The purpose of the paper is to extend reservoir limit test analysis techniques to fractured wells. By deriving the pseudo-steady state pressure functions for an unfractured and a fractured well at any position of a closed rectangle, it is shown that shape factors for fractured wells are not readily obtainable from the ones for unfractured wells.
Exact analytical expressions of shape factors for fractured and unfractured wells in a closed rectangle are presented, along with graphs of these quantities versus appropriate parameters.
Type curves for a fractured well at the center of a closed rectangle are also provided. Both uniform flux and infinite conductivity fractures are considered.
The curves presented in this paper are then used with actual field data for estimating the drainage volume of a fractured well and the shape of the well drainage area.
Reservoir limit tests, introduced by Jones1, are commonly used for evaluating the reservoir volume communicating with the well. The analysis is based on the fact that the well pressure during pseudo-steady state flow is a linear function of the production time:
A represents the drainage area (in sq.ft) and CA the drainage area shape factor. Eq. 1 may also written in dimensionless form as:
A cartesian plot of bottom-hole flowing pressure versus production time will thus yield a straight line after pseudo-steady state conditions are reached. The slope of the straight line (Eq.2) may be used to estimate the connected reservoir drainage volume:
and the drainage area, if Ï?h is known.
The shape of the drainage area may be estimated from the pseudo-steady state cartesian plot if pressure data are also available from an infinite acting flow period2. These are used to determine the semi-log straight line slope:
and p1hr. The system shape factor is then obtained from:
By comparing the calculated CA with the ones published in the literature for various drainage area configuration3-5, it is possible to estimate the shape of the drainage area.
The underground coal gasification field test performed by the Alberta Research Council on a site performed by the Alberta Research Council on a site near Forestburg, Alberta, during the summer of 1976 is reviewed and the 1977 excavation of the test site discussed. The test comprising two burns was made in the Battle River coal seam which is overlain by 20 m of an alternating series of bentonitic shales, siltstones and sandstones. The subbituminous coal seam was 3.6 n thick and had two significant horizontal partings.
The gasification area was defined by the injection and production well pattern which was 9.1 m along the minor cleat and 18.3 m along the major cleat in the coal. Control of the rate and pressure of the air used for gasification permitted use pressure of the air used for gasification permitted use of the formation water for the reaction, producing a gas with a heating value of 3700 to 5600 kJ/m .
The region of the first burn was excavated to obtain data from the coal zone affected by the test. The visually affected zone, comprising dried, carbonized and gasified coal, was measured, photographed and sampled for laboratory analyses. photographed and sampled for laboratory analyses
A major objective in selecting the site for the underground gasification test was to find a subbituminous seam that was shallow enough to permit excavation of the burn area after completion permit excavation of the burn area after completion of the test. A number of locations were investigated and the most suitable site was the one selected near Forestburg, Alberta. The test involved completion of 25 wells into the coal seam: four gasification wells, nine instrumentation wells and 12 water observation wells. The four gasification wells were located on the corners of a 9.1 m by 18.3 m rectangular pattern as shown in Fig. 1. Two burns were made. Burn 1 comprised the ignition of the coal in well no. 3 (cf. Fig. 1), followed by linking along the minor cleat to well no. 4 by reverse combustion and forward gasification back to well no. 3. This process lasted in excess of two weeks and produced 25 500 m of gas with an average heating value of 3700 kJ /m during linking and 169 900 m of gas with an average heating value of 5600 kJ /m during gasification.
Ignition in well no. 1 with linking by reverse combustion to well no. 2 and forward gasification back to well no. 1 comprised the first phase of burn 2. The second phase of burn 2 was an attempted line drive (forward mode) from the gasification zone between wells no. 1 and 2 to the burn 1 zone between wells no. 3 and 4. During the attempted line drive a channel from the burn 2 area to well no. 3 was established. Difficulties in maintaining lateral containment of the produced gases were encountered during burn 2 because much of the formation water was depleted during the first burn.
OBJECTIVES OF THE EXCAVATION
An understanding of the underground gasification process is possible from process data. However, at present it is not possible to confidently predict the geometry of areas which are gasified, predict the geometry of areas which are gasified, carbonized and dried in a coal seam during underground gasification. To define these zones more data are required. Additional information is also required concerning subsidence and chemical and thermal changes of the overburden bordering the gasified coal. The need for this information, a successful burn and the desire to examine and evaluate the condition of the down hole piping and instrumentation led to the decision to excavate the site.
Bourrel, Maurice (University of Texas at Austin) | Lipow, Andrew M. (University of Texas at Austin) | Wade, W.H. (University of Texas at Austin) | Schechter, R.S. (University of Texas at Austin) | Salager, Jean-Louis (Universidad de los Andes)
The oil recovery effectiveness of a chemical flood has been shown to be related to the phase behavior of the brine-oil-surfactant system. In particular, it is advantageous to formulate the system particular, it is advantageous to formulate the system so that middle phases are formed. There are, however, an infinite number of surfactant cosurfactant (alcohol) combinations which will give the desired phase behavior. The selection of the preferred system out of this infinity of possible systems is an optimization problem and is the subject of this paper. problem and is the subject of this paper. An extensive study of the interfacial tension of dodecyl ortho xylene sulfonate sodium salt, as a function of salinity, alcohol and hydrocarbon molecular weight has been conducted. The results reveal that certain formulations may be preferred since the interfacial tension of some systems at optimum conditions is smaller than others. Indeed, conditions giving a global interfacial tension minimum were found.
It is also known that for enhanced oil recovery, it is desirable to maintain miscibility between the chemical slug and the reservoir fluids as long as possible. This means that the height of the possible. This means that the height of the multiphase region should be minimized. This study show that the height can be minimized by a proper formulation.
A correlation relating the variables deft optimum systems for improved oil recovery has be reported . This equation gives the optimum salinity, S*, as a function of the alkane carbon number of the oil, ACN, the alcohol and a parameter, sigma, which is characteristic of the surfactant as follows:
where K is a constant equal to 0.16 for all alkylaryl sulfonates and f(A) is a function of alcohol type and concentration known for alcohols heavier than C5. The dots indicate that other variables, such as the water-oil ratio (WOR) and the temperature, have been omitted since they are not considered in this work. Equation 1 applies if WOR = 4 and T = 25 degrees C. The ratio sigma/K has been called the EPACNUS and is the extrapolated preferred alkane carbon number at unit salinity and preferred alkane carbon number at unit salinity and without alcohol, since f(A) is defined so that it vanishes as the alcohol concentration goes to zero.
Equation 1 represents a plane in the space in S,ACN and f(A) as shown in Figure 1, and any point on this plane is an optimum system in the following sense. For a given oil and surfactant system, a middle phase will be observed over a range of salinities and the midpoint of this salinity range will be called the optimum salinity. Furthermore, the surfactant system is said to be an optimum one. This implies that a series of experiments in which a property important to improved oil recovery, such property important to improved oil recovery, such as interfacial tension or amount of surfactant needed to solubilize certain volumes of water and oil, will yield a minimum value of the property when a point on the plane is reached. Thus, a series of interfacial tension measurements will reveal a minimum value at the point where line 4 shown in Figure 1 pierces the plane. (Perhaps, it would be more pierces the plane. (Perhaps, it would be more precise to assert that the minimum will occur in the precise to assert that the minimum will occur in the vicinity of the plane rather than on it. This point is further clarified in a subsequent section.) If the experiment is repeated at a different salinity or alcohol concentration or both, then the minima of the properties in question will be found at the new point at which a vector parallel to line 4 intersects the plane. If the values of the minima are different at the two points, then one point on the plane may be preferred to the other with regard to plane may be preferred to the other with regard to efficiency of oil recovery. Thus, it is appropriate to ask if all points on the optimum plane are equivalent with regard to oil recovery. This is the question addressed in this paper.
A computer model has been developed to describe the isothermal flow of two multi-component compressible phases, oil and gas, in a two-dimensional porous medium. The composition in each phase and the mass transfer between phases are calculated. Capillary and gravity forces are included. The partial differential equation describing flow in each phase includes a source/sink term which is used to account for mass transfer between the phases. Convective transport is handled by introducing moving points. In this study the Benedict, Webb and Rubin (BWR) equation of state was applied as the "phase behavior package". The numerical solution proceeds in a leap-frog manner, by first solving the flow equations and then carrying out equilibrium calculations. Calculated output from the model includes pressure, saturation, and vapor-and liquid-phase compositions as functions of time and position. The simulator has behaved well for the position. The simulator has behaved well for the different conditions tested indicating the suitability of using a moving point method in a compositional simulator.
Compositional models have been developed by a number of investigators. For these types of models, each hydrocarbon phase is assumed to consist of an N-component mixture. The fluid properties are functions of composition and pressure. Thus, composition should be specified for every mesh point at every time step. One approach to the development of compositional reservoir simulators has been to describe the behavior in terms of differential equations which represent a mass balance for each component in the system. This results in a large number of simultaneous equations which must be solved at each step in the solution. In another approach, a beta-type simulator has been modified to approximate compositional effects. In the latter approach, individual component compositions could not be calculated as a function of time and distance.
In this paper the hydrocarbon system is described basically by two partial differential equations, one describing flow in each phase. Mass transfer between phases is considered by including a sink/source term phases is considered by including a sink/source term in the two partial differential equations. The difference equations approximating the partial differential equations are formulated according to the implicit pressure-explicit saturation (IMPES) numerical method as presented by Stone and Garder. The difference equations, having pressures as the only unknowns, are solved directly using a D4 ordering scheme as proposed by Price and Coats. proposed by Price and Coats. To account for compositional changes resulting from convective transport of each phase, moving points are introduced. Each grid block is subdivided into cells of equal size and a moving point is defined to represent each phase in each cell, i.e., two moving points are used per cell. The points are moved in points are used per cell. The points are moved in each time step as dictated by the solution of the finite difference equations which describe the flow behavior.
Following the movement of the points for a single time step, equilibrium is re-established between phases by doing a flash equilibrium calculation. The phases by doing a flash equilibrium calculation. The mass-transfer rate which occurs is then used as the basis for the source/sink terms in the next tine step in the solution of the flow equations. The solution thus proceeds in a leap-frog manner, by first solving the flow equations and then carrying out equilibrium calculations.
THE MATHEMATICAL MODEL
The Flow Equations
In the flow equations of this model, the transfer of mass between phases is considered analogous to the production-injection (sink-source) process. The production-injection (sink-source) process. The withdrawal of a certain mass from one phase is balanced by an addition of an equal mass to the second phase. Based on this concept, the differential equations which conserve the mass of each phase may be written as follows:
For the oil phase,
The detailed technical evaluation of the Southeast Pecan Island geopressure aquifer prospect is described. The quantitative evaluation was based on detailed geology consisting of structural, isophachous, and cross-sectional maps of the geopressured zone. Pressure, water salinity, porosity, and permeability data were obtained porosity, and permeability data were obtained from well logs.
The gathered information was used to choose a location for a proposed exploratory well.
The evaluation of this prospect can serve as a guide for future analysis of other geopressured prospects.
Sixty-three potential areas of interest for the geopressure energy resource were found in a preliminary geologic study of southern Louisiana. preliminary geologic study of southern Louisiana. The geographic area of the study included all southern Louisiana (south of Baton Rouge) including the State-owned offshore area.
At present, the sixty-three potential areas of interest are being ranked, and the most promising prospects are being mapped and studied promising prospects are being mapped and studied in much greater detail. A preliminary ranking indicates that the better prospects tend to lie in the western half of the study area. The prospects in the eastern half of the study area prospects in the eastern half of the study area were down-graded primarily because of poorer sand development, but it is entirely possible that several of these prospects will be attractive upon closer inspection.
Detailed geologic studies have been started on five prospects. A suitable site for a geopressured test well will be selected within each of these prospects. It is hoped that a test well will be started at one of these sites before the end of the year.
At present, the Southeast Pecan Island area appears to be a promising prospect. This area is identified on Figure 1 together with the other four prospects.
The Southeast Pecan Island Prospect is located in the extreme southern portion of Vermilion Parish, Louisiana, being approximately 25 miles south-southwest of Abbeville, and approximately 6 miles southeast of Pecan Island, Figure 2. The prospect is surrounded by the Pecan Island Field to the northwest, Vermilion Block 16 Field to the south-west, and Fresh Water Bayou Field to the north. It is separated from these fields by large regional faults.
The primary source of data used in the detailed evaluation of the prospect was electric well logs obtained from the files of the Louisiana Office of Conservation. Logs from forty-six wells drilled in the area were available. Core data, water analyses and production test results were available from a limited number of these wells.
The evaluation techniques used are basically those used by the oil and gas industry. However, because of the nature of the problem and the limited data available, the evaluation methodology is noteworthy. Also, this methodology can serve as a guide for future analysis of other geopressured prospects. The following aquifer properties are prospects. The following aquifer properties are important and have been evaluated: (1) Areal extent, (2) depth, (3) thickness, (4) temperature, (5) pressure, (6) porosity, (7) salinity, (8) permeability, pressure, (6) porosity, (7) salinity, (8) permeability, and (9) dissolved natural gas content.
Geopressured zones in Louisiana are known to occur in Tertiary sediments in the southern part of the State. This Middle and Lower Miocene trend ranges in width from 50 to 70 miles northward of the Louisiana coastline.
A new water-oil ratio improvement chemical has been developed which, when applied to producing wells, may substantially improve profitability by decreasing water production and permitting additional oil to be produced. The material, which is polymeric, has a different conformation and polymeric, has a different conformation and polymer-rock interaction than previously used polymer-rock interaction than previously used materials. This new polymeric Water-Oil Ratio Control Agent will be referred to as WORCA which is an acronym for use in this paper only. The performance of WORCA is not significantly altered by performance of WORCA is not significantly altered by mechanical shear, exposure to oxygen, acids, oils, or other normally encountered oil field fluids.
Laboratory results show a significant decrease in relative permeability to water after the WORCA has been applied to a simulated producing formation. Consequent movement of oil relative to that of water is improved. These tests also indicate that wash off is minimal after the material is placed. placed. Application to a producing well is quite simple. An aqueous dilution of the base material is introduced into the formation at less than fracturing pressure. Normally, a rig is not required. No waiting or down-time is necessary. The well may be returned to production immediately.
Developmental field applications have been very encouraging. There has been either (1) marked decrease in water production, (2) a lowered fluid level while pumping the well, (3) an increase in oil production or (4) all of these.
Water production from oil wells is almost unavoidable in water drive reservoirs. The industry traditionally has lived with this problem by either separating and disposing of the produced water or by squeezing with a plugging agent to restrict water entry. The introduction of strict governmental regulations to control the disposal of produced water has rapidly increased the cost of handling this water. For example, in one field, the cost to lift, separate, and dispose of the produced water is $.15 per barrel.
The encroachment of water usually causes a significant decrease in oil production. Normally, as the degree of water saturation increases, the relative oil premeability is reduced. In many cases, the relative oil permeability of a typical sandstone formation approaches 0 when the degree of water saturation is greater than about 40-60%.
A high degree of water saturation near the wellbore may be due to water coning, water fingering, communication with a water zone through high permeability streaks, fissures and/or fractures. As the degree of water saturation increases, water is produced instead of oil. This water may actually "kill" the oil producing zones or portions of zones which are in the same completion.
The high production rate of water may have other problems associated with it, e.g., increased corrosion, sand production, emulsion formation, disposal, etc.
Historically there have been two general methods of treating undesired water production. If the region of water production is well defined and can be isolated, the treatment of that region only with a material which will "set-up" to irreversibly plug the matrix is the preferred method. Examples of zone isolation methods are cement squeezes and acrylamide and sodium silicate type grouts. These methods are generally expensive because of the equipment required.
In the event of a poorly defined water entry or when the expense of a rig is not justified, the use of a variety of chemicals to selectively reduce water production has been attempted. Some of these methods involve dispersing materials in an oil base fluid.
van Deemter, Henk,* and van der Kallen, Albert W.H.,* *Shell Internationale PetroleumMaatschappij, assigned to Nederlandse Aardolie PetroleumMaatschappij, assigned to Nederlandse Aardolie Maatschappij, (NAM), Assen, The Netherlands
In 1975 a three-dimensional seismic survey was carried-out near Coevorden (Drenthe Province in the eastern part of the Netherlands some 60 kms-5 mi-south of the Groningen gasfield, see fig. 1) covering a rectangular area of 4, 8 x 3, 25 kms (3 x 2 mi). This area is situated in a region known for its structural complexity. After 3D-processing including 3D-migration (completed in 1976) it appeared that the 3D-data contained much more information than the conventional 2D-seismic sections and allowed a detailed structural interpretation.
As a result the subsurface target of a gas appraisal well could be selected in a structurally more favourable position, i.e. around 1250 m. (4100 ft) southsoutheast of the surface location. Subsequent drilling of this well (completed early 1978) confirmed the correctness of the interpretation.
Appraisal drilling for natural gas on a high block in the Coevorden area (fig. 13) was delayed for some years as even a rather dense network (+ 250 x 250 m - 820 x 820 ft) of 2D-seismic data could not provide conclusive evidence for structural closure.
In 1975 the Nederlandse Aardolie Maatschappij (NAM) was approached by Shell Internationale Petroleum Maatschappij, The Hague (SIPM) with the question whether NAM would be interested in a 3D pilot project, preferably in an area where it could be of help in a field development plan. NAM accepted SIPM's proposal and selected the rectangular area indicated on fig. 13 for a 3D seismic survey, where the information, besides its value as a pilot study, could help NAM's Production Geological Department in unraveling the structurally complex subsurface.
The fieldwork was carried out by a German-based contractor under supervision of both SIPM and NAM. Seismic 3D data processing was done by a major contractor in Dallas (Texas, USA) under supervision of SIPM. The structural interpretation of the processed data was carried by NAM staff.
In the following a review will be given of the geological/geophysical problems in the area concerned. The 3D-data will be compared with the original 2D-data to indicate to what extent 3D stacking and migration has contributed to the clarification of the structural picture at the main prospective level, leading to the successful drilling prospective level, leading to the successful drilling of an appraisal well.
GEOLOGICAL SETTING IN THE AREA (fig. 2)
The primary objective in the area for natural gas-exploration and -development is the Zechstein Z2-carbonate of late Permian age. The directly underlying Z1-sequence of anhydrite, carbonate and Coppershale rests unconformably on a peneplaned surface of the Upper Carboniferous Coalmeasures, the sandy intervals of which form a secondary objective.
Natural gas originates from the Coalmeasures, generation and migration having taken place from Upper Cretaceous times to Recent. place from Upper Cretaceous times to Recent. The main seal is formed by the Z2 rock-salt overlying the Z2-anhydrite/carbonate interval. The Z2/Z1 sequence and the Carboniferous formations are dissected by numerous faults, sometimes with considerable throw (up to 500 m - 1640 ft), which predominantly control the traps.
Interspersed in the Zechstein salt are slabs of competent rocks (Z3 anhydrites, dolomites and limestones) of largely unknown size and shape. They can be strongly independently tectonized: in some wells duplication and even triplication of the same markerbed has been observed.
The Seminole San Andres Unit pressure maintenance facility in Gaines County, Texas is powered by multiple 1000 hp gas turbine engines driving multistage centrifugal pumps. The exhaust gas from each of these engines contains approximately 7 million Btu/hr recoverable heat. The central treating facilities for this Unit share common sites with the injection facilities and represent a highly variable heat load, ranging from zero in the summer months when production arrives at the treating facilities at design treating temperatures, to a maximum of approximately 25 million Btu/hr during the winter months when production arrives at the treating facilities 30 degrees F below design treating temperatures.
The exhaust gas from four engines is coupled through extended surface gas-to-oil heat exchangers which transfer the rejected heat to the hot oil circulating systems. The heated oil is circulated through shell and tube heat exchangers where the heat is transferred to the emulsion streams.
Because of the large cash flow significance of the production stream the system was designed with 100 percent auxiliary natural gas fired heating capability to replace the turbine exhaust heat when engines are down due to maintenance. The system was installed in 1974 and has operated successfully since, with no major system failures.
While the primary purpose of this paper is to discuss the application of waste heat from gas turbine engines to the dehydration of crude oil, a brief summary of the field production history is presented so that the reader can gain some understanding of the production system to which it is applied. production system to which it is applied. The Seminole San Andres Unit, operated by Amerada Hess Corporation, is located in Gaines County, Texas. The field was discovered in 1936. The discovery well penetrated the San Andres gas cap and produced at an extremely high GOR. This discouraged development until 1939, when the oil column was identified and rapid development of the field occurred.
The primary producing mechanism was solution gas expansion. Bottom-hole pressure had declined from the original 2020 psig to 1150 psig by March, 1969, when an operating unit was formed for the purpose of initiating a pressure maintenance project. The Unit encompasses 15,700 acres and contained approximately one billion barrels of oil in place. Water injection was initiated in October, 1969, utilizing two 1000 hp gas turbine engines driving multistage centrifugal pumps. The injection system has progressively been expanded to the present level of 10 pumps injecting 250,000 barrels per day. These pumps are located in three injection per day. These pumps are located in three injection plants, as illustrated in Figure 1. plants, as illustrated in Figure 1.
A linear stability analysis shows that reverse wet combustion is unstable for nearly all physically realizable operating conditions for the special case of coincident steam and combustion fronts. Expansion effects due to gas generation from combustion and vaporization are found to have a stabilizing influence on reverse wet combustion.
Forward wet combustion is also found to be conditionally stable. Significant expansion effects at the combustion front can overwhelm the stabilizing influence of a favorable mobility ratio and effect destabilization with respect to oscillatory long wavelength modes.
In situ combustion processes are being considered for a variety of recovery schemes for underground fossil fuel deposits. These include combustion processes for secondary recovery of highly viscous crude processes for secondary recovery of highly viscous crude oils, tertiary recovery of lighter oils, in situ retorting of oil shale, oil recovery from tar sands, and in situ coal gasification. It is useful to categorize all in situ combustion processes as either forward or reverse combustion. In the former the combustion front travels in the same direction as the flow of gases, whereas in the latter it travels countercurrent to the direction of gas flow.
Forward combustion is by far the more widely used; in such applications as secondary and tertiary oil recovery, it is effectively the only combustion process us However, reverse combustion offers particular advantages for in situ thermal recovery schemes for relatively impermeable media such as subbituminous coal lignites, and tar sands. The reason for this is that during forward combustion, tars vaporized at the combustion front are convected into cooler regions ahead of the front where they condense and thus reduce the natural permeability of the bed. In contrast, for reverse combustion the vaporized tars, or other high molecular weight compounds generated by the combustion, travel toward the production well through a heated region whose permeability is usually greater than the natural permeability of the bed since the front has passed through it. In technologies such as the linked passed through it. In technologies such as the linked vertical well process for in situ coal gasification, a reverse combustion linking step is used to create a highly permeable link through which the combustion gases from subsequent forward gasification can escape. The use of reverse combustion as a preparatory step prior to forward combustion is also being considered prior to forward combustion is also being considered for tar sands.
Forward and reverse in situ combustion may also be either a dry or wet combustion process. In the former only air is injected into a relatively dry fossil fuel deposit such that any vaporization of water due to conduction of heat from the combustion front, has no effect on the process. In a wet combustion process either water is injected along with air or there is sufficient water naturally present in the deposit, such that the steam front is in relative close proximity to the combustion front. If enough water is present, the steam front can be coincident with the combustion front and thus depress the combustion front temperature to the saturation temperature of steam at the prevailing pressure.
Forward wet combustion has some advantages for secondary recovery processes for highly viscous crude oils because less air is required for the front to traverse a given distance thus making it more economically attractive. The authors are particularly interested in the influence of wet combustion on the sweep efficiency of both the reverse and forward combustion steps for the in situ coal gasification process. This process is being considered for the gasification of process is being considered for the gasification of western subbituminous coal seams which can contain considerable moisture.
The sweep efficiency of many in situ combustion processes is related to the stability of the process. processes is related to the stability of the process. In a stable combustion process any perturbations in the combustion front, due to heterogeneities in the properties of the porous media, flow rate pulsations, properties of the porous media, flow rate pulsations, or a variety of other possible causes, die out very rapidly and the progressing flame front is more or less planar. In an unstable combustion process these perturbations grow rapidly and create a fingered perturbations grow rapidly and create a fingered combustion front which can bypass much of the potentially recoverable fossil fuel, thus making the process quite inefficient. Unstable in situ combustion is not always disadvantageous.
Aqueous solutions of two synthetic petroleum sulfonates, nonyl and dodecyl orthoxylene sulfonates with tertiary amyl alcohol as cosurfactant, were studied with the polarizing microscope. Surfactant concentrations of 2-10%, the approximate range being considered for injection in surfactant processes, were used, while salinities in each system ranged from well below to well above the optimum salinity for a particular mixture of refined oils. The solutions were also studied as a function of temperature and time.
Both these surfactants showed the same pattern of structure variation with salinity. At low salinities there was a dispersion of liquid crystalline particles in brine. At high salinities a single liquid crystal-line phase was present. over a narrow range of intermediate salinities a mixture of these two structures was seen. The generality of this behavior was confirmed by observation of solutions of two conventional petroleum sulfonates, which also exhibited a transition petroleum sulfonates, which also exhibited a transition between structures over a narrow salinity range.
The mean salinity of the transition region was found to increase as a surfactant's optimum salinity increases for a given oil. Since optimum salinity is associated with the lowest interfacial tensions, this result indicates that structure of an injected surfactant solution is related to its ability to produce low tensions on contacting oil. Solution viscosity should also be affected by the structural changes.
A major portion of current research on enhanced oil recovery deals with chemical flooding processes employing surfactants. In many proposed processes the surfactant is injected as a "slug" which is an aqueous saline solution containing the surfactant and often an alcohol cosurfactant as well. Surfactant concentration in the slug is typically in the range of 2-10% by weight.
Both the slug's flow behavior within the reservoir and its interaction with trapped oil globules, especially its ability to produce ultralow interfacial tensions and mobilize such globules, are very important for process performance. To obtain information which will help in understanding and predicting such aspects of slug behavior, we have used the polarizing microscope to study the macroscopic structure of aqueous saline solutions of some petroleum sulfonate surfactants. As discussed below, we have found that structure variation with composition, especially with salinity, follows a general pattern in these systems. in particular, there exists a narrow salinity range for each surfactant-cosurfactant mixture where a change occurs from one type of structure to another. The salinity where this transformation in structure occurs increases as the optimum salinity of the surfactant-cosurfactant mixture increases for a given oil. Since the lowest interfacial tensions occur at optimum salinity, these results suggest that the structure of the injected surfactant slug is related to its ability to produce low tensions upon contact with oil.
The synthetic petroleum sulfonates used were mono-ethanolamine alkyl orthoxylene sulfonates, which were supplied by Exxon Chemical Company. In PDM-337, which contains 84% active sulfonates, the alkyl chain is predominantly dodecyl. In PDM-484, which is 85% predominantly dodecyl. In PDM-484, which is 85% active, the alkyl chain is mainly nonyl. Conventional petroleum sulfonates used were TRS 10-410, which was petroleum sulfonates used were TRS 10-410, which was supplied by Witco Chemical Corporation, and Mahogany AA, which was supplied by Amoco Production Company. ate former contains 61.5% active sulfonates and has an equivalent weight of 424, while the latter contains about 60% active sulfonates and has an equivalent weight of 430.
Reagent grade isopropanol, isobutanol, and tertiary amyl alcohol were used as cosurfactants. The surfactant-cosurfactant mixtures were added to brines of the appropriate compositions made from distilled water and reagent grade NaCl.