Thermal Stability of Surfactants for Reservoir Application (includes associated papers 11323 and 11597 )

1982 ◽  
Vol 22 (05) ◽  
pp. 722-730 ◽  
Author(s):  
L.L. Handy ◽  
J.O. Amaefule ◽  
V.M. Ziegler ◽  
I. Ershaghi
Keyword(s):  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Half Life ◽  
Elevated Temperatures ◽  
Effect Of Temperature ◽  
Residual Oil ◽  
Chemical Additives ◽  
Thermal Stabilities ◽  
Oil Saturation ◽  
Residual Oil Saturation

Abstract The thermal stabilities of several sulfonate surfactantsand one nonionic surfactant have been evaluated. Thedecomposition reactions have been observed to followfirst-order kinetics. Consequently, a quantitativemeasure of a surfactant's stability at a given temperatureis its half-life. Furthermore, the activation energy can beestimated from rate data obtained at two or moretemperatures. This permits limited extrapolation of theobserved decomposition rates to lower temperatures forwhich the rates are too low for convenient measurement.The surfactants we investigated are being considered forsteamflood additives and need to be relatively stable atsteam temperatures.None of the surfactants evaluated to date has therequisite stability for use in steamfloods. The most stablepetroleum sulfonate we have investigated has a half-lifeof 11 days at 180 degrees C (356 degrees F). With this half-life, substantial overdosing would be required tomaintain the minimum effective surfactant concentration forthe life of the flood. On the other hand, the estimatedhalflife for this surfactant at 93 degrees C (200 degrees F), calculated by extrapolation, would be 33 years.Tests with the nonionic surfactant, nonylphenoxy-polyethanol, have shown this material to have a very short half-life at steam temperatures, but it doesappear to be more stable at concentrations greater than thecritical micelle concentration(CMC). In limited tests, the sulfonates showed increased stability in the presenceof a 2-M salt solution. Introduction Several chemical additives are being considered for usewith steamfloods to reduce the producing steam/oilratios and to increase oil recovery from steam projects.The emphasis to date has been on inorganic chemicaladditives. Sodium hydroxide has been used in the fieldwithout success. We have been investigating thepotential benefits of using organic surfactants. This hasbeen discusssed recently by Brown et al. and byGopalakrishnan et al. The surfactant would be introducedinto the reservoir along, with the steam at the beginning ofthe steamflood and, possibly, intermittently during the floodprocess. The surfactant would be injected in diluteconcentrations and would be expected to travel in thatportion of the reservoir being flooded by hot water.Although the residual oil saturation in the steam zone has been observed to be very low, residual saturation in thehot water portion of the steamflood is expected to be thenormal waterflood residual. A surfactant in the hot watermay reduce this residual oil saturation. A synergistic effect could be observed between the surfactant and thetemperature to give better performance than would beobserved for a surfactant flood at normal reservoirtemperatures.For the process to work as anticipated, the surfactantmust move in the heated portion of the reservoir, and it must be sufficiently stable at elevated temperatures tofunction as an effective recovery agent for the life of theflood. Therefore, two aspects of the process are beingstudied simultaneously. One of these is the effect oftemperature on adsorption of the surfactants, and theother is the effect of heat on the stability of thesurfactants. The effect of temperature on adsorption will bediscussed in a later paper. The objective of this paper isto discuss the experimental evaluation of the thermalstability of some surfactant types that could haveapplication in reservoir floods. The effect of temperatureon adsorption and stability of these surfactants also willbe important in micellar floods at higher reservoirtemperatures. Experimental Procedures Several anionic and noninoic surfactants were selectedfor evaluation. SPEJ P. 722^

Effect of Temperature on Surfactant Adsorption in Porous Media

1981 ◽  
Vol 21 (02) ◽  
pp. 218-228 ◽  
Author(s):  
Victor M. Ziegler ◽  
Lyman L. Handy
Keyword(s):  
Crude Oil ◽  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Elevated Temperatures ◽  
Steam Injection ◽  
Mineral Dissolution ◽  
Hot Water ◽  
Effect Of Temperature ◽  
Surfactant Adsorption ◽  
Thermal Stabilities

Abstract The effect of temperature on the adsorption of asulfonate surfactant and a nonionic surfactant ontocrushed Berea sandstone was studied by both staticand dynamic techniques. Static experiments were conducted over atemperature range from 25 to 95 degrees C to definetemperature-sensitive rock/surfactant systems and toestablish the shape of the equilibrium isotherm.Dynamic experiments served to reinforce the findingsof the static tests and extended the temperature rangefor sorption to 80 degrees C. This is a typicalsteamflood temperature. A mathematical model thatincorporates the mass transport, thermal degradation, and rate-dependent adsorption of the surfactantrepresented these dynamic results. The model wasused to determine the effect of temperature on the sorption rate constants. Mineral dissolution at elevated temperatures hasbeen found to cause precipitation of the sulfonate.Adsorption of the nonionic surfactant decreased withan increase in temperature at low concentrations, whereas the opposite was true at high concentrations.This has favorable implications for a low-concentration injection scheme. When performingstatic adsorption experiments, care had to be takenbecause of the poor thermal stability of the nonionic surfactant. Introduction Injection of surfactants concurrently with steam intooil-bearing reservoirs has been proposed recentlyto improve the recovery efficiency of the steam-driveprocess. From the behavior of chemical additivespreviously used in steamfloods, it is anticipated thatthe injected surfactant will travel through thatportion of the reservoir being flooded by hot water. Oil recovery can be increased if the surfactanteffectively reduces the residual oil saturation withinthis hot-water zone. For concurrent surfactant/steam injection to be technically attractive, a synergisticeffect between the surfactant and temperature isdesired. In our concept of the process, the surfactant mustmove in the heated portion of the reservoir and beable to function as an effective recovery agent atelevated temperatures for prolonged periods of time.Surfactant screening, therefore, requires thisinformation:surfactant stability under steamfloodconditions,temperature effects on the interfacial tension (IFT) between the reservoir oil and aqueoussurfactant,an evaluation of the effect oftemperature on surfactant flood performance, andthe effect of temperature on surfactant adsorption atthe water/solid interface. Handy et al. reported the thermal stabilities ofseveral classes of surfactants. Hill et al. showed thattemperature can have a dramatic effect in reducingthe IFT between crude oil and an aqueous sulfonatesystem. Handy et al. saw a similar temperatureeffect for a nonionic-surfactant/crude-oil system. Itappears, therefore, that the required synergismbetween temperature and surface activity necessaryfor concurrent surfactant/steam injection exists.Surfactant core floods are required to evaluate theeffect of temperature on oil recovery. Finally, toensure that the surfactant moves in the heatedportion of the reservoir, it is necessary to determinethe effect of temperature on adsorption. SPEJ P. 218^

Relationship between Residual Saturations and Wettability using Pore-Network Modeling

2021 ◽  
Author(s):  
Prakash Purswani ◽  
Russell T. Johns ◽  
Zuleima T. Karpyn
Keyword(s):  
Contact Angle ◽  
Oil Recovery ◽  
Network Modeling ◽  
Pore Network ◽  
Residual Oil ◽  
Residual Saturation ◽  
Oil Saturation ◽  
Pore Network Modeling ◽  
Residual Oil Saturation ◽  
Eor Processes

Abstract The relationship between residual saturation and wettability is critical for modeling enhanced oil recovery (EOR) processes. The wetting state of a core is often quantified through Amott indices, which are estimated from the ratio of the saturation fraction that flows spontaneously to the total saturation change that occurs due to spontaneous flow and forced injection. Coreflooding experiments have shown that residual oil saturation trends against wettability indices typically show a minimum around mixed-wet conditions. Amott indices, however, provides an average measure of wettability (contact angle), which are intrinsically dependent on a variety of factors such as the initial oil saturation, aging conditions, etc. Thus, the use of Amott indices could potentially cloud the observed trends of residual saturation with wettability. Using pore network modeling (PNM), we show that residual oil saturation varies monotonically with the contact angle, which is a direct measure of wettability. That is, for fixed initial oil saturation, the residual oil saturation decreases monotonically as the reservoir becomes more water-wet (decreasing contact angle). Further, calculation of Amott indices for the PNM data sets show that a plot of the residual oil saturation versus Amott indices also shows this monotonic trend, but only if the initial oil saturation is kept fixed. Thus, for the cases presented here, we show that there is no minimum residual saturation at mixed-wet conditions as wettability changes. This can have important implications for low salinity waterflooding or other EOR processes where wettability is altered.

scholarly journals SURFACTANT-POLYMER FLOODING PERFORMANCE IN HETEROGENEOUS TWO-LAYERED POROUS MEDIA

2011 ◽  
Vol 12 (1) ◽  
pp. 31-38 ◽  
Author(s):  
Muhammad Taufiq Fathaddin ◽  
Asri Nugrahanti ◽  
Putri Nurizatulshira Buang ◽  
Khaled Abdalla Elraies
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Reservoir Heterogeneity ◽  
Residual Oil Saturation ◽  
Layered Porous Media ◽  
Multiple Porosity

In this paper, simulation study was conducted to investigate the effect of spatial heterogeneity of multiple porosity fields on oil recovery, residual oil and microemulsion saturation. The generated porosity fields were applied into UTCHEM for simulating surfactant-polymer flooding in heterogeneous two-layered porous media. From the analysis, surfactant-polymer flooding was more sensitive than water flooding to the spatial distribution of multiple porosity fields. Residual oil saturation in upper and lower layers after water and polymer flooding was about the same with the reservoir heterogeneity. On the other hand, residual oil saturation in the two layers after surfactant-polymer flooding became more unequal as surfactant concentration increased. Surfactant-polymer flooding had higher oil recovery than water and polymer flooding within the range studied. The variation of oil recovery due to the reservoir heterogeneity was under 9.2%.

Laboratory Tests on Heavy Oil Recovery by Steam Injection

1983 ◽  
Vol 23 (03) ◽  
pp. 417-426 ◽  
Author(s):  
Philip J. Closmann ◽  
Richard D. Seba
Keyword(s):  
Pore Size ◽  
Heat Loss ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Steam Injection ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
The Core ◽  
Unconsolidated Sand

Abstract This paper presents results of laboratory experiments conducted to determine the effect of various parameters on residual oil saturation from steamdrives of heavy-oil reservoirs. These experiments indicated that remaining oil saturation, both at steam breakthrough and after passage of several PV of steam, is a function of oil/water viscosity ratio at saturated steam conditions. Introduction Considerable attention has been given to thermal techniques for stimulating production of underground hydrocarbons, particularly the more viscous oils production of underground hydrocarbons, particularly the more viscous oils and tars. Steam injection has been studied as one means of heating oil in place, reducing its viscosity, and thus making its displacement easier. place, reducing its viscosity, and thus making its displacement easier. A number of investigators have measured residual oil saturations remaining in the steam zone. Willman et al. also analyzed the steam displacement process to account for the oil recoveries observed. A number of methods have been developed to calculate the size of the steam zone and to predict oil recoveries by application of Buckley-Leverett theory, including the use of numerical simulation. The work described here was devoted to an experimental determination of oil recovery by steam injection in linear systems. The experiments were unscaled as far as fluid flow rates, gravity forces, and heat losses were concerned. Part of the study was to determine recoveries of naturally occurring very viscous tars in a suite of cores containing their original oil saturation. The cores numbered 95, 140, and 143 are a part of this group. Heterogeneities in these cores, however, led to the extension of the work to more uniform systems, such as sandpacks and Dalton sandstone cores. Our interest was in obtaining an overall view of important variables that affected recovery. In particular, because of the significant effect of steam distillation, most of the oils used in this study were chosen to avoid this factor. We also studied the effect of pore size on the residual oil saturation. As part of this work, we investigated the effect of the amount of water flushed through the system ahead of the steam front in several ways:the production rate was varied by a factor of four,the initial oil saturation was varied by a factor of two, andthe rate of heat loss was varied by removing the heat insulation from the flow system. Description of Apparatus and Experimental Technique Two types of systems were studied: unconsolidated sand and consolidated sandstone. The former type was provided by packing a section of pipe with 50–70 mesh Ottawa sand. Most runs on this type of system were in an 18-in. (45.72-cm) section of 1 1/2 -in. (3.8 1 -cm) diameter pipe, although runs on 6-in. (15.24-cm) and 5-ft (152.4-cm) lengths were also included. Consolidated cores 9 to 13 in. (22.86 to 33.02 cm) long and approximately 2 1/4 in. (5.72 cm) in diameter were sealed in a piece of metal pipe by means of an Epon/sand mixture. A photograph of two 9-in. (22.86-cm) consolidated natural cores (marked 95 and 143) from southwest Missouri, containing original oil, is shown as Fig. 1. In all steamdrive runs, the core was thermally insulated to reduce heat loss, unless the effect of heat loss was specifically being studied. Flow was usually horizontal except for the runs in which the effects of flushing water volume and of unconsolidated-sand pore size were examined. Micalex end pieces were used on the inlet end in initial experiments with consolidated cores to reduce heat leakage from the steam line to the metal jacket on the outside of the core. During most runs, however, the entire input assembly eventually became hot. SPEJ p. 417

The Effect of Temperature on Relative and Absolute Permeability of Sandstones

1975 ◽  
Vol 15 (05) ◽  
pp. 376-384 ◽  
Author(s):  
R.M. Weinbrandt ◽  
H.J. Ramey ◽  
F.J. Casse
Keyword(s):  
Relative Permeability ◽  
Temperature Increase ◽  
Absolute Permeability ◽  
Effect Of Temperature ◽  
Residual Oil ◽  
Relative Permeabilities ◽  
Permeability Ratio ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
The Individual

MEMBERS SPE-AIME Abstract Equipment was constructed to perform dynamic displacement experiments on small core samples under conditions of elevated temperature. Oil-water flowing fraction and pressure drop were recorded continuously for calculation of both the relative permeability ratio and the individual relative permeability ratio and the individual relative permeabilities. Imbibition relative permeabilities permeabilities. Imbibition relative permeabilities were measured for five samples of Boise sandstone at room temperature and at 175deg.F. The fluids used were distilled water and a white mineral oil. The effect of temperature on absolute permeability was investigated for six Boise sandstone samples and two Berea sandstone samples. Results for all samples were similar. The irreducible water saturation increased significantly, while the residual oil saturation decreased significantly with temperature increase. The individual relative permeability to oil increased for all water saturations below the room-temperature residual oil saturation, but the relative permeability to water at flood-out increased with permeability to water at flood-out increased with temperature increase. Absolute permeability decreased with temperature increase. Introduction Test environment is generally acknowledged to have a significant effect on measurement of relative permeability. The environment consists not only permeability. The environment consists not only of the temperature and pressure, but also of the fluids used and the core condition. Several workers have used the approach of completely simulating the reservoir conditions in the laboratory experiment. Such methods are termed "restored state." Restored state data are generally different from "room condition" data; since several variables are involved, it is difficult to determine the importance of each variable. Another approach used attributes the changes in relative permeability to changes in the rock-fluid interaction or wettability. Wettability, however, depends on many variables. Specifically, wettability depends on the composition of the rock surface, the composition of the fluids, the saturation history of the rock surface, and the temperature and pressure of the system. The purpose of this study is to isolate temperature as a variable in the relative permeability of a given rock-fluid system. Work on isolation of temperature as a variable in relative permeability has been conducted since the early 1960s. Edmondsons established results in 1965 for a Berea sandstone core using both water/refined oil and water/crude oil as fluid pairs. He showed a change in the relative permeability ratio accompanied by a decrease in the residual oil saturation with temperature increase. Edmondson showed no data for water saturations below 40 percent, and his curves show considerable scatter in the middle saturation ranges. Edmondson's work was the only study to use consolidated cores to investigate the effect of temperature on relative permeability measurements. Poston et al. presented waterflood data for sand packs containing 80-, 99-, a nd 600-cp oil, and packs containing 80-, 99-, a nd 600-cp oil, and observed an increase in the individual relative permeabilities with temperature increase. The permeabilities with temperature increase. The increase in the oil and the water permeability was accompanied by an increase in irreducible water saturation and a decrease in the residual oil saturation with temperature increase. Poston et al. was the only work to present individual oil and water permeability. Davidsons presented results for displacement of No. 15 white oil from a sand pack by distilled water, steam, or nitrogen. However, he found little permeability-ratio dependence in the middle permeability-ratio dependence in the middle saturation ranges. Davidson, too, found a decrease in the residual oil saturation with temperature increase, but he did not include data on irreducible water saturation. SPEJ P. 376

scholarly journals Modeling Wettability Variation during Long-Term Water Flooding

2015 ◽  
Vol 2015 ◽  
pp. 1-11 ◽  
Author(s):  
Renyi Cao ◽  
Changwei Sun ◽  
Y. Zee Ma
Keyword(s):  
Oil Recovery ◽  
Water Flooding ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Polar Substance ◽  
Oil Displacement Efficiency ◽  
Reservoir Wettability

Surface property of rock affects oil recovery during water flooding. Oil-wet polar substances adsorbed on the surface of the rock will gradually be desorbed during water flooding, and original reservoir wettability will change towards water-wet, and the change will reduce the residual oil saturation and improve the oil displacement efficiency. However there is a lack of an accurate description of wettability alternation model during long-term water flooding and it will lead to difficulties in history match and unreliable forecasts using reservoir simulators. This paper summarizes the mechanism of wettability variation and characterizes the adsorption of polar substance during long-term water flooding from injecting water or aquifer and relates the residual oil saturation and relative permeability to the polar substance adsorbed on clay and pore volumes of flooding water. A mathematical model is presented to simulate the long-term water flooding and the model is validated with experimental results. The simulation results of long-term water flooding are also discussed.

Peripheral Low Salinity Water Injection Handil Case Study

2021 ◽  
Author(s):  
Julfree Sianturi ◽  
Bayu Setyo Handoko ◽  
Aditya Suardiputra ◽  
Radya Senoputra
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Water Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Abstract Handil Field is a giant mature oil and gas field situated in Mahakam Delta, East Kalimantan Indonesia. Peripheral Low Salinity Water injection was performed since 1978 with an extraordinary result. The paper is intending to describe the success story of this secondary recovery by low salinity water injection application in the peripheral of Handil field main zone, which successfully increased the oil recovery and brought down the remaining oil saturation beyond the theoretical value of residual oil saturation number. Water producer wells were drilled to produce low salinity water from shallow reservoirs 400 - 1000 m depth then it was injected to main zone reservoirs where the main accumulation of oil situated. This low salinity water reacted positively with the rock properties and in-situ fluids which was described as wettability alteration in the reservoir. It is related to initial reservoir condition, connate water saturation, rock physics and connate water salinity. This peripheral scheme then observed having the sweeping effect on top of pressure maintenance due to long period of injection. The field production performance was indicating the important reduction of residual oil saturation in some reservoirs with continuous low salinity water injection. From static Oil in Place calculation, some reservoirs have high current oil recovery up to 80%. This was proved by in situ residual oil saturation measurement which was performed in 2007 and 2011. It was indicating the low residual saturation as low as 8% - 15%. This excellent result was embraced by a progressive development plan, where water flooding with pattern and chemical injection will be performed later on. The continuation of this peripheral injection is in an on-going development with patterns injection which is called water flooding development. An important oil recovery can be achieved with a simple scheme of low salinity injection, performed in a close network injection, where the water treatment is simple yet significant oil gain was recovered. This innovation technique brings more revenue with less investment compared to chemical EOR injection.

Heavy Oil Recovery by Alkaline-Cosolvent-Polymer Flood: A Multi-Scale Research Using CT Imaging

2021 ◽  
Author(s):  
Hang Su ◽  
Fujian Zhou ◽  
Lida Wang ◽  
Chuan Wang ◽  
Lixia Kang ◽  
...  
Keyword(s):  
Computed Tomography ◽  
Ct Scan ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Micro Ct ◽  
Residual Oil ◽  
Micro Computed Tomography ◽  
Total Acid ◽  
Oil Saturation ◽  
Residual Oil Saturation

Abstract For reservoirs containing oil with a high total acid number, alkali-cosolvent-polymer (ACP) flood can potentially increase the oil recovery by its saponification effects. The enhanced oil recovery performance of ACP flood has been studied at core and reservoir scale in detail, however, the effect of ACP flood on residual oil saturation in the swept area still lacks enough research. Medical computed tomography (Medical-CT) scan and micro computed tomography (Micro-CT) scan are used in combination to visualize micro-scale flow and reveal the mechanisms of residual oil reduction during ACP flood. The heterogeneous cores containing two layers of different permeability are used for coreflood experiment to clarify the enhanced oil recovery (EOR) performance of ACP food in heterogeneous reservoirs. The oil saturation is monitored by Medical-CT. Then, two core samples are drilled in each core after flooding and the decrease of residual oil saturation caused by ACP flood is further quantified by Micro-CT imageing. Results show that ACP flood is 14.5% oil recovery higher than alkaline-cosolvent (AC) flood (68.9%) in high permeability layers, 17.9% higher than AC flood (26.3%) in low permeability layers. Compared with AC flood, ACP flood shows a more uniform displacement front, which implies that the injected polymer effectively weakened the viscosity fingering. Moreover, a method that can calculate the ratio of oil-water distribution in each pore is developed to establish the relationship between the residual oil saturation of each pore and its pore size, and reached the conclusion that they follow the power law correlation.

Characterization of Surfactants Using a Scaling Law Interpretation of Coreflood Residual Oil Saturation Profiles

1983 ◽  
Vol 23 (03) ◽  
pp. 511-518
Author(s):  
L.A. Davis ◽  
T.N. Tyler ◽  
D.F. Brost ◽  
H.K. Haskin
Keyword(s):  
Microwave Absorption ◽  
Oil Recovery ◽  
Scaling Law ◽  
Linear Scaling ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Saturation Profiles

Abstract The characterization of surfactant candidates for a given reservoir can be improved by the use of linear coreflood residual-oil-saturation profiles measured along the core after chemical flooding. A surfactant formulation's functional relation of oil recovery to slug size can be calculated from a single coreflood with the assumption of a relaxed scaling law. A volumetric linear scaling approach is developed from laboratory coreflood data. Residual-oil-saturation profiles measured in reservoir material with a microwave absorption instrument support this approximate scaling relation. Analysis of 32 linear surfactant-slug corefloods is presented as additional verification. The limits of this scaling law are defined, with emphasis on the role of mixing and dispersion. The procedure for using saturation profiles to calculate oil recovery as a function of slug size is developed and a test case is presented. A recovery relation derived from a single coreflood saturation profile is compared with that determined by multiple conventional corefloods. Introduction Many techniques and instruments are now available for noninvasive measurement of oil/brine saturations along linear cores during secondary and tertiary displacement experiments, these are reviewed briefly in Ref. 1. The most popular recent method is based on the microwave absorption properties of water. Such saturation- profile measurements provide much more information on a given chemical-flood experiment than can be collected merely from effluent material balance. This abundance of data can be used in two ways: to determine relations that would otherwise have to be developed laboriously from many separate conventional corefloods and to develop predictive capability for estimating surfactant- flood performance in new situations. Both applications are possible as an outgrowth of the concept of volumetric linear scaling for chemical flooding proposed by Parsons and Jones. This relaxed scaling technique is supported by the data of Ref. 6 and a wide variety of conventional and scanned corefloods presented in this work. A process can be defined as volumetrically linearly scalable if the fluid compositions and saturations at any point in the matrix at any time are functions only of the PV of fluids injected relative to that point with respect to the injection point. This can be stated simply for a single slug of surfactant: a given-PV slug of surfactant will produce the same compositions and saturation distributions in a core of any physical shape and size. Moreover, a 0. 10-PV slug injected into a 2-m core will produce the same composition and saturation distribution in the first meter of that core as would be produced over the entire length of a 1-m core that had seen a 0.20-PV slug. This is a trivial-but not an obvious-view of the recovery process. Limitations to this relative-sizing concept are discussed in the following paragraph. SPEJ P. 511^

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