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Results
Determination of Rock Compressibility in Unconsolidated Sand in Heavy and Extra-Heavy Oil Fields in Mexico
Fragoso, A. (Schulic School of Engineering, University of Calgary, Calgary, Alberta, Canada) | Aguilera, R. (Schulic School of Engineering, University of Calgary, Calgary, Alberta, Canada) | Cinco-Ley, H. (Universidad Nacional Autonoma de Mexico and Consultant, Mexico)
Abstract Unconsolidated sands in heavy and extra-heavy oil fields in Mexico have significant potential that has not been fully evaluated yet. Thus, this paper examines petrophysics and geomechanical aspects with a view to estimating rock compressibility. This is important since determining this parameter from cores has proved to be difficult many times as the samples tend to collapse easily during laboratory experiments. The proposed method uses an empirical correlation for estimating Biot coefficient (Li et al., 2020) and more established geomechanical equations written in such a way as to allow the estimation of several types of compressibilities including: bulk compressibility, uniaxial bulk compressibility, pore compressibility, uniaxial pore compressibility, and pore compressibility under hydrostatic load. The data are loaded on a Pickett plot (1966, 1973) to demonstrate the value of pattern recognition. There are several intermediate results from calculations leading to the compressibilities mentioned above. These include process speed (ratio of permeability and porosity), pore throat aperture in microns at 35 percent cumulative pore volume (rp35), water saturation (Sw), mercury-air capillary pressure (pc), pore throat apertures (rp) at different water saturations, Biot coefficient (ฮฑ), Poisson's ratio (PR), shear modulus (G), Young's modulus (YM), and fluid compressibility (cf). An important observation is that although use of the equations presented in the paper are straight forward and lead to quick calculation of all parameters mentioned above, it is likely that calculations from well logs without using pattern recognition may lead to uncertain results. The novelty of the paper is developing a methodology for calculating diverse types of rock compressibilities in unconsolidated sandstone reservoirs. Application of the methodology can lead to improved calculated recovery factors of unconsolidated sandstone reservoirs in heavy and extra-heavy oil fields in Mexico by at least 10%.
- North America > Mexico (1.00)
- North America > Canada > Alberta (0.68)
- North America > United States > Texas (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)
Abstract A method, based on factual observations of naturally fractured reservoirs in several countries is presented for estimating distribution of hydrocarbon cumulative production in wells drilled in fractured reservoirs of types A, B or C. These observations indicate that in reservoirs of type C most of the cumulative production is provided by just a few wells while the majority of the wells contribute a small part of the reservoir cumulative production. In reservoirs of type B the number of wells contributing significantly to cumulative production becomes larger relative to the case of type C reservoirs. Finally in reservoirs of type A, a large number of wells contribute to field production, as compared with type B reservoirs. The method is shown to be useful for tackling problems of practical importance in naturally fractured reservoirs including, performing or not infill drilling, estimating the variation in cumulative hydrocarbon production per well in a given reservoir, and estimating the number of wells that might be required for a given field hydrocarbon recovery. The method is illustrated using data from various fractured reservoirs, including the Barnett shale and sandstone reservoirs in the United States, carbonate reservoirs in Mexico and Venezuela, and coalbed methane reservoirs and tight gas sands in Canada. Introduction Methods for estimating the optimum number of wells in a given reservoir have been available for over 80 years (Haseman, 1929). More recently Nelson (2001) analyzed cumulative production per well in individual naturally fractured reservoirs and found that there are distinctive variations in the production distributions depending on the amount of natural fracturing and heterogeneity present in the reservoir. From this observation Nelson concluded that these distributions are a function of fractured reservoir type, something that has been corroborated by this author in several instances as discussed in this study. Figure 1 shows the ABC classification of naturally fractured originally introduced by McNaughton and Garb (1975). In naturally fractured reservoirs of Type A the storage capacity in the matrix porosity is large compared with storage capacity in the fractures (Figure 1A). This is generally equivalent to a reservoir of type 3 in Nelson's classification (2001). For this case, it can be seen in the lower part of Figure 1A that a small percentage of the total porosity is made out of fractures. In general, this situation would tend to occur in reservoirs where the matrix porosity is rather high (larger than 10 up to more than 35%). However, there are exceptions. For example reservoirs in tight gas formations can be generally classified as being of type A even if their porosity is usually smaller than 10%. If the matrix has some permeability so as to allow flow into the wellbore, Type A reservoirs can be considered equivalent to what Nelson (2001) has called "fracture permeability assist" reservoirs, i.e., reservoirs where the fractures contribute permeability to an already producible reservoir. Figure 1B shows a schematic of rocks with about the same storage capacity in fracture and matrix porosity (Type B reservoirs).
- North America > United States > Texas (0.35)
- North America > Canada > Alberta (0.30)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.87)
- South America > Venezuela > Zulia > Maracaibo Basin > La Paz Field (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.97)
- North America > Canada > Alberta > Nelson Field > 981384 Nelson 4-20-44-25 Well (0.97)
- (2 more...)
Abstract As part of the activities of the ConocoPhillips-NSERC-AERI Chair in Tight Gas Engineering established in the Chemical and Petroleum Engineering Department at the University of Calgary, a comprehensive literature review has been conducted that has led to an understanding of the current status of the study of tight gas sand formations. This paper presents the results of that work, concentrating initially on Canadian and U.S. tight gas sands. The literature survey discussed in this paper is the first part of the mission-oriented research on tight gas reservoirs conducted at the University of Calgary. The planned research looks at refining the resource base and recoveries from tight gas formations in Canada. Evaluating the current status of geologic models, reservoir characterization, recovery and production technologies currently available for these types of formations is the first step in the effort to reach the final goal: finding the economic means of producing as much of this gas as possible. It is expected that the research results will prove to be of value in other parts of the world and will be exportable, creating business opportunities for Canadian companies. The program will also result in a supply of highly qualified professionals having significant knowledge of tight gas formations. Introduction The complete reference list and interpretation of tight gas sands are presented by Aguilera and Harding. Tight gas sands are part of what is usually known as unconventional gas, which also includes coalbed methane, shale gas and natural gas hydrates. Although tight gas production is not reported separately in Canada, interest in this resource is growing significantly. Tight gas sands have been defined in different ways by different organizations and a unique definition has proven elusive. The original definition dates back to the U.S. Gas Policy Act of 1978 that required in situ gas permeability to be equal to or less than 0.1 mD for the reservoir to qualify as a tight gas formation. At present, this is probably the most commonly accepted definition. The National Energy Board (NEB) of Canada placed tight original gas-in-place at between 89 and 1,500 Tcf in 1999. The Canadian Association of Petroleum Producers (CAPP) indicates that, more recently, the National Energy Board estimated that Canada has 300 Tcf of tight gas-in-place. Although the figures vary significantly among different estimators, the pervasive opinion among experts is that there are significant volumes of gas-in-place in Canadian tight gas sands. The estimated volumes of unconventional gas throughout the world are gigantic, as shown in a study presented by Rogner. He estimated tight original gas-in-place (OGIP) at 7,500 Tcf for the entire world. Our preliminary estimates suggest that this figure is conservative. For other unconventional gas sources, the volumes are even higher. The above tight gas volumes are in, at most, 271 of the 937 recognized petroleum provinces in the world. An evaluation of the resources from the remaining provinces would lead to even higher estimates, as has occurred with more conventional hydrocarbon reservoirs.
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Cardium Formation (0.99)
- North America > United States > Wyoming > Wind River Basin (0.98)
Abstract A model is developed for petrophysical evaluation of naturally fractured reservoirs where dip of fractures ranges between zero and 90 degrees, and where fracture tortuosity is greater than 1.0. This results in an intrinsic porosity exponent of the fractures (mf) that is larger than 1.0. The finding has direct application in the evaluation of fractured reservoirs and tight gas sands, where fracture dip can be determined, for example, from image logs. In the past, a fracture-matrix system has been represented by a dual porosity model which can be simulated as a series-resistance network or with the use of effective medium theory. For many cases both approaches provide similar results. The model developed in this study leads to the observation that including fracture dip and tortuosity in the petrophysical analysis can generate significant changes in the dual porosity exponent (m) of the composite system of matrix and fractures. It is concluded that not taking fracture dip and tortuosity into consideration can lead to significant errors in the calculation of water saturation. The use of the model is illustrated with an example. Introduction The petrophysical analysis of fractured and vuggy reservoirs has been an area of interest in the oil and gas industry. In 1962, Towle considered some assumed pore geometries as well as tortuosity, and noticed a variation in the porosity exponent m in Archie's equation ranging from 2.67 to 7.3+ for vuggy reservoirs and values much smaller than 2 for fractured reservoirs. Matrix porosity in Towle's models was equal to zero. Aguilera (1976) introduced a dual porosity model capable of handling matrix and fracture porosity. That research considered 3 different values of Archie's2 porosity exponent: One for the matrix (mb), one for the fractures (mf =1), and one for the composite system of matrix and fractures (m). It was found that as the amount of fracturing increased, the value of m became smaller. Rasmus (1983) and Draxler and Edwards (1984) presented dual porosity models that included potential changes in fracture tortuosity and the porosity exponent of the fractures (mf). The models are useful but must be used carefully as they result incorrectly in values of m > mb as the total porosity increases. Serra et al. developed a graph of the porosity exponent m vs. total porosity for both fractured reservoirs and reservoirs with non-connected vugs. The graph is useful but must be employed carefully as it can lead to significant errors for certain combinations of matrix and non-connected vug porosities (Aguilera and Aguilera). The main problem with the graph is that Serra's matrix porosity is attached to the bulk volume of the "composite system". More appropriate equations should include matrix porosity (รb) that is attached to the bulk volume of the "matrix system" (Aguilera, 1995). Aguilera and Aguilera published rigorous equations for dual porosity systems that were shown to be valid for all combinations of matrix and fractures or matrix and nonconnected vugs. The non-connected vugs and matrix equations were validated using core data published by Lucia.
- North America > United States (1.00)
- Europe (0.68)
Abstract As part of the activities of the Conoco Phillips Chair in Tight Gas Engineering in the Chemical and Petroleum Engineering Department at the University of Calgary, a comprehensive literature review has been conducted that has led to our understanding of the current status on the study of tight gas sand formations. This paper presents the results of that work concentrating initially on Canadian and U.S. tight gas sands. Next, we will examine these types of formations throughout the world. The resource base of tight gas sands is estimated to be between 90 and 1500 trillion cubic feet in Canada. The resource base around the world has been estimated at some 7500 trillion cubic feet. The literature survey discussed in this paper is the basis for the mission-oriented research on tight gas reservoirs conducted at the University of Calgary. This research looks at refining the resource base and recoveries from tight gas in Canada and finding economic means of extracting as much of this gas as possible. The planned research program will be presented. It is expected that the research program will result in the delivery of highly qualified professionals, with significant knowledge of tight gas formations, needed by industry and research organizations. In addition, it is likely that the research results will prove to be of value in other parts of the world, and will be exportable, creating business opportunities for Canadian companies. Evaluating the current status of geologic models, reservoir characterization, recovery and production technologies currently available for these types of formations is the first step in the effort to reach the final goal: finding economic means of producing as much of this gas as possible. Introduction Tight gas production is not reported in Canada. However, the interest in this resource is growing significantly. For example, a quick search in the SPE website using the words "tight sands" resulted in 5842 publications as of March 14, 2007. Obviously our goal in this survey paper is not to list everything that has been published in the literature but to highlight what we consider key issues in the evaluation and commercialization of tight gas sand production. Tight gas sands are part of what is usually known as unconventional gas which also includes coal bed methane, shale gas and natural gas hydrates. Tight gas sands have been defined in different ways by different organizations but a unique definition has proven elusive. The original definition dates back to the U.S. Gas Policy Act of 1978 that required in-situ gas permeability to be equal to or less than 0.1 md for the reservoir to qualify as a tight gas formation. At present this is probably the most commonly accepted definition. A second U.S. legal definition indicates that in a tight reservoir an average sustained un-stimulated initial gas rate is less than the maximum specified for a given depth class. However, it is important to understand that, although convenient, not only permeability and/or depth play a role in gas production from tight gas reservoirs.
- North America > United States > Colorado (1.00)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.45)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.93)
- North America > United States > Wyoming > Sand Wash Basin (0.99)
- North America > United States > Wyoming > Green River Basin (0.99)
- North America > United States > Utah > Sand Wash Basin (0.99)
- (22 more...)
Abstract The integration of capillary pressures and Pickett plots has been shown recently to be a useful approach for determining flow units. The present study extends the method to the case of naturally fractured reservoirs by preparing Pickett plots for only the matrix. This requires calculation of matrix porosities and true resistivities for the matrix. By placing pore throat apertures, capillary pressures and heights above the free water table on Pickett plots, it is possible to generate matrix flow units and to estimate if the matrix will contribute to production. Pattern recognition is the key to success with this approach. Two examples are presented. If total porosities and resistivities of the composite system are used on a Pickett plot when the partitioning coefficient (v) is constant, then the usual straight lines for fixed values of water saturation are not obtained. In this case, the Pickett plot results in downward concave lines. Not recognizing this effect might lead to significant errors in the calculation of water saturation. Introduction Pickett plots have long been recognized as very useful in log interpretation. In Pickett's method, a resistivity index, I, and water saturation, Sw, are calculated from log-log crossplots of porosity vs. true resistivity (in some cases apparent resistivity, or resistivity as affected by a shale group, Ash). The Pickett plot has been extended throughout the years to include many situations of practical importance. For example, Aguilera demonstrated that Pickett plots could be used for evaluating naturally fractured reservoirs. In these formations, the value of the porosity exponent was shown to be smaller than usual. Sanyal and Ellithorpe and Greengold have shown that a Pickett plot should result in a straight line with a slope equal to (n - m) for intervals at irreducible water saturation. Aguilera extended the Pickett plot to the analysis of laminar, dispersed, and total shale models. In this approach, the resistivity included in the plot is affected by a shale group, Ash, whose value depends on the type of shaly model being used. Aguilera showed that all equations for evaluation of shaly formations published in the literature, no matter how long they are, become Sw = Ish. He further showed that a Pickett plot for shaly formations should result in a straight line with a slope equal to (n - m) for intervals at irreducible water saturation. Aguilera demonstrated that a log-log crossplot of Rt vs. effective porosity, as determined from neutron and density logs, minus free fluid porosity, as determined from a nuclear magnetic log, should result in a straight line with a negative slope equal to the water saturation exponent, n, for intervals that are at irreducible water saturation. Extrapolation of the straight line to 100% porosity yields the product aRw. Gas intervals plot above the straight line. Intervals with movable water plot below the straight line. In the same paper, Aguilera showed that a Pickett plot should result in a straight line for intervals of constant permeability at irreducible water saturation.
- North America > Canada > Alberta (0.28)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.65)
- North America > United States > Colorado > Spindle Field (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.97)
Summary This paper shows how to construct lines of constant capillary pressure, process speed, pore-throat aperture, and height above the free water table on a Pickett plot. The integration of these properties allows the determination of flow units and reservoir containers and illustrates the important link between geology, petrophysics, and reservoir engineering. The concept of flow (or hydraulic) units and reservoir containers has been used in the oil industry with a good deal of success during the past few years. The process or delivery speed k/f can be used in many instances to define a flow unit. Correlation of flow units between wells helps to establish reservoir containers and forecast reservoir performance. We show that a Pickett crossplot of effective porosity vs. true resistivity should result in parallel straight lines for intervals with constant process speed k/f. The slope of the straight lines is related to the porosity exponent m, the water-saturation exponent n, and constants in the absolute permeability equation. From the straight lines, it is possible to determine capillary pressures and pore-throat apertures directly for each flow unit at any water saturation. Pore throats at 65% water saturation compare very well with Winland r35 values. The method has not been published previously in the literature. Building lines of constant k/f allows the display of complete capillary pressure curves on the Pickett plot, including regions that are and are not at irreducible water saturation. Previous empirical methods for determining the absolute permeability of a given interval assume that the water saturation is at irreducible conditions. This paper presents a technique that allows us to estimate absolute permeability even if the interval contains moveable water. The use of this technique is illustrated with previously published data from the Morrow sandstone in the Sorrento field of southeastern Colorado and carbonates from the Mission Canyon formation in the Little Knife field of North Dakota. We conclude that flow units can be determined reliably from the integration within one single log-log graph of Pickett plots, capillary pressures, pore-throat apertures, and Winland r35 values. Introduction Pickett plots have long been recognized as very useful in log interpretation. The Pickett plot has been extended throughout the years to include many situations of practical importance, including naturally fractured reservoirs, shaly formations, reservoirs with irreducible and moveable water, formations with variable permeabilities, and reservoirs with significant variations in pore throat apertures. This paper shows how to determine flow units by incorporating lines of constant process speed k/f on a Pickett plot. A schematic of this approach is shown in Fig. 1, where Pc1 and Pc2 are constant capillary pressures, r1 and r2 are constant pore-aperture radii, and (k/f)1 and (k/f)2 are constant process or delivery speeds. The correlation of flow units between wells helps to define reservoir containers. Theory Well-log signatures, capillary pressures, Winland r35 pore throats, and/or process (or delivery) speed k/f help to define a flow unit. Hartmann and Beaumont have defined a flow unit as a reservoir subdivision characterized by a similar pore type. They define a container as "a reservoir system subdivision consisting of a pore system made up of one or more flow units, which respond as a unit when fluid is withdrawn." The work presented in this paper is based on those definitions. The same parameters mentioned earlier are built on the Pickett plot to facilitate the determination of flow units. Pickett Plot Archie's basic formation evaluation equations can be combined as proposed by Pickett to obtainEquation 1 Eq. 1 indicates that a crossplot of f vs. Rt on log-log coordinates should result in a straight line with a negative slope equal to m for intervals with constant values of aRw, n, and Sw. Archie's equation poses the limitation that it would tend to give unrealistically large values of water saturation in shaly formations. To alleviate the problem, it is better to prepare the Pickett plot using a shale correction (Ash) to the resistivity (Rt), as explained by Aguilera. This is based on the observation that all equations for evaluation of shaly formations published in the literature, no matter how long they are, become Sw=Ish-1/n. Permeability An empirical equation that has been found to give reasonable estimates of permeability throughout the years has the formEquation 2 for the case of a medium-gravity oil. For a dry gas at shallow depth, a constant approximately equal to 79 is used in place of 250. Water saturation in Eq. 2 is at irreducible conditions. The optimum situation is when core data are available and the constants in Eq. 2 can be calibrated to better fit a particular reservoir. In that case, the permeability equation is written as follows:Equation 3 Eq. 3 can be solved for irreducible water saturation Swi and incorporated into Eq. 1 to obtainEquation 4 Eq. 4 indicates that a crossplot of Rt vs. f on log-log coordinates should result in a straight line with a slope equal to (-c3n-m+n/c4) for intervals at irreducible water saturation with constant aRw and constant k/f. Extrapolation of the straight line to 100% porosity yields the product [aRw(c2-n)(k/f)n/c4].
- North America > United States > Texas (0.68)
- North America > United States > Colorado > Cheyenne County (0.34)
- North America > United States > North Dakota > Billings County (0.25)
- Geology > Geological Subdiscipline (0.91)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.71)
- North America > United States > North Dakota > Little Knife Field (0.99)
- North America > United States > Colorado > Spindle Field (0.99)
- North America > United States > Colorado > Sorrento Field (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract The integration of capillary pressures and Pickett plots has been shown recently to be a useful approach for determining flow units. The present study extends the method to the case of naturally fractured reservoirs by preparing Pickett plots for only the matrix. This requires calculation of matrix porosities and true resistivities for the matrix. By placing pore throat apertures, capillary pressures and heights above the free water table on Pickett plots, it is possible to generate matrix flow units and to estimate if the matrix will contribute to production. Pattern recognition is the key to success with this approach. Two examples are presented. Introduction Pickett plots have long been recognized as very useful in log interpretation. In Pickett's method, a resistivity index, I, and water saturation, Sw, are calculated from log-log crossplots of porosity vs. true resistivity (in some cases apparent resistivity, or resistivity as affected by a shale group, Ash), as shown on Figures 1a, 1b, 1c, 1d, 1e and 1f. The Pickett plot has been extended throughout the years to include many situations of practical importance. For example, Aguilera demonstrated that Pickett plots could be used for evaluating naturally fractured reservoirs. In these formations the value of the porosity exponent was shown to be smaller than usual (Figure 1b). Sanyal and Ellithorpe and Greengold have shown that a Pickett plot should result in a straight line with a slope equal to (n - m) for intervals at irreducible water saturation. Aguilera extended the Pickett plot to the analysis of laminar, dispersed and total shale models (Figure 1c). In this approach, the resistivity included in the plot is affected by a shale group, Ash, whose value depends on the type of shaly model being used. Aguilera showed that all equations for evaluation of shaly formations published in the literature, no matter how long they are, become Sw = Ish. He further showed that a Pickett plot for shaly formations should result in a straight line with a slope equal to (n - m) for intervals at irreducible water saturation. Aguilera demonstrated that a log-log crossplot of Rt vs. effective porosity, as determined from neutron and density logs, minus free fluid porosity, as determined from a nuclear magnetic log, should result in a straight line with a negative slope equal to the water saturation exponent, n, for intervals that are at irreducible water saturation (Figure 1d). Extrapolation of the straight line to 100% porosity yields the product aRw. Gas intervals plot above the straight line. Intervals with movable water plot below the straight line. In the same paper, Aguilera showed that a Pickett plot should result in a straight line for intervals of constant permeability at irreducible water saturation (Figure 1e). The same concept has been used successfully by Doveton et al. More recently Aguilera presented techniques for incorporating capillary pressures, pore aperture radii, height above free water table, and Winland r35 values on Pickett plots (Figure 1f). He developed an equation, which compares favorably with Winland r35.
- North America > United States > Texas (0.28)
- North America > Canada > Alberta (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.65)
- Geology > Geological Subdiscipline > Environmental Geology > Hydrogeology (0.46)
- North America > United States > Colorado > Spindle Field (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.97)
Abstract The concept of flow (or hydraulic) units and reservoir containers has been used in the oil industry with a good deal of success during the last few years. The process or delivery speed k/f can be used in many instances to define a flow unit. Correlation of flow units between wells helps to establish reservoirs containers and to forecast reservoir performance. This study shows that a Pickett crossplot of effective porosity vs. true resistivity (in some cases apparent resistivity or true resistivity affected by a shale group) should result in parallel straight lines for intervals with constant process speed k/f. The slope of the straight lines is related to the porosity exponent m, the water saturation exponent n, and constants in the absolute permeability equation. From the straight lines it is possible to determine directly capillary pressures and pore throat apertures for each flow unit at any water saturation. Pore throats at 65% water saturation compare very well with Winland r35 values. The method has not been published previously in the literature. Building lines of constant k/f allows displaying complete capillary pressure curves on the Pickett plot including regions that are and are not at irreducible water saturation. Previous empirical methods for determining absolute permeability of a given interval assume that the water saturation is at irreducible conditions. This paper presents a technique that allows estimating absolute permeability even if the interval contains moveable water. The use of this technique is illustrated with previously published data from the Morrow sandstone in the Sorrento field of Southeastern Colorado and carbonates from the Mission Canyon formation in the Little Knife field of North Dakota. It is concluded that flow units can be determined reliably from the integration within one single log-log graph of Pickett plots, capillary pressures, pore throat apertures and Winland r35 values. The correlation of the flow units between wells leads to the definition of reservoir containers. Introduction Pickett plots (Figure 1a, 1966, 1973) have long been recognized as very useful in log interpretation. In Pickett's method, a resistivity index, I, and water saturation, Sw, are calculated from log-log crossplots of porosity vs. true resistivity (in some cases apparent resistivity, or resistivity as affected by a shale group, Ash), as shown on Figures 1a, 1b, 1c, 1d, 1e and 1f. The Pickett plot has been extended throughout the years to include many situations of practical importance. For example, Aguilera (1974, 1976) demonstrated that Pickett plots could be used for evaluating naturally fractured reservoirs. In these formations the value of the porosity exponent was shown to be smaller than usual (Figure 1b). Sanyal and Ellithorpe (1978) and Greengold (1986) have shown that a Pickett plot should result in a straight line with a slope equal to (n - m) for intervals at irreducible water saturation.
- North America > United States > Texas (0.93)
- North America > United States > Colorado (0.87)
- North America > United States > North Dakota > Billings County (0.24)
- North America > United States > North Dakota > Little Knife Field (0.99)
- North America > United States > Colorado > Spindle Field (0.99)
- North America > United States > Colorado > Sorrento Field (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Calculations of water saturation were carried out for the A Sand of the Bridger Lake Field using techniques based on:capillary pressure measurements, old well logs and old conventional interpretation charts, and cross plot and pattern recognition. It was found that approaches (1) and (3) provided very close results for average water saturations (31.0 and 30.7%). Calculations using method (2) gave misleading results (65 and 100%). It is concluded that techniques based on capillary pressure measurements and cross plot pattern recognition provide reliable values of average water saturation. The former has the major disadvantage of being susceptible to error in the determination of the volumetric midpoint of the reservoir. The latter has the advantage of accounting for water saturations in different zones, which still allow us to determine an average water saturation for the whole sand. It is recommended to exercise special care in the use of conventional "cookbook" interpretation charts and computer programs. The in discriminated use of these charts and programs can result in serious error. Introduction The Bridger Lake Field is located about 95 miles east of Salt Lake City (Utah) at the northern foot of the Uinta Mountains on the extreme south flank of the Green River Basin. The legal location according to Utah regulations is Range 14 East, Township 3 North. Figure 1 shows the location of the Field. The A Sand is located in the lowest part of the Cretaceous Dakota formation. The Dakota formation lies between the Mowry formation and the Morrison formation at an average depth of 6,500 ft. below mean sea level. Core analyses of these zones indicated good oil show with very erratic values of mean permeability. The sand grains are basically light brown, and their size varies from fine to medium. The purpose of this study was to compare the values of water saturation determined from capillary pressure measurements and logs. The former requires knowledge of the geometric mean permeability and the volumetric mid-point of the reservoir. The latter is based on the following relationships: Equation (1) (Available in full paper) Equation (2) (Available in full paper) Equation (3) (Available in full paper) FIGURE 1: Location map of the Bridger Lake Field. (Available in full paper) Water Saturation From Capillary Pressure Measurements For the calculation of the average water saturation, capillary pressure measurements were made on 13 samples for different water saturations as shown in Figures 2, 3, 4, and 5. Table 1 summarizes the properties of these samples. The logarithm of permeability for each sample was plotted against water saturation holding capillary pressure constant. This plot yielded approximate linear trends represented by straight lines in Figure 6. The next step was to calculate geometric mean permeability. This was accomplished by means of the equation: Equation (4) (Available in full paper) FIGURE 2: Capillary pressure curves, samples 171 A, 172 A, and 179 A. (Available in full paper) where kg = geometric mean permeability, millidarcies Fj = frequency of j interval, fractional (ka)j = arithmetic average permeability of logarithmic class interval j n = total number of classified intervals
- North America > United States > Utah > Summit County (0.66)
- North America > United States > Utah > Salt Lake County > Salt Lake City (0.24)
- North America > United States > Wyoming > Green River Basin (0.99)
- North America > United States > Wyoming > Baxter Basin > Morrison Formation (0.99)
- North America > United States > Utah > Green River Basin (0.99)
- (3 more...)