Determinations of carbon dioxide minimum miscibility pressures (MMP) using a slim-tube apparatus were compared with those using a rising-bubble apparatus (RBA). MMPs were determined for 12 different oils, with gravities varying from 34 to 51 °API. The results were found to compare very well when using a specific criterion for the slim-tube MMP. Although the slim-tube method is often referred to as the industry standard, there is no standard design, no standard operating procedure, and no standard criterion for determining MMPs with the slim tube. It is shown that the RBA is faster and more reliable than the slim tube for determining MMP. Bubble behavior is described for both the vaporizing and condensing gas processes.

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Summary. The Hall plot was originally used to analyze water-injection wells. This paper demonstrates that the Hall plot can also be used to analyze injection of polymer solutions. In particular, it is possible to determine the in-situ and residual resistance factors of a polymer solution from the Hall plot. The analysis methods developed are used to examine two field injection tests and one hypothetical example. The analytical results are verified with a reservoir simulator. Introduction Polymer floods, micellar/polymer floods, and injectivity- or productivity-profile-modification treatments are the most common applications of polymer solutions. The interpretation of injection pressures and rates associated with polymer solution injection is important to the efficient application of the solutions. The Hall plot is a useful tool for evaluating performance of injection wells. The Hall plot was originally developed for single-phase, steady-state, radial flow of Newtonian liquids. Since the advent of polymer and micellar solutions for EOR, it has also been applied to the injection of these solutions. Moffitt and Menzie used the Hall plot to evaluate injection of polymer solutions but did not verify the validity of the Hall plot for this application. This paper verifies the validity of the Hall plot for evaluating polymer solution injection. Because of the complex nature of polymer solution flow through porous media, exact analytical solutions are generally not possible. However, some relatively simple approximate analytical solutions can be developed. To verify the analytical solutions for polymer solution injection, a two-phase, radial, numerical reservoir simulator was developed. The simulator is designed to consider the more important phenomena and effects that occur when polyacrylamide or polyacrylamide polymer solutions are injected into porous media. The simulator has the following characteristics: slightly compressible flow, two-phase flow, non-Newtonian rheology, adsorption/retention with permeability reduction, concentration effects, skin, and wellbore storage. It was used to history match two field injectivity data sets. Development of the Hall Plot The Hall plot was originally proposed to analyze the performance of waterflood injection wells. Hail simply used Darcy's law for single-phase, steady-state, Newtonian flow of a well centered in a circular reservoir:(1) Hall integrated both sides with respect to time to obtain (2) Separating the integral of Eq. 2, Hall then rearranged to obtain (3) The relation between surface and bottomhole pressures for steady-state vertical flow is given by (4) Hall substituted Eq. 4 into Eq. 3 to arrive at (5) Hall simply dropped the second term on the right side of Eq. 5 and plotted the integral of wellhead pressures with respect to time vs. cumulative injection, which came to be known as the "Hall plot." By plotting in this format, Hall observed that if an injection well was stimulated, the slope decreased, and if a well was damaged, the slope increased. While Hall's conclusions regarding changes in slope are valid, the second term on the right side of Eq. 5 is often not negligible in comparison with the other terms and therefore usually cannot be dropped. In industry applications, the Hall integrals dt and f frequently are used. The slopes calculated from these integrals should not be used for quantitative calculations unless a correction procedure is applied. Fig. 1 is a Hall plot based on the data for Well A, where the integral dt has been plotted vs. cumulative injection. Several changes in slope can be seen on the plot, but there has been no change in transmissibility or skin. The changes in slope are caused by changes in rate, which occur because the integraldt has been neglected. Fig. 2 is a Hall plot based on data for Well C. The three most common forms of the Hall integral have been plotted for the same data. For each integration method, the slopes of the curves are quite different. Injection data must be plotted in the form of Eq. 2 to make valid quantitative calculations; i.e., cumulative injection should be plotted vs. (Pwf-pe)dt. The slope of the Hall plot from Eq. 2 is then given by(6) Eq. 6 will not be appropriate when multiple fluid banks with significantly different properties exist in the reservoir. Advantages and Disadvantages The Hall plot is a steady-state analysis method, whereas falloff tests, injection tests, and type-curve analysis are transient methods. Transient pressure analysis methods determine the reservoir properties at essentially one point in time. The Hall plot is a continuous monitoring method; i.e., reservoir properties are measured over a period of weeks and months. The Hall plot, therefore, can help identify changes in injection characteristics that occur over an extended period. Hall's method has several advantages. Integrating the pressure data with the Hall integral [ (pwf-pe)dt] has a smoothing effect on the data. Data acquisition for the Hall plot is inexpensive because only the recording of cumulative injection and surface pressures is required. SPERE P. 41^

Summary Polymer flooding of fractured reservoirs is common. In water-wet fracturedreservoirs, the primary recovery mechanism may be imbibition. This paperpresents results of an experimental study investigating the effect of polymerson the imbibition process. Two sets of experiments, static and dynamic, wereperformed. The static experiments showed that the amounts of oil ultimatelyrecovered by water and polymer-solution imbibition are practically equal. Therate of oil recovery by the polymer solutions, however, is always less than therate with water. The dynamic experiments consisted of flooding oil-saturatedfractured cores through the fractures. The oil-recover behavior in theseexperiments depended not only on the rate of injected fluid imbibition from thefracture into the matrix blocks, but also on the operating injection rate andthe efficiency of the injected fluid in displacing the oil in the fracture. Introduction Excessive water channeling through the high-permeability fracture system ofthe Spraberry field prompted Atlantic Refining Co. researchers to explorewater-imbibition displacement as a production mechanism for recovering oil. Since then, theoretical work and field experience have supported this idea andhave found that water imbibition is not only important, but could be the mainmechanism for recovering oil from fractured reservoirs. In water-imbibition displacement, water flows by capillary forces from thefractures into the oil-saturated, water-wet matrix blocks, causing oil to flowcountercurrently from the matrix blocks into the fractures. This oil then isdisplaced by oncoming water through the fracture system to the productionwells. Polymer flooding is known to offer a better alternative over existingwaterflooding in conventional reservoirs if the mobility ratios are unfavorableor if significant permeability variations exist. This knowledge also makespolymer flooding an attractive process to apply in fractured reservoirs. Polymer flooding would offer better mobility control in the displacement of oilin these reservoirs. Through polymer retention, polymer flooding also couldredirect the flow of injected polymer solution polymer flooding also couldredirect the flow of injected polymer solution from one fracture to another andfrom the fractures into the matrix blocks. Lastly, at any injection rate, polymer flooding would generate more viscous forces than waterfloodingperformed at the same rate. Problem Problem Polymer flooding in fractured reservoirs, or in anyheterogeneous Polymer flooding in fractured reservoirs, or in any heterogeneousreservoir, offers some advantages but also raises some senous questions thathave not been investigated:(1)do polymer macromolecules retard the imbibition process;(2)if so, will the polymer concentration, polymer molecule size, andpolymer-solution salt content play a role in this effect; and(3)if polymerretards the play a role in this effect; and(3)if polymer retards theimbibition process, will the extra viscous forces generated and the bettermobility control of the polymer flooding make up for the imbibitionretardation? The purpose of this study was to provide some answers to these questions, Two sets of experiments were performed: static and dynamic. The staticimbibition experiments involved oil displacement from the matrix blocks infractured reservoirs by imbibition into the fracture system. The dynamicimbibition experiments involved both displacement from the core by imbibitionand displacement of oil by the oncoming injected fluid through the fracturesystem. A literature search found no papers dealing with the effect of polymers onthe imbibition process. Only an example of the data collected polymers on theimbibition process. Only an example of the data collected is illustrated in thefigures. The complete data set is available elsewhere. Experimental Fluids and Cores The four different brines (0, 1,000, 5,000, and 10,000 ppm NACl) used inthis work were all synthetic and prepared in the laboratory. Four oil typeswere used. The first three were synthetic and prepared in the laboratory. Type1 is a 100% n-decane with a viscosity of 0.95 cp. Type 2 is prepared by mixing25 vol% n-decane with 75 vol% mineral oil with a viscosity of 6.5 cp. Type 3 isa 100% mineral oil with a viscosity of 18.3 cp. Type 4 is a natural crude oilwith a viscosity of 143.9 cp. All viscosities were measured at roomtemperature. Partially hydrolyzed polyacrylamide (PHPA) polymers of three differentmolecular weights were used. Polymer L is a low-molecular-weight (2 × 10), Mis a medium-molecular-weight (5 × 10), and H is a high-molecular-weight (11 ×10) polymer. These polymers were used to prepare solutions differing inmolecular weight, concentration, and salt content. Each solution was given acode name accordingly. For example, Solution L460,0 is Polymer L (low molecularweight) of 460-ppm polymer concentration and 0-ppm salt content. All theexperimental fluids underwent physical property measurements. Detailed tablesand graphs of these property measurements. Detailed tables and graphs of thesemeasurements are available elsewhere. 10 The interfacial tension (IFT)measurements showed that the polymer molecular weight or concentration haslittle to no effect on the values measured between the polymer solutions andcertain oils. The salt content of the solu-tions, on the other hand, was foundto have some effect on the measured values. The measured IFT's increasedslightly with the solutions' salt content. Berea sandstone cores with porosities ranging between 0.22 and 0.23 wereused in these experiments. The permeability ranged between 400 and 840 md. Thegeneral dimensions of the cores were 2 in. in diameter and 51/2 in. in length. Ref. 10 gives exact core dimensions and properties. The cores were fired tostabilize any clay materials present in the rock pore space and to achievestrong water-wet conditions. Treating the cores so that they were stronglywater-wet allowed comparison of tests performed with different cores withoutcore wettability being a strong factor. To avoid plugging, the polymers used in this study had molecular sizes lessthan 30 % of the average pore-throat size of the porous medium. The average pore-throat size of the porous medium was determined to be 13um. The size of the polymer random coil can be expressed in terms ofstatistical parameters such as the root-mean-square distance between its ends,(r 2) 1/2, and its radius of gyration and the root-mean-square distance of theelements of the chain from its center of gravity, (S 2) 1/2. Both thesestatistical parameters can be estimated with the polymer viscosity measurementsand the Polymer's molecular weight and configuration. Polymer's molecularweight and configuration. The hydrodynamic radius of gyration of Polymers L, M, and H in deionized water was found to be 0.237, 0.344, and 0.504 um, respectively. The statistical parameter, end-to-end distance of Polymers L, M, and H molecular coils, was found to be 1.419, 2.066. Polymers L, M, and Hmolecular coils, was found to be 1.419, 2.066. and 3.024 Am, respectively. These values suggest that all Polymers L, M, and H can be applied in thiswork's porous media without plugging problems.

An equation has been derived for use in calculating the sand face pressure of flowing gas wells in which the variation of the compressibility factor of the gas with pressure is taken into consideration. This variation due to compressibility has been put into both graphical and tabular form. Comparison of calculated results with field measured results were made on 20 dry gas wells from a given field and 11 distillate wells from different fields. The agreement between calculated and observed results is good.In addition to their use in the calculation of sandface pressures of flowing wells, the factors can be used in the direct calculation of the static bottom hole pressure of gas wells, the capacity of gas transmission lines, and in the calculation of the theoretical isothermal horEepower necessary to compress a natural gas. Examples demonstrating the use of various equations are given.