent limits on water may not be so crucial. In Canada, crude oil to be transported must contain less than 0.5% by volume of water and solids. In the United Slates. BS&W limits in crude oil vary with each pipeline company. usually from 0.5% to 3%. The question of whether these American companies experience any more pipelining or processing difficulties than do their Canadian counterparts was a fundamental part of the survey. The second aim of the sludy was to assess the perceived advantages and disadvantages to the Canadian stakeholders. Producers, pipeliners. upgraders. and refiners were asked for their views on separately regulated. higher water limits for pipeline crude. SURVEY RESULTS The survey contacts were largely chosen on a random basis. although an effort was made to reach American refiners processing higher amounts of water. Most contacts were interviewed by telephone. Approximately 80% of those called were willing to participate. Producers Twelve producers from Western Canada were surveyed by telephone on the quality ofcrude oil they produce, and practices that impact downstream users. The producers were fairly evenly split between heavy oil producers in the Lloydminster area, and producers ofmedium crude in more southerly regions. Producers were, for the most part, well able to treat oil to the 0.5% BS&W standard. Producers reported an average BS&W of 0.35%, with solids ranging from a trace to 60% of the BS&W. Most producers were in favour of relaxing the water limit of pipeline specifications. Even producers who had little dewatering difficulty, said that they could save substantial amounts in demulsifier and fuel gas costs. This is partly due to the fact that the "finishing" aspect of treating exhausts a disproportionally large amount of demulsifier.
Oxidation Of Heavy Oils And Their Sara Fractions - Its Role In Modelling In-Situ Combustion
Verkoczy, B. (Saskatchewan Research Council) | Freitag, N.P. (Saskatchewan Research Council)
Abstract The relevance of various oxidation reactions to the modelling of in-situ combustion in heavy oils was studied in three sets of experiments. The first set of tests involved temperature-programmed thermal gravimetric scans of three heavy oils and their SARA fractions. A comparison between the scans made in the presence and in the absence of air revealed the temperature regions in which each of the SARA fractions underwent oxygen uptake and then combustion. In the second set of experiments the effect of various levels of oxygen exposure on the subsequent high-temperature coke formation was investigated. The results clearly showed that low-temperature oxidation had significant and sometimes dramatic effects on the amount of cake formation. Finally, a series of autoclave tests allowed the products of low-temperature oxidation to be identified within the SARA based reaction scheme. These tests indicated also that asphaltenes apparently underwent low-temperature oxidation more rapidly than the other fractions-a characteristic that could not be detected by thermal gravimetric analysis. The observed reaction characteristics provided guidelines for visualizing a SARA-based reaction model that would be realistic for the prediction and enhanced control of the in-situ combustion process. Introduction After many years of enhanced oil recovery (EDR) experience. the use of in-situ combustion to produce heavy oils still falls far short of its apparent potential. The process is highly efficient in delivering heat to a reservoir. it has a strong tendency to display gravity-stabilized gas override. and it has an inherently strong gas drive. These features make the process particularly attractive in pressure-depleted reservoirs that are either very thick or very thin. The application of in-situ combustion has been restricted in part by difficulties in predicting its performance in new reservoirs or under new operating conditions. A major root of this problem is the lack of reliable kinetic parameters for the oxidation reactions ranging from low temperature oxidation (LTD) through the auto ignition temperature (AIT) region. This is especially true for liquid or solid hydrocarbons. for which we know of no systematic LTD and AIT study. The use of SARA (saturates, aromatics, resins, asphaltenes) fractions as a basis for a chemical reaction model offers a practical option for filling this void in the chemical kinetics. Earlier studies provided some evidence that each SARA fraction oxidizes at a different rate, and that perhaps characteristically different reactions can be distinguished through the study of the separate fractions. The coke/residue formation by individual SARA fractions was shown to depend strongly on the type of mineral surface present, and was reservoir specific. However, the main contribution to the amount of coke/residue available for combustion came from the preceding oxidation reactions. The characteristics of the various oxidation reactions in heavy oils were studied through three very different sets of tests. The first set involved normal then no gravimetric analysis, whereby the oxidation behaviour of each fraction was inferred over the entire temperature range of interest. In the second set of experiments, the measurements focused on the amount of coke/residue remaining after a SARA fraction had been heated under oxygen-poor conditions.
Laboratory Investigation Of Weyburn Co2 Miscible Flooding
Srivastava, R.K. (Saskatchewan Research Council) | Huang, S.S. (Saskatchewan Research Council)
Abstract Weyburn reservoir, Located in southeast Saskatchewan and operated by PanCanadian PetroLeum Ltd., has reached its economic Limit of production by waterflooding. The reservoir is a target for tertiary CO2 miscible flooding to enhance oil recovery and extend its production Life. A comprehensive study has been conducted by the Saskatchewan Research Council and PanCanadian to assess the suitability of the process for Weyburn. This paper presents a technical evaluation of CO2 near miscibleinjection for Weyburn reservoir. This is based on laboratory studies conducted with three Weyburn oils collected from different regions of the reservoir. These studies included:measurement of minimum miscibility pressure for the reconstituted reservoir fluids for pure and impure CO2, determination of PVT properties for reservoir fluid-CO2 mixtures. and assessment of recovery behaviour from uniquely designed Laboratory coreflood tests representing the permeability contrast of the reservoir. The studies indicated that the CO2 minimum miscibility pressure for the Weyburn reservoir oils varied from about 11.5 to N.5 MPa. indicating suitability for CO2 miscible flooding. PVJ data generated for the three Weyburn reservoirfluid-CO2 mixtures showed that viscosity reduction and oil swelling by CO2 also contributed to oil recovery. A slight manipulation of he measured PVT properties of the mixtures made it possible to obtain single property curves for the three Weyburn oils. This feature can be used to estimate the PVT behaviour for any Weyburn oil from the reservoir. Coreflood studies showed that CO2 injected into the Vuggy zone could rise to the upper Marly zone and heLp enhance oil recovery. A separate simulation and modelling study conducted by PanCanadian Petroleum Ltd. satisfactorily matched the experimental PVT propenies. MMP values and recovery mechanism suggested by the coreflood behaviour. Introduction The total oil reserves of Saskatchewan are estimated at over 3 billion m of initial oil-in-place (lOIP). The light and medium oil (LMO) reserves contribute approximately 1.6 billion m IOIP. Over 10% of the LMO reserves, or 178 million m IOIP, are held in Weyburn reservoir. The Weyburn field is located approximately 130 km southeast of Regina in Saskatchewan and covers over 180 km of production area. The field was discovered in 1955 and PanCanadian Petroleum (PCP) Ltd. is the major operator. It has over 627 producing wells and 162 water injection wells on approximately 24 ha spacing. . The oil production from the Weyburn field comes from Midale beds of the Mississippian Charles Formation in the Williston Basin at a depth of 1310 to 1500 m. The field was produced by primary depletion for about 9 years until 1964. Waterflood was started thereafter using a nine-spot pattern. In 1985, to optimize the waterflood performance, both horizontal and vertical infill drilling programs were initiated. The combined oil recovery by primary and secondary production was approximately 28% IOIP by 1994. Waterflooding has almost reached its economic limit for the Weyburn reservoir. The ultimate conventional recovery is expected to be 31% IOIP, leaving a large target for tertiary recovery techniques. A similar situation exists for the majority of Saskatchewan's LMO reservoir.
- North America > Canada > Saskatchewan > Williston Basin > Charles Formation (0.99)
- North America > Canada > Manitoba > Williston Basin (0.99)
- North America > Canada > Alberta > Williston Basin (0.99)
- (4 more...)
Heavy Oil Production By In-Situ Combustion - Distinguishing The Effects Of The Steam And Fire Fronts
Freitag, N.P. (Saskatchewan Research Council) | Exelby, D.R. (Saskatchewan Research Council)
Abstract In heavy oil production by in-situ combustion, information on the relative importance a/the combustion and steamfronts is very useful in the development of good production strategies. To obtain this information/or two reservoirs, one containing heavy oil and the other a bitumen, a novel series of combustion lube tests was conducted. Contrary to conventional belief, the results showed that, before steam breakthrough, the produced oil properties were influenced much more by steam distillation than by cracking reactions. While the combustion front mobilized substantial amounts of oil, almost all a/it remained behind the steam front. This oil displayed huge differences in properties and composition compared with the original oil. Overall, the results helped to provide some guidelines for developing improved strategies for fireflood operation, and emphasize some requirements for the prediction of fiireflood behaviour. Introduction As a thermal method of improved oil recovery, in-situ combustion has the advantage of delivering heat to a formation very efficiently. Consequently, the prospect of using in-situ combustion to produce heavy oils has continually attracted interest, particularly for thin formations where heat losses to non-productive horizons arc large. The results of field trials in such reservoirs have varied widely, suggesting that the method may be strongly affected by the approaches used to apply it. For the development of efficient strategies for in-situ combustion, it is important for engineers to understand its many mechanisms and their impact on oil recovery. Islam et al have demonstrated the importance of the gas flooding effect on oil recoveries during in-situ combustion. Other phenomena such as the combustion and steam fronts, must also affect oil production. During dry combustion, the steam zone may be small, particularly in thin reservoirs. In this case, the combustion and steam fronts act almost as a unit. During wet combustion, however, when water is injected behind the combustion front to scavenge heat and deliver it in the form of steam, to the oil-bearing zone, the steam front can advance well ahead of the combustion front. In this case, several important questions arise. Does the steam front dominate the oil displacement process, leaving the combustion front to function only as the heat source that sustains the steam front, or does the combustion front also serve to displace oil? To what extent does each front affect the properties of the displaced oil? In an effort to, answer these questions, a series of four combustion tube tests was carried out. These tests were designed to show the effects of each front in two reservoirs, one representative of a heavy oil, and one of a bitumen. Equipment The experiments were conducted in a heavy-walled Incolloy 800 combustion tube with an inside diameter of 5.37 cm, a total inside length of 162.3 cm, and a wall thickness of 0.49 cm. No pressure jacket was employed. The maximum working pressure was 4.2 MPa (610 psig). Pack temperatures at the centreline were measured with 25 thermocouples inserted through fittings welded in a helical pattern on the tube wall.
Quantification of Asphaltene Flocculation During Miscible CO2 Flooding in the Weyburn Reservoir
Srivaslava, A.K. (Saskatchewan Research Council) | Huang, S.S. (Saskatchewan Research Council) | Dye, S.B. (Saskatchewan Research Council) | Mourits, F.M. (CANMET/Energy Research Laboratories)
Abstract In a CO2 miscible displacement process, asphaltenes from the oil can flocculate in the presence of CO2 and can cause numerous production problems with a detrimental effect on oil recovery. A five-year multiclient research project was initiated in 1988 to evaluate the suitability of CO2 as an enhanced oil recovery (EOR) agent for a southeast Saskatchewan reservoir, Weyburn. The initial asphaltene content of the oils collected from the Weyburn pool was about 5% and suggested the possibility of formation plugging and wettability alteration during CO2 injection. A laboratory study was undertaken to assess the extent of asphaltene flocculation during a CO2 miscible flood In the Weyburn field. A prototype high pressure PVI cell was used to quantify the asphaltene flocculation. A photometric technique was developed to determine the asphaltene content of the flashed CO2 -saturated test oils. The effect on the asphaltene flocculation of operating pressure, CO2-oil contact time, CO2 concentration, gas contaminants such as N2 and CH4 in CO2 and the presence of formation brine was investigated for three different oil samples (approximately 29 ยฐ APl) collected from the pool. Results of the study indicated that the onset of asphaltene flocculation occurred at about 42โ46 mol% CO2 concentration. There was a linear increase in asphaltene flocculation with CO2 concentration after the onset. The asphaltene flocculation pattern seemed to be relatively insensitive to the operating pressure in the pressure range studied. The normalized asphaltene flocculation data showed a negligible effect of brine and contaminants in CO2 tested. For the experiments conducted in the single-phase region, the effect of CO2-oil contact time on asphaltene flocculation during the 4โ19 day period was negligibly small. However, the mixing time required to achieve equilibrium in the two-phase region was significantly high. Introduction The majority of the Saskatchewan light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology (primary and secondary recovery methods). Miscible flooding with carbon dioxide is shown to be a promising enhanced oil recovery (EOR) technique for southeast Saskatchewan reservoirs. A study undertaken by Saskatchewan Energy and Mines has shown that the successful development of the miscible displacement process using CO2 and hydrocarbon gases can lead to a significant increase in Saskatchewan LMO reserves and substantially extend the production life of these pools. Crude oil normally consists of a conglomeration of waxes, resins, asphaltenes, and other semisolid materials. Because of their different physical and chemical characteristics, and when subjected to slight changes in equilibrium conditions, paraffins and asphaltenes often precipitate. One of the problems confronting researchers and field operators is asphaltene deposition during a CO2 miscible flood. This concern with asphaltene deposition and problems arising from it during CO2 miscible flooding was one aspect of a comprehensive five-year multiclient research project. It was started in 1988 at the Saskatchewan Research Council (SRC) to evaluate the Suitability of CO2 as an EOR agent for a southeast Saskatchewan reservoir, Weyburn. Asphaltene deposition and flocculation can change the wettability of the reservoir matrix and consequently affect the flood performance. It can also cause formation damage and wel
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.96)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.96)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Forbisher Formation (0.96)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Charles Formation:Middale Formation (0.96)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Correlation Of Demulsifier Performance And Demulsifier Chemistry
MacConnachie, C.A. (CANMET/EMR) | Mikula, R.J. (CANMET/EMR) | Kurucz, L. (Saskatchewan Research Council) | Seoular, R.J. (Saskatchewan Research Council)
Abstract The chemical make-up of over one hundred demulsifiers was characterized by nuclear magnetic resonance spectroscopy and compared to their effectiveness as determined by standard bottle tests. Principal component analysis was used to handle the extensive data generated from the nmr and bottle tests. The demulsifiers clustered into only a few distinctly different chemical groups. These similar chemical types were shown to have similar demulsification performance which means that demulsifier evaluations can be made on the basis of demulsifier chemistry. Therefore only a few of the chemically distinct ones need to be tested before optimization can begin. Since the nmr chemical characterization takes only a fraction of the time of a bottle test, it is possible to more rapidly identify the best demulsifier and to focus on optimization of demulsifter dosage. This characterization method would be especially useful for chemical suppliers as a way to significantly decrease the number of demulsifters that are evaluated in the field before work begins on optimization. Future research will develop and expand the database to relate demulsifier chemistry to oil and emulsion properties; ultimately to predict demulsiftcation performance from first principles. Introduction Chemical demulsification is commonly used to separate water from heavy oils in order to produce a fluid suitable for pipelining (typically less than 0.5 percent solids and water). A wide range of chemical demulsifiers are available in order to effect this separation. In principle, a complete chemical and physical characterization of both the demulsifier and the emulsion to be separated would allow one to develop a fundamental understanding of the demulsification mechanism and therefore to optimize the demulsifier selection or allow synthesis of tailored demulsifiers for separation of particular emulsions. In practice, this is not yet possible because of the wide range of factors that can affect demulsifier performance. Aside from demulsifier chemistry, factors like oil chemistry. the presence and wettability of solids, oil viscosity and the size distribution of the dispersed water phase can all influence demulsifier effectiveness. As a result, an empirical approach involving the testing of many, (often hundreds), of demulsifiers is undertaken to determine the best candidates for optimization based on dosage. As a first step in developing a fundamental understanding of the relationship between demulsifier chemistry and effectiveness, 121 different demulsifiers (or demulsifier bases) and six different produced oil samples were evaluated. Clearly, it would be prohibitive to develop derailed chemical and physical analyses of such a large number of demulsiflers and In any case, such a detailed analyses of the demulsifiers may not completely account for their performances on different oil emulsion samples. However. if performance on a given emulsion were related to chemical composition, it would be possible to rapidly optimise demulsifier selection by testing selected members of chemically distinct demulsifier groups and doing more detailed bottle tests only on members of the groups that showed the best results. Principal component analysis (PCA) is one method that allows one to relatively quickly develop correlations between similar members of large data sets .
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (0.91)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.56)
An Alternative Approach To The Selection Of Pseudocomponents For Modelling In-Situ Combustion
Hutchence, K. (Saskatchewan Research Council) | Freitag, N. (Saskatchewan Research Council)
Abstract An important step in the numerical simulation of in-situ combustion for enhanced oil recovery is the selection of the pseudocomponents used to represent the oil. Frequently the oil is separated according 10 distillation cuts. In addition, a hydrocarbon pseudocomponent called "coke" is used to present the heavy residue that results from the reactions immediately ahead of a combustion zone. While this approach provides for some of the general changes that occur during in-situ combustion. it provides a poor basis for representing the overall set of chemical reactions. Chemical principles and the results of several publications from diverse sources suggest that a modified SARA analytical approach presents a sound basis for representing in-situ combustion chemistry. The potential for such all approach is discussed and a set of pseudocomponents is proposed that could plausibly represent all the major physical and chemical changes that oil experiences in the in-situ combustion process. Finally. the steps that are foreseen to successfully implement such all approach are outlined. Introduction In-situ combustion may be a good option for enhanced oil recovery of many reservoirs. Unfortunately, its use is diminished by the lack of reliable methods for predicting performance. Usefully accurate prediction of performance almost certainly requires numerical simulation. The complicated interactions that control firefloods vary with oil and reservoir types and cannot normally be represented in simpler forms. Many of these interactions depend on the chemical reactions that dominate in-situ combustion. Consequently, the selection of a suitable set of pseudocomponents and reactions is vital to the establishment of an accurate numerical model for firefloods. In the search for a suitable basis to express the chemical reactions of fireflooding, a thought-provoking publication by Ciajolo and Barbellawas found. Their thermal gravimetric analysis data suggested that SARA (saturates, aromatics, resins and asphaltenes) analysis offered this sought-after basis for pseudocomponent selection. Various data in another publication by Bad provided a separate indication that the oxidation and cracking behaviour of a wide variety of oils corresponded to their SARA analysis. In this paper, the SARA-based approach is used to build a plausible and comprehensive reaction scheme that describes the chemistry of in-situ combustion; PSEUDOCOMPONENT SELECTION Distillation Cuts The conventional approach to pseudocomponent selection has been to separate oil into boiling-point ranges. This allows reasonable variations in the physical properties of the oil, and can effectively portray distillation effects if at least three distillation cuts are used. In addition, gas and a nonvolatile pyrolysis (thermal cracking) product called "coke" are added to the pseudocomponent list. Coke and gas are usually formed by pyrolysis of one or more of the higherboiling cuts. This approach implicitly assumes that all the material in a selected boiling point range will participate equally in chemical reactions. It also assumes that the high-boiling or non-volatile products of both pyrolysis and low-temperature oxidation reactions are the same. As pointed out below, this is not the case.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.96)