Formic and acetic acids have been used in conjunction with stimulation and cleanout treatments for many years. They have found particular application because of their low corrosiveness on metals and compatibility with crude oils. The organic acids have been used either by themselves or in mixtures containing hydrochloric acid. The mixtures have shown the ability to develop etching of carbonate fractures that is usually representative of acid solutions containing much higher hydrochloric acid concentrations.
Recent laboratory investigations have shown that mixtures of formic acid and hydrochloric acid may have particular application as stimulation fluids in very high temperature environments. While it has been known that formic acid, or compounds that form formic acid through chemical reaction or degradation, can reduce the corrosiveness of HCl, there has been no systematic study to optimize such a system. This paper shows that the low corrosivity of HCl-formic paper shows that the low corrosivity of HCl-formic mixtures can be optimized and is a function of the ratio of HCl to formic acid and highly dependent on the corrosion inhibitor selected for use. It will be shown that mixtures containing as high as 10% HCl can be prepared which maintain low corrosivity at temperatures up to 400 deg. F without the use of inhibitor intensifiers. This low degree of corrosivity can be maintained with reduced concentrations of organic corrosion inhibitor.
This investigation resulted in the development of a retarding system that appears to function synergistically in the presence of formic acid. The reduced reaction rate on carbonates appears to be due to a change in the process controlling reaction kinetics. The retarding system changes the reaction kinetics from a diffusion controlled process to a process that is controlled by the surface reaction process that is controlled by the surface reaction rate. This approach to retardation allows deeper penetration of acid into fracture systems before the penetration of acid into fracture systems before the acid completely spends, and appears to be effective at temperatures to at least 400 deg. F.
The acid system resulting from this investigation has best application in treating wells with bottom-hole temperatures between 250 deg. and 400 deg. F. The mixed acid system can be used to prepare fluids for the following applications: (1) perforating and completion, 12) clay removal with HF/HCl/formic, (3) breakdown fluid ahead of fracturing; (4) retarded acid for fracture acidizing, and (5) scale removal.
Retarded acid systems are considered necessary to stimulate effectively the production of many high temperature formations. Retarded acids are used to achieve an acid penetration distance and a conductive fracture length that approaches the drainage radius of the well.
Chemically retarded and emulsified acid systems utilizing hydrochloric acid have provided adequate retardation at temperatures up to 93-3 deg. C (200 deg. F) and in many applications up to 121.1 deg. C (250 deg. F). Slower reacting and less corrosive acid systems are desirable to stimulate production in wells having temperatures above 121.1 deg. C (250 deg. F).
Formic and acetic acid have been used in conjunction with well completions, cleanout, and stimulation treatments for many years because of their low corrosivity on metals. The organic acids have been used alone, but an important application has been in mixtures with hydrochloric acid.
Organic acids, if reacted individually or as a hydrochloric-organic acid mixture, do not react generally to completion on carbonate formations. A previous investigation with acetic acid and formic previous investigation with acetic acid and formic acid shows 42% and 86% conversion to the calcium salts, respectively." Another investigation with hydrochloric-acetic acid mixtures shows that the acetic acid portion is converted to about the same extent. Fig. 1 shows data obtained with a 7 1/2 HCl-10% formic acid mixture. These data show that 86% of the formic acid in the mixture was converted to calcium formate at a temperature of 121.1 deg. C (250 deg. F).
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.
The prime purpose of this work was to provide thermal cracking reaction models which can be incorporated into numerical simulators of thermal recovery processes for the Athabasca Oil Sands. processes for the Athabasca Oil Sands. Athabasca bitumen, free of water and minerals, was thermally cracked at constant temperatures in a closed system under an inert atmosphere. The products of cracking were separated into six pseudo products of cracking were separated into six pseudo components: coke, asphaltenes, heavy oils, middle oils, light oils, and gases. Experimental runs were made over the temperature range from 303 deg. C to 452 deg. C. Three series of runs were made at 360 deg. C, 397 deg. C, and 422 deg. C in which the reactions were terminated at various degrees of cracking. For these runs, reaction time versus product concentration curves were obtained for the above six pseudo components.
Several pseudo reaction mechanisms are proposed to simulate the experimental results. The reaction rate constants were represented by an Arrehnius type expression, the activation energies and corresponding frequency factors were determined for each reaction mechanism proposed.
Recently, the use of numerical simulators to predict the performance of steamfloods has become predict the performance of steamfloods has become a common practice.
As far as the numerical simulation of in situ combustion is concerned, a number of simulators have been developed and many of them have been successful in predicting the fluid flow and the temperature profiles along with the production history. The model presented by Crookston et al. incorporates most of the physical and chemical phemonema including the fluid flow, the phase phemonema including the fluid flow, the phase behavior and oxidation and thermal cracking reactions. Although it is claimed that the model can be applied to any thermal recovery process, it has not yet been thoroughly tested.
In the case of the in situ combustion process, the fuel which is a coke-like material is deposited on the reservoir rock by a combination of gas stripping, vaporization and thermal cracking. The major operational cost of the in situ combustion process is for compressing air. The quantity of process is for compressing air. The quantity of air required depends on the amount of fuel available underground, thus the quantitative prediction of the extent of thermal cracking is directly related to the economic evaluation of an in situ combustion project.
Thermal cracking reactions also play an important role in fluid flow in the reservoir because the flowing oils do not have the same fluid properties as the original oil in place. Thermal cracking reactions are also important for the design of bitumen upgrading facilities.
Although rather extensive studies have been made of thermal cracking reactions involving Athabasca bitumen, most studies reported so far are concerned with the chemical and physical properties of the cracked products. In this study emphasis was placed on the collection of experimental data and the development of a prediction model of the thermal cracking reactions.
The experimental apparatus used in this study is schematically shown in Figure 1. The reaction vessel was placed in an electrically heated furnace which was equipped with a stirrer in order to obtain an even temperature distribution within the furnace. The temperature of the bitumen sample was measured with a 1.59 mm O.D. stainless steel sheathed C/A K type thermocouple. The pressure of the system was monitored by a pressure transducer. Vacuum and helium gas lines were provided as shown in Figure 1 to achieve an inert gas atmosphere in the reaction vessel at the beginning of each experimental run.
An investment risk analysis by the probability distribution technique was proposed and published by Hillier in a 1963 issue of Management Science. His work was quite theoretical. A simplified form of the method was presented in petroleum literature by Davidson and Cooper in 1975. However, their work did not extend to using the method in practical decision making. Both of these works critically discussed why this approach is preferable to earlier methods. In as much as the main value of such an innovation and the ultimate need for its publication is its application, discussion of the practical aspects of the method is important. The purpose of this paper is to fulfill this need.
Regardless of what criterion an investor uses to determine the profitability of his venture, the amount of risk involved must be considered for a sound, final decision. As such, many techniques have evolved over the years for quantifying risk. Among the older techniques which have been used are: 1) Payback Period - The length of time required to Payback Period - The length of time required to recover an investment through the net cash flows from the project. 2) Expected Monetary Value - Sum of the products of investment outcomes and their respective products of investment outcomes and their respective chances of occurrence. 3) The Certainity Equivalent - A method of discounting cash flow by a risk-free interest rate. 4) Sensitivity Analysis - Determining the profitability measure by varying an uncertain parameter. For reasons well discussed in parameter. For reasons well discussed in literature, all of these techniques are weak and are inadequate for proper risk portrayal. The more recent and certainly more sophisticated method of risk analysis is the probability distribution of the profitability index. One form of this is the Monte profitability index. One form of this is the Monte Carlo simulation which uses randomly selected parameters from appropriate ranges of values to generate parameters from appropriate ranges of values to generate a series of possible outcomes. While this technique is a quite reliable tool, it does not lend itself to routine application because of the computer work involved. Another form is the, analytical technique proposed by Fredrick Hillier . This approach adopts proposed by Fredrick Hillier . This approach adopts well know statistical theories and assumes the distribution of the profitability index to derive the probability distribution. Hillier's work, though probability distribution. Hillier's work, though amenable to hand calculators, was quite theoretical. A simplified form of the method was presented in petroleum literature by Davidson and presented in petroleum literature by Davidson and Cooper in 1975. However, their work did not extend to using the method in practical decision making.
This paper discusses the practical aspects of Hillier's approach. Although Davidson and Cooper suggested log-normal distribution assumption for analysis of petroleum investments, this work is based on the validity of normal distribution when the random variable is the cash flow. Both assumptions are compared in the discussion. Arriving at a decision to accept or reject an investment proposal on the basis of the method requires the use of utility theory. Therefore, the concept of the theory is reviewed. Its use in conjunction with the probability distribution of net present value is then shown. Finally, a decision present value is then shown. Finally, a decision concerning two or more risky investments may be influenced by the skewness of normal distribution. Hence, the semi-variance equation for testing the normality or magnitude and direction of skewness is presented and its application discussed.
DERIVATION OF PROBABILITY DISTRIBUTION
In his work, Hillier assumed that under conditions of uncertainity, cash flows from an investment are random variables which can be characterized by their means and variances. Therefore, by the central limit theorem, the distribution of these means will be approximately normal. Moreover, their sum will approach a normal distribution. Based on these, he derived the probability distributions of net present values and internal rate of return for three possible cases of cash flows from an investment. These cases include (1) statistically independent cash flows (2) perfectly correlated cash flows and, (3) combined independent and correlated cash flows. This paper considers the second case only.
A comprehensive numerical model of the under-ground coal gasification process via the stream method was developed for a two-dimensional geometry. Seven reactions, involving carbon, carbon dioxide, carbon monoxide, oxygen, water/steam, hydrogen, and methane are accounted for. Nitrogen is the seventh gas component. As a result of gasification, the channel diameter increases with time, and a combustible gas is produced. The model accounts for all of these factors.
Considering the fact that vast known coal reserves occur in the United States, much research has been directed toward producing synthetic liquids and gases via above ground gasification and liquefaction of coal which lends itself to large scale operations. The current federal and state pollution control regulations and the enormous cost of mining, transporting and processing make this process commercially unfeasible. Furthermore a low quality coal cannot be used in this process. Some of these problems can be avoided if gasification of coal in situ is utilized.
This process, known as underground gasification of coal, is defined as the controlled burning of coal seam in the presence of gas mixture consisting of mainly nitrogen, oxygen and steam, to produce gasification reactions. A combustible gas mixture containing nitrogen, carbon monoxide, steam, hydrogen, methane and carbon dioxide is formed, which can be used in the generation of electricity on a commercial scale.
This method possesses many advantages over conventional mining and synthetic fuel operations in that it minimizes health hazards to miners, improves process safety, provides ecological benefits in that process safety, provides ecological benefits in that the land surface is left intact, and eliminates much of the need for aboveground plant requirements. Furthermore, it offers a technically simple and feasible method for producing the vast bituminous and low rank coal reserves in the United States (much of which can neither be economically mined nor is acceptable in rank for commercial synthetic fuel operations), and if designed properly can be very economical.
In order to increase the understanding of this process, a series of steady state analytical models process, a series of steady state analytical models by the stream methods were developed by Magnani, by Magnani and Farouq Ali, and by Farouq Ali and Pasha. The steady state assumption of the process enabled the extraction of closed form solutions, which, though complex, were useful for carrying out parameter sensitivity studies. Furthermore, these models were of considerable value for carrying out pseudosteady state simulation of unsteady state underground coal gasification process.
The present model is a numerical extension of the previous models, and as a result is considerably more general. A two dimensional axisymmetrical coal seam is assumed to be ignited at one end and thereafter a mixture of air and steam (or a mixture of oxygen enriched air and steam) is injected. As a result, the combustion zone advances in both axial and radial directions and the channel wall recedes resulting in the production of a combustible gas mixture.
It should be mentioned that while this study has been devoted to the stream method of underground coal gasification, a number of other simulation studies has been reported which consider other gasification processes. These include the works of Kotowski and processes. These include the works of Kotowski and Gunn, Gunn and Whiteman, Winslow, Thorsness and Rosza, and Dinsmoor, Galland and Edgar.
1. The coal bed consists of 100% carbon. However, the model allows for source terms in all components considered and thus the influx of any of these as a function of distance and time may be simulated.
2. The gasification channel is initially assumed to be of cylindrical geometry, one extremity of which is ignited.
Leakoff control is the key to effective stimulation of carbonate reservoirs by acid fracturing. Converting the acid to a stable foam is one method of greatly improving control of fluid loss to the formation. This method is particularly useful at high temperatures since most of the commonly used fluid-loss additives are destroyed by acid at elevated temperatures. Foaming the acid not only provides fluid-loss control but retards acid reaction rate.
Acids are easily converted to a stable foam by adding a foaming agent and injecting gases at the surface. For high temperature applications, foam stabilizers can be added to the acid to enhance foam stability.
This paper presents data showing the effect of foam quality, permeability and temperature on leakoff rate in limestone cores. Recommendations are presented for improving the effectiveness of foamed acid treatments. Also, field results are presented to show the increased effectiveness presented to show the increased effectiveness of stimulation treatments using foamed acid.
One of the most difficult problems encountered in well stimulation is the control of fluid loss during acid fracturing treatments. Most commonly used fluid-loss additives are either destroyed by the acid or rendered ineffective at elevated temperatures. The constant and rapid acid erosion of the fracture faces further camplicates the problem by preventing filter cake formation.
Foams present a new approach for achieving acid fluid-loss control. Previous laboratory studies have demonstrated the effectiveness of foam as a fracturing fluid, emphasising its fluid-loss-control properties. These same properties have also been properties. These same properties have also been attributed to foamed acid; however no substantiating data have yet been presented This paper presents laboratory data describing fluid-loss-control properties of foamed acid against limestone and illustrates the difference observed between acid and nonreactive foamed fluids.
Leakoff control during acid fracturing treatments has proved to be of prime importance in achieving optimum stimulation results. Although a number of authors have proposed techniques to control acid proposed techniques to control acid fluid-loss, new and more efficient methods are constantly being sought . Most conventional fluid-loss additives control leakoff by depositing a low permeability filter cake against the fracture face. Fluid loss is thus reduced by a wall-building mechanism.
More recently, foams have been used to achieve fluid-loss control in acid fracturing treatments. One of the advantages of foam is its quality of being a clean fluid, void of particulate fluid-loss additives which may have potential for producing formation damage. Also, since producing formation damage. Also, since foams are not wall-building fluids, leakoff control is not affected by fracture face erosion.
The flow of foams through porous-media has been investigated by several porous-media has been investigated by several authors . It has been demonstrated by Bernard and Holm that the effective permeability of a porous media is greatly permeability of a porous media is greatly reduced in the presence of foam.
Aminoil USA has been waterflooding the Huntington Beach Field since 1959. During this time three zones have been waterflooded: the Upper Jones, the Lower Jones, and the Lower Main. The Upper and Lower Jones have been flooded using only sea water, while the Lower Main Tone flood was initiated with sea water and then converted to produced water.
This paper discusses the problems which have been encountered in the waterflood projects due to the use of sea water and produced water. Specifically, these problems have included biological sulfate reduction, corrosion, scaling, and injectivity impairment. Also presented are the chemical and mechanical approaches to solve these problems. problems. In 1973, changes in the ocean discharge requirements resulted in conversion of the Lower Main Zone waterflood from sea water to produced water. Several problems were experienced which led to injectivity impairment caused by the high hydrogen sulfide and oil concentration of the produced water. produced water. In May 1978 Aminoil USA initiated a pilot test of an alkaline flooding process in the Lower Main Zone using 11,000 barrels per day of a blended produced water which has been softened. The problems associated with removing the calcium and magnesium from the high total dissolved solids produced water with carboxylic cation exchange produced water with carboxylic cation exchange resin will be discussed.
The Huntington Beach Field is a major producing field lying on the California coastline producing field lying on the California coastline approximately 20 miles southeast of Los Angeles. Figure I shows the location of the Huntington Beach Field in the Los Angeles Basin with the offshore area of the field cross-hatched.
The field has a length of seven miles along the Newport-Inglewood Fault zone and a maximum width of three miles. Production from the offshore area is from five major zones with the upper zone production stimulated by steam injection while three of the lower zones are under waterflood. One of the zones has not yet been waterflooded and is producing by primary. Two of the zones, the Upper Jones and the Lower Jones, are currently being waterflooded with sea water, while the third zone, the Lower Main, is being flooded with produced water; although initially the Lower Main produced water; although initially the Lower Main Zone was flooded with sea water. The Huntington Beach Field ranks as the third largest waterflood in the United States with a current water injection rate of 450,000 barrels per day.
Waterflooding has been conducted in the Huntington Beach Field since 1959. During this time a number of problems have been experienced which relate primarily to water treatment and water handling. This paper will discuss those problems and their relation to sea water flooding, problems and their relation to sea water flooding, produced water flooding, and the utilization of produced water flooding, and the utilization of produced water for an alkaline flooding project. produced water for an alkaline flooding project. SEA WATER FLOODS
In 1959 waterflooding was initiated in the Lower Jones Zone, and in 1968 expanded to include the Upper Jones. Because of the proximity of the field to the ocean, sea water was used as the primary water source for the waterfloods. Rather primary water source for the waterfloods. Rather than pumping water directly out of the ocean, wells drilled to a gravel bed approximately 30 feet thick and lying approximately 60 feet below the surface were found to be an adequate source of sea water. The water produced from these wells was essentially filtered sea water without the suspended solids and plankton which would be expected in water taken directly from the ocean.
This study has looked into the feasibility of operating a floating methanol plant in a North Sea environment. The plant was fed with associated gas from an oil field.
Both the technical and economical results are promising. This indicates that such projects might promising. This indicates that such projects might be an alternative solution for otherwise reinjected gas; however, more work needs to be done to evaluate their attractiveness.
By now the floating production facility approach is a well recognized concept. Its major advantages are savings in capital investments, shorter development time, and increased flexibility because parts of the facility can be easily relocated.
So far the interest has focused mostly on floating gas processing plants; however, to the author's knowledge none is planned yet for the North Sea.
The purpose of this study was to do a technical/ economical feasibility study of gas-to-methanol conversion aboard a converted oil tanker in the North Sea.
The methanol plant would be of Imperial Chemical Industries (ICI) design. Close contacts were established with their contractors in order to find what is critical when operating a plant under such adverse conditions.
With few exceptions the contractors outlined the same points as critical. Based on this information and knowledge about the limitations on other parts of the facility, it was possible to arrive at parts of the facility, it was possible to arrive at an expected "on time" plant availability.
The methanol producer was treated as a separate company, buying associated gas from the field operators.
A computer model was written to perform the economic evaluations. Both a base case calculation and a sensitivity analysis were treated in this model.
2. DESCRIPTION OF EQUIPMENT AND PROCESSES
Fig. 1 shows a principle view of the thought facility. The associated gas arrives at the SALM base, rises through it, and feeds into flexible lines to the plant. The 1000 M.T./day methanol plant is ICI's L.P. (low pressure) design.
In the plant the gas is first desulphurized. It is then combined with superheated steam (prepared from seawater) and fed to a reformer. There, synthesis gas, comprising hydrogen and carbon oxides, is formed. This mixture is further compressed and fed to the reactor where the methanol reaction takes place. This methanol is thereafter distilled and place. This methanol is thereafter distilled and stored in the tanker.
The processing tanker, together with the shuttle tanker when loading occurs, is free to weathervane 360 degrees around the SALM. The shuttle tanker then brings the methanol to a shore base for further distillation into grade AA before being stored.
The methanol facility is self-sufficient with energy and has an overall thermodynamic efficiency of approximately 60%. As a rule of thumb, it can be said the production of 1 M.T. of methanol requires approximately 31 MMSCF of natural gas.
3. TECHNICAL FEASIBILITY
The mooring unit is of Exxon's SALM type. It is able to permanently moor a 50-60000 DWT tanker in a northern North Sea environment, and should therefore not represent operating limitations.
The Exxon SALM is built in modules for rapid connections/disconnections when maintenance or repairs are performed at the field site.
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.
Thus paper discusses the application of a compositional model to develop an optimum exploitation scheme for the C Pool gas condensate reservoir. Performance predictions of a straight blowdown and Performance predictions of a straight blowdown and three cycling schemes involving different replacement ratios have been obtained. Considerable emphasis was placed on predicting the reservoir rock properties in placed on predicting the reservoir rock properties in a highly heterogeneous reservoir such as the Kaybob Beaverhill Lake C Pool, and on the phase behavior of data derived from laboratory studies. Also, a productivity loss factor that results due to productivity loss factor that results due to condensate accumulation in the vicinity of the wellbore was incorporated in the model. These special features were necessary to increase the reliability of model predictions while cycling.
Results of the model study indicated that a good match of phase behavior was developed, thus ensuring a reliable prediction of gas cycling. Predictions indicated that cycling technically was feasible and that recovery of an additional 2 million bbl of hydrocarbon liquids trill occur compared with a straight blowdown scheme. The economic evaluation performed for the simulated schemes indicated that a performed for the simulated schemes indicated that a partial cycling scheme provides the best economics to partial cycling scheme provides the best economics to initiate the exploitation of the C Pool. This simulation study formed the basis of an application filed with the Energy Resources Conservation Board of Alberta requesting approval to implement a gas cycling scheme in the Kaybob Beaverhill Lake C Pool.
The Kaybob Beaverhill Lake C Pool, discovered in 1961, is located approximately 180 miles northwest of Edmonton, Alta., as shown in Fig. 1. Exploitation of the pool will be performed through five wells located in Townships 63, 64, and Range 18 West of the Fifth Meridian.
Originally it was believed that this gas condensate reservoir was in communication with an oil reservoir northwest of the Kaybob Beaverhill Lake area. However, reservoir fluid analyses from Wells 12-24-63-18 and 10-4-64-18 as well as pressure surveys in Wells 2-4, 10-4, and 4-10-64-18 led to the conclusion that the East Kaybob Beaverhill Lake area consisted of a saturated volatile oil reservoir and a gas condensate reservoir that do not communicate. This was confirmed further with the drilling of Well 11-3-64-18, which encountered the early postulated permeability barrier. The well postulated permeability barrier. The well subsequently was abandoned.
Production from this gas condensate reservoir under a straight blowdown could be detrimental to hydrocarbon liquids recovery because of retrograde loss during depletion, so gas cycling can be carried out to maintain the reservoir pressure and minimize retrograde loss by simultaneously changing the reservoir fluid composition.
DATA FOR THE MODEL STUDY
Reservoir Description and Fluid Properties
The Kaybob Beaverhill Lake C Pool is part of the Swan Hills reef limestone development. The reservoir dips toward the south and west as indicated by the structure contour map of the bottom of the pool shown in Fig. 2. Maximum net pay thickness pool shown in Fig. 2. Maximum net pay thickness based on the reef section encountered in Well 12-24 is 195 ft (6875 to 7070 ft subsea). The hydrocarbon pore volume distribution is shown in Fig. 3. Based pore volume distribution is shown in Fig. 3. Based on this mapping, the total hydrocarbon pore volume was calculated to be 7676 acre-ft, resulting in an original gas-in-place of 82 Bcf. The computational grid for the simulation model is presented in Fig. 4. The original reservoir pressure at a datum of 7040 ft subsea is 4315 psia. This pressure is about 240 psia above the dew-point pressure of 4075 psia at 237 deg. F. The reservoir fluid has a total propane-plus fraction of 18.08% with the heptane-plus fraction in the amount of 6.64%. Based on this composition the initial hydrocarbon liquid content of the gas is estimated at 190 bbl/MMcf.