An experimental study of crude oil alteration in reservoir rocks by water washing

~

Pergamon

0146-6380(93)E0002-4

Org. Geochem. Vol. 21, No. 5, pp. 465-479, 1994 Copyright © 1994ElsevierScienceLtd

Printedin GreatBritain.All rightsreserved 0146-6380/94$7.00+ 0.00

An experimental study of crude oil alteration in reservoir rocks by water washing LUNG-CHUAN KUO Conoco Inc., 1000 South Pine, Ponca City, OK 74602-1267, U.S.A. (Received 20 May 1993; returned for revision 16 June 1993; accepted in revised form 6 October 1993)

Abstract--The objective of this research was to establish the effect of water washing on the physical and chemical properties of crude oils. To simulate water washing under reservoir conditions, crude oil was washed in sandstone and limestone cores by as much as 240 liters of a degassed, bacteria-free water over a period of up to 149 days at 90°C (194°F) under a confining pressure of 138 bars (2000 psi) in a flow-through core holder unit. The water-washed oils were recovered by Soxhlet extraction. Compared to the original oils, water-washed oils show lower API gravities, lower concentrations of light aromatic compounds such as phenanthrene and dibenzothiophene, lower metal and sulfur content, lower light paraffins with respect to heavy paraffins and isoprenoids, more negative stable carbon isotopic ratios for the NSO fraction, lower diterpane content relative to triterpane content, lower C27 steranes relative to C30 hopane and 4-methyl sterane, and altered bicyclic alkane and aromatic steroid biomarkers. Oils washed in limestone cores show a more severe reduction in API gravity and loss of aromatics than those in sandstone cores. These changes can be used to discern the effects of water washing from those caused by biodegradation, deasphalting, and maturation of related crude oils. Diterpane, triterpane, and sterane biomarkers are little affected by water washing and therefore can be used to correlate water-washed oils with related, unaltered oils and source rocks and to assess the depositional environments of the source rocks for the water-washed oils. Although these experiments did not produce tarmat, tarmat formation by water washing over geological time cannot be ruled out. The API gravity, sulfur, and metal content of oils may be reduced by water injection. Key words--petroleum alteration, water washing, reservoir geochemistry, biomarkers, tarmat, water injection

INTRODUCTION One of the main objectives of organic geochemical research in petroleum exploration is to determine the quantity, composition, and distribution of hydrocarbons in a given sedimentary basin. The composition of crude oils is controlled by four major factors: (1) organic matter type, (2) maturity of the source rock(s), (3) hydrocarbon migration, and (4) alteration of crude oils after their generation. The effect of post-generative alteration processes on crude oil composition is often significant. For example, biodegraded oils form some of the world's largest hydrocarbon accumulations (Demaison, 1977). Reservoir bitumens, which occur in many major oil fields, may be formed by biodegradation, gas deasphalting, and water washing (Evans et al., 1971). Elevated temperatures in deep reservoirs may cause thermal cracking of liquid hydrocarbons to gases and pyrobitumens (Landes, 1967). The effect of water washing is difficult to discern in crude oils because biodegradation typically occurs with water washing and has a significant effect on oil composition (Milner et al., 1977; C o n n a n , 1984; and references therein). Water washing experiments have been conducted in the absence of reservoir rocks (Bayliss, unpublished work quoted by Milner et al.,

1977; Wayer, 1985; Lafargue and Barker, 1988; Eakin et al., 1990) and in attempts to simulate the alteration of oil spills at the surface of the ocean (Davis and Gibbs, 1975; Farrington, 1980; Albaiges and Cuberes, 1980). The present study was designed to simulate water washing under reservoir conditions without the effects of biodegradation. The experimental product was studied to gain knowledge on the effects of water volume and reservoir lithology on crude oil composition and API gravity.

METHODS Material and setup

The rock cores used in this study were 2" in dia and 3.5" long plugs of the Berea sandstone from the Cleveland Quarries (South Amherst, Ohio) and the Texas Cream limestone from the Texas Quarries (Cedar Park, Tex.). The Berea sandstone contains over 90% quartz with minor kaolinitic clay, feldspars, and calcite (Table 1). The Texas Cream limestone is an oolitic grainstone with patchy, sparry calcite cement. For each experiment (Fig. 1), a core with a pair of end plugs is enclosed in a Viton" sleeve. This core assembly is affixed in the center of a high-pressure 465

466

LUNG-CHUAN Kuo pressure back-pressure ulator temperature

controller V8

water

pressur

tank.

T h e water c o m p o s i t i o n used was 10,000 mg/1 Na, 80 mg/l Ca, 52 mg/l K, 1 2 m g / l Mg, a n d 15,400 mg/l C1 with 500 p p m o f glutaraldehyde as bactericide. The water was p r e p a r e d by dissolving a p p r o p r i a t e quantities o f reagent-grade chlorides in deionized, distilled water. The water was then filtered, degassed, a n d transferred into the water tank. M i s h r i f crude oils from the Southwest F a t e h Field (offshore Dubai) were used for the experiments. The physical a n d chemical properties o f the oils are listed a n d discussed in detail in later sections.

Procedure valve high-pressure reactor' b ~ ~ l i n d e

Fig. 1. A schematic diagram of the experimental setup. Arrowheads indicate the direction of water flow. reactor by a pair of gland nuts. The high-pressure reactor is s u r r o u n d e d by a ceramic b a n d heater with a t e m p e r a t u r e controller. The confining pressure of the core is m o n i t o r e d by a pressure gauge a n d adjusted t h r o u g h a valve. The water flow system is connected to the core assembly t h r o u g h a n inlet valve. The system is c o m p o s e d o f a water tank, a metering p u m p , a n d a back-pressure regulator. The flow pressure is m o n i t o r e d by a pressure gauge. The water drainage system, which is c o m p o s e d o f a g r a d u a t e d cylinder a n d a d r a i n a g e beaker, is connected to the core assembly at a n outlet valve.

Core No.

A c o n s t a n t confining water pressure of 138 bars (2000 psi) a n d a t e m p e r a t u r e of 90°C (194°F) were applied to the core assembly. The core was first connected to a v a c u u m p u m p to remove air in the pore space. Then, a p u m p i n g system (not s h o w n in Fig. 1) was connected to the inlet valve to saturate the core with water a n d measure the pore volume o f the core. A n oil transfer cell (not s h o w n in Fig. 1) was then connected to the inlet valve to start crude oil saturation. The process was completed when excess crude oil was accumulated in a g r a d u a t e d cylinder. The core, at this point, resembled a water-wet reservoir. The volume o f the water expelled during oil s a t u r a t i o n was recorded to determine the irreducible water saturation. The water flow system was then connected to the inlet valve (Fig. 1), a n d water started to flow t h r o u g h the core. C r u d e oil within the core was flushed out until water started to flow from the core. T h a t point, which is called b r e a k t h r o u g h by p r o d u c t i o n engineers, is defined as the starting point o f a water washing run. The volume o f the crude oil flushed o u t of the core was m e a s u r e d to calculate the residual oil s a t u r a t i o n (Table 1). The residual crude oil in

Table 1. Mineralogy and reservoir properties of the sandstone and limestone cores Pore volume (cm3) Helium Air XRDdatat porosity permeability Swl* SOR* H e l i u m Water (%) (md) (%) (%) Qtz Cc Fsp

Clay

Sandstone

2E 5E 6E 7E 8E

33.69 34.33 33.27 33.00 32.06

30.08 31.77 31.12 31.23 30.11

18.59 18.82 18.59 18.41 17.89

154.84 163.61 164.35 152.15 112.77

34.57 36.73 42.87 28.02 38.56

37.24 34.63 29.99 46.75 33.87

91.4 90.2 90.5 95.0 91.7

0.7 0.5 0.5 0.4 0.4

1L 46.93 43.94 25.37 4L 49.61 44.50 26.31 5L 48.10 45.41 25.70 7L 48.15 45.32 25.63 10L 44.15 44.33 24.38 12L 48.15 43.91 25.92 *Swl, Irreducible water saturation

18.15 18.32 20.74 18.26 18.43 19.11

26.95 26.76 29.97 29.22 28.76 36.47

29.13 32.36 32.35 35.07 29.78 24.72

0.5 0.5 0.5 0.5 0.5 0.5

99.5 99.5 99.5 99.5 99.5 99.5

4.7 2.0 1.7

2.4 2.6

3.2 7.3 7.3 2.2 5.3

Limestone

Swl = 1

water expelled - headspace volume water pore volume

SoR, Residual oil saturation SOR= 1 -- Swt

oil expelled - headspace volume water pore volume

tXRD data, normalized weight percent. Qtz, quartz; Cc, carbonates (calcite, dolomite, and ankerite); Fsp, feldspars (K-feldspar and plagioclase); Clay, clay minerals (kaolinite).

Crude oil alteration in reservoir rocks the pore space was subsequently washed by water flowing continually through the core. The volume of water exiting the core was regularly measured and discarded. Table 2 summarizes the conditions of the experiments. At the conclusion of each experiment, the heater was turned off to allow the core assembly to cool. The confining pressure was bled off, and the core was retrieved from the high-pressure reactor and solvent extracted to recover the water-washed oil.

Extraction and analysis Extraction of water-washed oils was carried out in a Soxhlet apparatus for 16 h, using a 2:1 tolueneisopropanol mixture. After extraction, the solvent was removed using a rotary evaporator followed by a nitrogen stream. The original oils and water-washed oils were then subjected to identical analyses. A small piece of the extracted core from each experiment was ground for mineralogy determination by X-ray diffraction. Oil was filtered with heptane to precipitate the asphaltene fraction. The remaining oil sample was separated into saturate, aromatic, and N S O fractions by sequentially eluting with heptane, toluene, and a chloroform-methanol mixture (9:1) through a glass column (3/8 in. i.d.) packed with alumina, silica, and quartz wool. Whole-oil samples were analyzed with a Mettler D M A 4 5 digital densitometer for API gravity, with a L E C O SC-432 instrument for sulfur content, and with an Ortec T E F A - 3 tube-excited fluorescence analyzer for vanadium and nickel content. Stable carbon isotopic analysis was performed with a VG

467

Table 2. Identificationand conditions of water washing experiment Water volume Average Run Core Run time flow rate No. No. (days) Liters PV* (cm3/min) Sandstone

SM2 SM3 SM4 SM6 SM7

2E 5E 6E 8E 7E

42 70 90 92 149

30 60 97 165 200

997 1888 3117 5465 6404

0.50 0.60 0.75 1.25 0.93

Limestone

LM I lL 13 20 455 1.07 LM3 4L 40 80 998 1.39 LM4 12L 46 110 2505 1.66 LM6 7L 76 180 3972 1.64 LM7 10L 82 210 4737 1.78 LM8 5L 94 240 5285 1.77 *PV, pore volume (water volume divided by water pore volume).

Sigma 10 Series 2 triple collector isotope ratio mass spectrometer. Gas chromatography (GC) was performed using a Hewlett-Packard 5890 instrument from 100°C to 325°C at 4°C/min with a DB5 column and an F I D detector. Gas chromatography-mass spectrometry ( G C - M S ) was performed using an H P 5890 instrument at 4°C/min from 100 to 210°C and 1.5°C/rain from 210 to 325°C with a DBI (50m, 0.2 mm i.d.) column and an H P 5970 M S D detector with selected ion monitoring (SIM) mode. Helium was used as the carrier gas in both G C and G C - M S analyses. Data reduction was done using an H P 1000 computer. Corrected peak areas obtained by baseline subtraction were used for data calculation. A Siemens D500-II system with CuK~t radiation at 40 kV and 30 m A and a D I F F R A C V software were used to collect and reduce the X-ray diffraction data.

Ph

26

Pr

SM4 ( 97 Liters) 26

11

18

LM3 ( 80 Liters)

Ph

Fig. 2. Gas chromatograms showing the effect of water washing in (A) sandstone and (B) limestone cores. Pr: pristane, Ph: phytane. Paraffins are identified by their carbon numbers.

468

LUNG-CHUAN KUO Table 3. Bulk chemical composition and API gravity of the original and water-washed crude oils

Composition (wt%) Run No.

APi

V (ppm)

Ni (ppm)

V/(V + Ni)

(wt%)

Sat

20.7 18.4 16.9 16.7 18.8 20.9 18.3

67.6 25.4 19.8 2.1 2.5 2.5 10.5

18.8 7.1 9.3 2.1 2.5 2.5 4.7

0.78 0.78 0.68 0.50 0.50 0.50 0.69

3.01 2.14 2.05 2.05 1.25 1.21 1.74

27.6 13.7 21.7 12.2 27.2 16.7 11.9 17.2

24.2 3.3 13.7 10.0 17.0 6.2 5.0 9.2

12.2 5.9 15.5 23.1 15.3 21.3 5.0 14.4

0.66 0.36 0.47 0.30 0.53 0.23 0.50 0.38

1.75 1.24 1.47 1.55 1.47 1.41 1.42 1.43

S

Arom

NSO

Asph

Sat/Arom

HC/NHC

35.11 29.49 33.84 29.20 37.12 44.15 34.76

31.98 28.03 27.49 28.92 21.11 18.46 24.80

18.10 34.95 30.09 30.70 26.45 23.82 29.20

14.81 7.53 8.58 11.18 15.32 13.57 11.24

1.10 1.05 1.23 1.01 1.76 2.39 1.40

2.04 1.35 1.59 1.39 1.39 1.67 1.47

40.13 42.07 56.45 53.22 64.90 58.45 52.81 54.65

33.80 25.23 16.85 21.60 13.69 21.86 23.58 20.47

19.05 25.86 18.22 18.86 13.88 12.62 19.09 18.09

7.02 6.84 8.48 6.32 7.53 7.07 4.52 6.79

1.19 1.67 3.35 2.46 4.74 2.67 2.23 2.67

2.83 2.06 2.75 2.97 3.67 4.08 3.23 3.02

Sandstone

MI SM2 SM3 SM4 SM6 SM7 SMA Limestone

M2 LM 1 LM3 LM4 LM6 LM7 LM8 LMA

V, vanadium; Ni, nickel; S, sulfur; Sat, saturates; Arom, aromatics; NSO, nitrogen-, sulfur- and oxygen-bearing compounds; Asph, asphaltenes; HC, hydrocarbons (Sat + Arom); NHC, nonhydrocarbons (NSO + Asph). M1 and M2, original Mishrif crude oils. SMA and LMA, averaged water-washed oils.

P o r o s i t y a n d p e r m e a b i l i t y m e a s u r e m e n t is precise to + 2 % relative. X - r a y diffraction is precise to + 5 % relative for e a c h m i n e r a l c o m p o n e n t . Analytical precision is + 0 . 5 ° a b s o l u t e f o r A P I gravity; + 5 % relative f o r v a n a d i u m , nickel, a n d s u l f u r c o n t e n t ; a n d + 0.1%o a b s o l u t e f o r stable c a r b o n i s o t o p i c c o m p o sition. Bulk a n d h y d r o c a r b o n c o m p o s i t i o n is precise to + 10% relative f o r each fraction. G e o c h e m i c a l p a r a m e t e r s derived f r o m G C a n d C G - M S analyses are precise to w i t h i n +__2.5% relative.

THE EFFECT OF WATER WASHING ON OIL GEOCHEMISTRY G e o c h e m i c a l analysis w a s p e r f o r m e d o n the C15 + f r a c t i o n o f the oils; the C15_ f r a c t i o n w a s lost d u r i n g Soxhlet extraction. O r g a n i c g e o c h e m i c a l d a t a for

the t w o original oils (M 1 a n d M2), w a t e r - w a s h e d oils ( S M a n d L M series), a n d a v e r a g e d w a t e r - w a s h e d oils ( S M A a n d L M A ) are listed in T a b l e s 3-7. G C a n d G C - M S traces for original a n d selected w a t e r w a s h e d oils are p r e s e n t e d in Figs 2 - 9 . B i o m a r k e r n o m e n c l a t u r e follows t h a t given in Peters a n d M o l d o w a n (1993).

A PI gravity T h e A P I gravity o f the w a t e r - w a s h e d oils in s a n d s t o n e cores r a n g e s f r o m 16.7 to 20.9 ° with an a v e r a g e o f 18.3 ° ( T a b l e 3). T h i s r e p r e s e n t s a m a x i m u m o f 4.0 ° a n d a n a v e r a g e o f 2.4 ° decrease in A P I gravity d u e to w a t e r w a s h i n g . T h e A P I gravity o f the w a t e r - w a s h e d oils in limestone cores r a n g e s f r o m i 1.9 to 27.2 ° with an a v e r a g e o f 17.2 ° (Table 3), indicating a m a x i m u m o f 15.7 ° a n d an a v e r a g e o f 10.4 ° decrease in A P I

Table 4. Carbon isotopic and hydrocarbon composition on the original and water-washed crude oils HC composition (wt%) Ran No.

Par

,~ t3CpDB(%o)

Isoprenoid ratios

C31/Ci9 W.O.

Arom

Naph

Pr/Ph

Pr/17

Ph/18

CPI

15.09 13.51 14.17 14.11 23.27 19.84 16.98

47.67 48.73 44.82 49.76 36.25 29.49 41.81

37.24 37.76 41.01 36.13 40.48 50.67 41.21

0.43 0.39 0.41 0.41 0.47 0.47 0.43

0.36 0.38 0.37 0.37 0.53 0.79 0.49

0.74 0.77 0.78 0.78 0.88 1.08 0.86

0.95 1.00 1.00 1.00 0.99 0.96 0.99

0.20 0.52 0.36 0.50 0.98 0.91 0.65

27.10 36.00 46.02 27.58 33.23 32.33 26.15 33.55

45.72 37.49 22.99 28.87 17.41 27.21 30.87 27.47

27.18 26.51 30.99 43.55 49.36 40.46 42.98 36.58

0.65 0.65 0.65 0.79 0.79 0.75 0.79 0.74

0.37 0.39 0.40 0.58 0.62 0.58 0.64 0.54

0.59 0.61 0.62 0.70 0.71 0.71 0.76 0.69

0.99 0.99 1.00 1.02 1.02 1.02 1.02 1.01

0.16 0.23 0.58 0.63 0.61 0.67 0.70 0.57

Sat

Arom

NSO

Asph

-26.5 -26.8 -26.8 -26.8 - 26.9 -26.8 -26.8

-27.1 -27.2 -27.2 -27.3 - 27.4 -27.5 -27.3

-26.1 -25.9 -25.9 -25.9 - 26.0 -26.0 -25.9

-25.9 -27.2 -27.3 -27.4 - 27.2 -27.2 -27.3

-26.3 -26.2 -26.2 -26.2 - 26.6 -26.4 -26.3

-26.6 -26.9 -27.0 -26.8 -26.7 -26.8 - 26.8 -26.9

-27.2 -27.3 -27.4 -27.4 -27.4 -27.4 - 27.4 -2%4

-26.2 -26.1 -26.1 -26.1 -26.1 -26.0 - 26.1 -26.1

-25.8 -27.1 -27.3 -27.2 -2%2 -27.3 - 27.4 -27.3

-26.1 -26.1 -26.1 -26.4 -26.2 -25.9 - 26.3 -26.2

Sandstone

MI SM2 SM3 SM4 SM6 SM7 SMA Limestone

M2 LMI LM3 LM4 LM6 LM7 LM8 LMA

Par, paraffins; Arom, aromatics; Naph, naphthenes; Pr, pristane; Ph, phytane; 17, .qClT; 18, nCts; CPI, carbon preference index (C~733); W.O., whole oil. MI and M2, original Mishrif crude oils. SMA and LMA, averaged water-washed oils.

469

Crude oil alteration in reservoir rocks Table 5. Bicyclic alkane, diterpan¢, and triterpan¢ biomarker data on the original and water-washed crude oils

Run No. RI R2 R3 R4 R5 R6 R7 Rs R9 Ri0 Rll RI2 RI3 Rj4 Sandstone 0.94 0.71 1.27 2.59 1.04 0.97 5.55 0.95 0.38 0.60 0.62 0.62 MI 0.19 0.27 0.93 0.78 1.33 2.53 1.05 0.95 5.46 0.93 0.41 0.59 0.61 0.63 SM2 0.16 0.31 0.94 0.79 1.31 2.44 1.01 0.98 5.25 0.93 0.41 0.60 0.61 0.63 SM3 0.17 0.28 0.94 0.78 1.37 2.57 1.02 0.94 5.34 0.93 0.44 0.59 0.61 0.63 SM4 0.15 0.31 0.97 0.85 1.28 2.43 0.99 0.85 5.11 0.93 0.45 0.59 0.61 0.64 SM6 0.22 0.45 0.93 0.84 1.25 1.97 0.93 1.06 5.31 0.93 0.43 0.59 0.62 0.62 SM7 0.22 0.44 0.94 0.81 1.31 2.39 1.00 0.96 5.29 0.93 0.43 0.59 0.61 0.63 SMA 0.18 0.36 Limestone 1.15 1.04 1.52 3.11 0.99 1.09 3.83 0.95 0.53 0.60 0.61 0.63 M2 0.44 0.76 1.07 1.05 1.37 2.61 0.94 1.07 3.81 0.94 0.55 0.57 0.61 0.65 LM I 0.44 0.76 0.97 1.14 1.40 2.50 0.91 0.91 3.89 0.93 0.57 0.58 0.61 0.66 LM3 0.44 0.76 1.07 1.07 1.31 1.83 0.85 0.90 3.58 0.94 0.52 0.57 0.61 0.66 LM4 0.50 0.88 1.05 1.07 1.28 1.84 0.86 0.97 3.65 0.94 0.52 0.59 0.61 0.64 LM6 0.55 0.85 1.00 1.13 1.23 1.93 0.87 1.04 3.68 0.94 0.53 0.60 0.61 0.65 LM7 0.51 0.85 1.03 1.16 1.33 2.07 0.88 1.10 3.67 0.93 0.55 0.59 0.61 0.64 LM8 0.49 0.88 1.03 1.10 1.32 2.13 0.89 1.00 3.71 0.94 0.54 0.59 0.61 0.66 LMA 0.49 0.83 R t , Cis/Ci6 bicyclic alkane ratio (DRI/HDR); R2, rearranged CI5 bicyclic alkane ratio (RD1 + RD2/DRI); R3, C24/C25diterpane ratio if/g); R4, tetracyclic index (x/h); Rs, C26/C2~diterpane ratio (h/28); R6, diterpane index (b + c + d + e + f + g + h/E); RT, C29/C30hopane ratio (C/E); Ra, C35/C34hopane ratio (R + S/P + Q); R 9, C29 hopane ratio (C/Cp); Ri0, C30 hopane/hopane + moretane ratio (E/E + F); R , , C27 trisnorhopane ratio (Ts/Ts + Tm); R~2, C32 bishomohopane ratio (K/K + L); Rt3, C3~ homohopane isomerization (G/G + H); R~4, C3~ 35 22R/22S hopane ratio (H + L + O + Q + S/G + K + N + P + R). MI and M2, original Mishrif crude oils. SMA and LMA, averaged water-washed oils.

g r a v i t y as a result o f w a t e r w a s h i n g . T h i s s u g g e s t s t h a t w a t e r w a s h i n g is m o r e effective in l i m e s t o n e cores. T h e A P I g r a v i t y d e c r e a s e in w a t e r - w a s h e d oils e x h i b i t s l a r g e v a r i a t i o n a n d is n o t c o r r e l a t e d w i t h w a t e r v o l u m e . T h i s i r r e g u l a r A P I g r a v i t y v a r i a t i o n is likely a r e s u l t o f c o m p l e x fluid flow b e h a v i o r in p o r o u s m e d i a . I n a S a u d i A r a b i a n field c a s e r e p o r t e d by E a k i n et al. (1990), c r u d e oil p r o d u c e d p r i o r to w a t e r i n j e c t i o n h a s a n a v e r a g e d A P I g r a v i t y o f 30 °, whereas that produced after water injection and water breakthrough has an irregular variation of

--O-- M1 .-.0-.- SIA2 ( 30 --Z~- SM3 ( 60 - 0 - sa4 ( 97 --B-- sue (165 --¢k-' SM7 (200

A

"~'~

A P I g r a v i t y f r o m l 0 to 30 ° w i t h a n a v e r a g e o f 20 °. T h i s field c a s e is e s s e n t i a l l y d u p l i c a t e d in t h e p r e s e n t e x p e r i m e n t w i t h t h e l i m e s t o n e cores. T h i s r e m a r k a b l e similarity suggests that the present study provides a very reasonable simulation of water washing under reservoir conditions.

M e t a l and sulfur content Oils w a s h e d in s a n d s t o n e c o r e s s h o w a s y s t e m a t i c d e c r e a s e in v a n a d i u m , nickel, a n d s u l f u r c o n t e n t w i t h increasing water washing, and the V/(V + Ni) ratio d e c r e a s e s f r o m a b o u t 0.8 to 0.5. T h e v a n a d i u m ,

~

B

Liter=) Uter=) Uter=) L~er~) Uteri=)

~.~

M2 LM1 ( 20 Uter=)

LM3( 80 Uter=) LM4 L~6 LM7 u,~

(110 (180 (210 (24o

Uterll) uter=) Liter=) ut~,~)

Saturates

Saturates

Whole-oil

Whole-oil

Aromatics

Aromatics

NSOs

NSOs

Asphaltenes

Asphaltenes

I

I

I

I

I

I

I

I

-28

-27

-26

-25

-24

-28

-27

-26

I

-25

I

-24

613CpDB ( 0 / 0 0 ) Fig. 3. Isotope type curves (Stahl, 1978) for the oil samples from (A) sandstone and (B) limestone experiment set. OG 21/5~D

LUNG-CHUAN K u o

470

Table 6. Sterane biomarker data on the original and water-washed crude oils Run No.

Ri5

Ri6

Rir

Rl~

RI9

R20

R21

R22

R23

R24

Sandstone MI SM2 SM3 SM4 SM6 SM7 SMA

3.34 3.44 3.62 3.43 3.49 3.88 3.57

0.58 0.64 0.64 0.67 0.68 0.62 0.65

0.57 0.57 0.57 0.56 0.57 0.57 0.57

0.94 0.98 0.98 0.99 0.99 0.92 0.97

1.16 1.20 1.20 1.21 1.17 1.22 i.20

0.53 0.52 0.52 0.52 0.53 0.55 0.53

0.49 0.50 0.49 0.50 0.50 0.48 0.49

39.8:30.1:30.1 40.3:30.2:29.5 39.7:29.8:30.5 40.2:29.9:29.9 40.0:29.5:30.5 38.3:29.91:31.8 39.7:29.9:30.4

0.17 0.18 0.19 0.16 0.17 0.18 0.18

0.77 0.61 0.71 0.58 0.77 0.83 0.70

Limestone M2 LM1 LM3 LM4 LM6 LM7 LM8 LMA

3.85 3.36 3.57 4.72 4.88 4.88 4.39 4.30

0.88 0.92 0.94 0.81 0.88 0.93 0.89 0.90

0.60 0.60 0.58 0.58 0.59 0.59 0.58 0.59

1.04 1.02 1.20 1.09 0.94 1.21 0.89 1.06

1.33 1.41 1.42 1.31 1.24 1.51 1.24 1.36

0.56 0.57 0.56 0.53 0.53 0.55 0.54 0.55

0.51 0.50 0.54 0.52 0.49 0.55 0.47 0.51

42.1:29.4:28.5 40.7:28.9:30.4 41.3:29.4:29.3 38.2:29.6:32.2 38.0:30.0:32.0 38.7:29.9:31.4 39.4:29.3:31.3 39.4:29.5:31.1

0.11 0.10 0.10 0.13 0.12 0.12 0.il 0.11

0.45 0.44 0.53 0.64 0.85 0.86 0.75 0.68

Ris, hopane/sterane ratio (E/8 + I1); RI6, C27 diasterane index (I + 2/8 + I1); RI7 , C27 fl3/(ct~t + tiff ) cholestane ratio (9 + 10/8 + 9 + 10 + 11); Ris, C29 stigmastane 50t (20S)/5~t (20R) ratio (19/22); RIg, C29 stigmastane 14fl,17//(20R)/5~t (20R) ratio (20/22); R20, C29 fl///(0t~t +//,6' ) stigmastane ratio (20 + 21/19 + 20 + 21 + 22); R21, C29 sterane isornerization (19/19 + 22); R22,////sterane proportion (27bb:28bb:29bb); R23, C30 diasterane index (30d/8+ I1); R24, C30 4-methyl sterane index (4Me/8 + 1 I). M1 and M2, original Mishrif crude oils. SMA and LMA, averaged water-washed oils.

nickel, and sulfur content in water-washed oils in limestone cores show a similar decrease from the original oil, with a sharp drop during the initial stage of water washing and with variable V/(V + Ni) ratio. The lowest metal and sulfur content in water-washed oils in sandstone and limestone cores is very similar (vanadium and nickel: 2.1 ppm vs 5.0ppm, sulfur: 1.21% vs 1.24%, Table 3).

Bulk and hydrocarbon composition Aromatic hydrocarbon content decreased by an average of 7.2% and NSO content increases by an average of 11.1% in oils washed in sandstone cores (Table 3). These indicate that water preferentially removes low molecular-weight aromatic compounds which are several orders of magnitude more soluble in water than saturate compounds with similar carbon numbers (McAuliffe, 1963, 1966, 1969; Baker, 1967; Wauchope and Getzen, 1972; Sutton and Calder, 1974, 1975; Button, 1976; Eganhouse and Calder, 1976; Price, 1976; Schwartz and Wasik, 1976; Mackay and Shiu, 1977). The decrease in aromatic content is likely to be responsible for the higher saturate/aromatic (Sat/Arom) ratio and lower hydrocarbon/nonhydrocarbon (HC/NHC) ratio in these water-washed oils (Table 3). Oils washed in limestone cores lost an average of 13.3% of aromatics but gained an average of 14.5% of saturates. These oils have lower aromatic content and higher Sat/Arom ratios, but their NSO content increases first and then decreases and HC/NHC ratio decreases first and then increases (Table 3). These indicate that water washing also affects some heavier resins in these oils. This is consistent with the earlier interpretation that oils in limestone cores are more effectively washed by water. Hydrocarbons in water-washed oils also show significant decrease in aromatic content (by 18.2%

in sandstone cores and 28.3% in limestone cores) (Table 4). On average, water-washed oils in limestone cores have a greater increase in paraffin and naphthenic content than those in sandstone cores. Pristane/nC17, phytane/nCjs, and C31/C~9 ratios all are increased by water washing (Table 4), which is consistent with preferential loss of light paraffins over isoprenoids and heavier paraffins because of their higher aqueous solubility (McAuliffe, 1966; Baker, 1967; Sutton and Calder, 1974; Price, 1976, 1981). Pristane/phytane ratio and carbon preference index (CPI) are unchanged. A greater enrichment of

Table 7. Aromatic biomarker data on the original and water-washed crude oils Run No.

R25

R26

R27

R28

R_,9

R30

R3~

R32

Sandstone MI SM2 SM3 SM4 SM6 SM7 SMA

0.36 0.35 0.37 0.37 0.46 0.44 0.40

0.43 0.40 0.41 0.41 0.49 0.48 0.44

2.25 1.83 1.50 1.43 1.37 1.45 1.52

1.52 1.48 1.55 1.60 1.52 1.64 1.56

0.45 0.33 0.22 0.22 0.14 0.15 0.21

0.30 0.27 0.26 0.25 0.15 0.17 0.22

0.88 0.95 0.93 0.95 1.00 1.01 0.97

0.87 0.91 0.92 0.93 0.96 0.98 0.95

Limestone M2 LM1 LM3 LM4 LM6 LM7 LM8 LMA

0.43 0.44 0.49 0.40 0.40 0.39 0.40 0.42

0.46 0.48 0.51 0.41 0.41 0.41 0.41 0.44

1.69 1.65 1.36 1.87 1.56 1.64 1.80 1.65

1.62 1.65 1.57 1.58 1.46 1.38 1.26 1.49

0.44 0.29 0.12 0.18 0.06 0.11 0.09 0.13

0.32 0.29 0.14 0.15 0.06 0.09 0.07 0.13

0.87 0.90 1.08 0.95 1.12 I.II 1.19 1.06

0.89 0.91 1.02 0.94 1.04 1.04 1.08 1.01

R25, C20/C20+C27 triaromatic sterane ratio (20/20+27); R26, C2jC 2~+ C2s triaromatic sterane ratio (21/21 + 28); R27, dibenzothiophene/phenanthrene ratio (DBT/PHEN); R2s , methyldibenzothiophene/methylphenanthrene ratio (MDBT/MPH); R2~, dibenzothiophene/methyldibenzothiophene ratio (DBT/MDBT); R30, phenanthrene/methylphenanthrene ratio (PHEN/MPH), R~, methylphenanthrene index, MPI (3 × 2MPH/PHEN + IMPH + 9MPH); R32, calculated Ro equivalent (0.6 x MPI + 0.37). MI and M2, original Mishrif crude oils. SMA and LMA, averaged water-washed oils.

Crude oil alteration in reservoir rocks heavier hydrocarbons in oils washed in limestone cores (Fig. 2) again indicates more effective washing and removal of light paraffins. Stable carbon isotopic composition Stable carbon isotopic composition of waterwashed oils is slightly more negative in the saturate fraction, essentially unchanged in the aromatic fraction, and significantly more negative in the NSO fraction. The whole-oil carbon isotopic composition is 0.3-0.4%0 more negative than the original oils (Table 4 and Fig. 3). The variation in the carbon isotopic composition in the saturate and aromatic fractions observed in this study is consistent with that observed in a series of naturally water-washed oils (Palmer, 1984). The dramatic effect of water washing on NSO fraction requires further investigation. For instance, the data

seem to suggest that certain isotopically more positive NSO compounds are highly soluble in water, and this hypothesis may be tested when compound-specific carbon isotopic analysis on NSO fraction can be performed. Saturate biomarkers In water-washed oils, the Cl5 8fl (H)-drimane/Ci6 8/~(H)-homodrimane (DRI/HDR) ratio increases slightly and the Ct5 rearranged drimane/Cl5 8/~ (H)drimane ratio (RD/DRI) increases significantly, with respect to the original oils (Table 5, Fig. 4). This suggests that rearranged drimanes are more resistant to water washing than homodrimane and drimane. Water washing has little effect on diterpanes. The C24/C2s and C26/C28 diterpane ratios (f/g and h/28) and tetracyclic index (x/h) are all little changed in water-washed oils (Table 5, Fig. 5). Triterpanes

HDR

HDR

M1

471

m/z123

m/z 123

M2

DRI

LM3 ( 80 Liters)

SM2 ( 30 Uters)

J

0 e0 O. n"

LM8 (240 Uters)

SM7 (200 Liters)

ScBn

,~

Fig. 4. Mass chromatograms (m/z 123) of original and selected water-washed oils. Peak identification: RDI and RD2: rearranged drimane, DRI: 8fl-drimane, HDR: 8fl-homodrimane.

472

LUNG-CHUANKUO

are also little affected by water washing. The C 2 9 / C 3 0 triterpane ratio (C/E), C35/C34 triterpane ratio (R + S/P + Q), and C29 triterpane ratio (C/Cp) in water-washed oils show some variation with water volume but are, on average, little changed with respect to the original oils (Table 5, Fig. 5). A slight depletion of diterpanes with respect to triterpanes in water-washed oils is noted by the lower diterpane index (Table 5). Water washing has little effect on steranes. Original and water-washed oils have similar C27 diasterane index (l + 2 / 8 + ll), C27 and C29 fl[3/(~ct + tiff ) sterane ratios (9 + 10/8 + 9 + 10 + 11 and 20 + 21/19 + 20 + 21 + 22, respectively), C29

M1

c

m/z 191

5= (20S)/5ct (20R) and 14fl, 17fl (20R)/50t (20R) ratios (19/22 and 20/22, respectively), C2729 tiff sterane proportion (27bb:28bb:29bb), and C30 diasterane index (30d/8+ 11) (Table 6; Fig. 6). Water-washed oils have slightly higher hopane/ sterane ratio (E/8 + ! 1 in Table 6) and C30 4-methyl sterane index (4Me/8 + 11) (Table 6, Fig. 7). This indicates a slightly preferential removal of C27 steranes which have a lower molecular weight than C30 hopane and C30 4-methyl steranes. Hopane maturity indicators, including C30 hopane/ hopane + moretane ratio (E/E + F) (Gallegos, 1981), C27 trisnorhopane ratio (Ts/Ts + Tm) (Seifert and Moidowan, 1978), C31 homohopane isomerization

M2

CE •

m / z 191

G

o ,

T°II

G

PIK

b

,.I

;

L,I [i I,,

LN

h

h , ~l L L . . J

28

"~U

LN

_._

F

IlO~

/t.U--!l

LM3 ( 8o uters)

SM2 ( 30 Liters)

1

0

0CI. 0

t.LLJ

L LM8 (240 Liters)

SM7 (200 Liters)

I

tel,. SgJn

l=

Fig. 5. Mass chromatograms (m/z 191) of original and selected water-washed oils. Peak identification: I~h, C20 to C26 tricyclic terpanes; x, C24 tetracyclic terpane; 28, C2s tricyclic terpanes; T~, 22,29,30-trisnorhopane-II; T m, 22,29,30-trisnorhopane; C, 17~t,21fl(H)-30-norhopane; Cp, 18~t(H)-30-norneohopane; E, 170t21fl(H)-hopane; F, 17fl,21~(H)-hopane (moretane); G and H, 17ct,21fl(H)-29-homohopane 22S and 22R; K and L, 17ct,21fl(H)-29-bishomohopane 22S and 22R; N and O, 17ct,21fl(H)-29-trishomohopane 22S and 22R-, P and Q, 17ct,21fl(H)-29-tetrakishomohopane 22S and 22R; R and S, 17ct,21fl(H)-29-pentakishomohopane 22S and 22R.

Crude oil alteration in reservoir rocks (G/G + H) (Mackenzie et al., 1980; Mackenzie and McKenzie, 1983), and C32 bishomohopane ratio (K/K + L) (Mackenzie et al., 1988), are unaffected by water washing (Table 5). The C29 sterane isomerization ratio (19/19 + 22) (Mackenzie et al., 1980) is also little affected by water washing (Table 6). Aromatic biomarkers

The dibenzothiophene/methyldibenzothiophene and phenanthrene/methylphenanthrene ratios (DBT/ MDBT and PHEN/MPH, respectively) in all waterwashed oils decrease systematically with increasing water volume (Table 7, Figs 8 and 9). That is also observed in a laboratory study by Lafargue and Barker (1988). The methyldibenzothiophene/methylphenanthrene ratio (MDBT/MPH) in water-washed oils is un9

473

changed in sandstone cores but decreases slightly in limestone cores (Table 7). Lafargue and Barker (1988) also observed that this ratio is little affected by water washing, whereas Palmer (1984) showed that this ratio decreases in some naturally waterwashed oils. The dibenzothiophene/phenanthrene ratio (DBT/PHEN) in water-washed oils in sandstone cores decreases systematically with increasing water volume and, on average, slightly decreases in the limestone cores (Table 7). The decrease in dibenzothiophene/phenanthrene ratio is observed in some naturally water-washed oils (Palmer, 1984), but not in some experimentally water-washed oils (Lafargue and Barker, 1988). Triaromatic steroid maturity indicators (Mackenzie, 1984) show a slight maturity increase in water-washed oils (Table 7). Methylphenanthrene 9

m/z 217

m/z 217

M2

MI

0 20 \

10 11 I

21

I

,I

2 0 /21

2

SM2 ( 30 Liters)

LM3 ( 80 Uters)

SM7 (200 Uters)

LM8 (240 Uters)

C

g

m o n-

Scan

Fig. 6. Mass chromatograms (m/z 217) of original and selected water-washed oils. Peak identification: 1 and 2, 13fl,17~t-diacholestane20S and 20R; 8, 5~t-cholestane 20S and 5fl-cholestane 20R; 9, 5~t,14/~,17/~cholestane 20R and 13fl,17ct-diastigmastane 20S; 10, 5~t,14fl,17fl-cholestane 20S; 11, 5~t-cholestane 20R; 19, 5et-stigmastane 20S; 20, 5ct,14fl,17fl-stigmastane 20R; 21, 5a, 14fl,17fl-stigmastane 20S and 5fl-stigmastane 20R; 22, 5ct-stigmastane 20R.

LUNG-CHUANKuo

474

Index (MPI) and calculated vitrinite reflectance (Radke et al., 1982) increase markedly (Table 7) due to a decrease in phenanthrene relative to methylphenanthrenes as a result of water washing. EXPLORATION AND PRODUCTION

APPLICATIONS

Recognition of water washing effects The major effects of water washing on crude oils include (1) decrease or API gravity, sulfur, nickel, and vanadium content, (2) decrease of aromatics including low molecular-weight compounds, phenanthrene, and dibenzothiophene, (3) decrease of low molecularweight normal alkanes, (4) increase of rearranged drimanes relative to the 8fl (H)-drimane, (5) slight decrease of diterpanes relative to triterpanes, (6) slight decrease of C27 steranes relative to C30 hopane and 4-methyl steranes, (7) slight increase of C20 and C21 triaromatic steranes relative to the C27 and C2s counterpart, and (8) decrease of the stable carbon

m/z231 /

isotope ratio of NSO compounds. Table 8 summarizes organic geochemical parameters which can be used to discern different alteration processes in crude oils derived from common source(s). Reservoir lithology affects the location of oil and the relative permeability of water in the pore system in such a way that water washing is more effective in limestones than in sandstones. As a result, oils washed in limestone cores tend to have lower API gravities and more severe loss of aromatics than those washed in sandstone cores. Oils washed in limestone cores also have a slightly smaller decrease in sulfur and metal content and slightly more severe loss of NSOs and light paraffins than those washed in sandstone cores. However, these variations are considered minor relative to the major effects of water washing described above.

Geochemical interpretation of water-washed oils Diterpane, triterpane, and sterane biomarkers are little affected by water washing, and thus can be used

m/z231

M2

4Me 4Me

SM2( Liters) 30

LM8 ( 2 4 0 liters)

Scan

L

Fig. 7. Mass chromatograms (m/z 231) of original and selected water-washed oils. Peak identification: 4Me, C30 4-methyl steranes.

Crude oil alteration in reservoir rocks

475

Table 8. A summary of the effect of petroleum alteration processes on oil geochemistry Water washing

Biodegradation

Deasphalting

Maturation

API gravity Metal content Sulfur content C6_15 content Gas-to-oil ratio C~5+ composition

Decreased Decreased Decreased Decreased Decreased Aromatics decreased

Decreased Increased Increased Decreased Decreased Saturates decreased

Decreased Increased Increased Decreased Decreased Asphaltenes increased

CSCI9, pristane/nCiT, and phytane/nCi8 ratios Carbon isotopic composition

Increased

Increased

Unchanged

Increased Decreased Decreased Increased Increased Asphaltenes and NSOs decreased Decreased

NSO fraction becomes lighter

Aromatic fraction becomes lighter

Asphaltene fraction becomes heavier

CI5/Ct6 bicyclic

Increased

Saturate fraction becomes heavier, Asphaltene fraction becomes lighter Increased

Unchanged

Increase

Increased

Decreased

Unchanged

Increased

Diterpanes decrease relative to triterpanes C27 steranes decrease relative to C30 hopane and 4-methyl steranes C20 and C2~ increase relative to C27 and Cz8

Diterpanes increase relative to triterpanes* Decreased*

Unchanged

Diterpanes increase relative to triterpanes Unchanged

C20 and C2~ increase relative to C27 and C28

Unchanged

Increased

Decreased

Decreased

C20 and C2t increase at the expense ofC27 and C28 Increased

Decreased Decreased

Decreased Decreased

Increased Increased

lncreased~ Decreasedt

alkanes Rearranged/8fl (H) CL5 bicyclic alkanes Terpanes Steranes Triaromatic steranes Methylphenanthrene index (MPI) DBT/MDBT PH EN/M PH

Unchanged

*Severe biodegradation. fType II source rocks only. Sources: Bailey et al. (1973), Seifert and Moldowan (1978, 1979), Stahl (1980), Volkman et al. (1983), Mackenzie (1984), Radke et al. (1986), Dahl and Speers (1986), Williams et al. (1986), Kennicutt (1988), Lafargue and Barker (1988), the present study, and unpublished Conoco data.

for oil-oil and oil-source correlation. The biomarker distributions for the water-washed oils are essentially identical to those of the original oils (Figs 4-9). Biomarker data can also be used to assess the depositional environments of source rocks from which water-washed oils were derived because the geochemical variations due to water washing are considerably smaller than those related to depositional environment. For example, Isaksen (1991) showed that the hopane/sterane ratio has a range of 0-5 for oils with a marine algal origin, 8-25 for those with a freshwater algal and terrigenous higher plant origin, and 3-10 for those with a mixed marine and terrestrial origin. The hopane/sterane ratio for all the original and water-washed oils has a range of 3.34-4.88 (Table 6). Didyk et al. (1978) showed that the pristane/phytane ratio has a range of 0.4-1.2 for oils and sediments with an anoxic marine origin, and 1.9-2.9 for those with an oxic deltaic/marine origin, whereas the pristane/phytane ratio in both original and waterwashed oils has a range of 0.39-0.47 in sandstone cores and 0.65-0.79 in limestone cores (Table 4). A combination of these geochemical parameters can therefore lead to the correct interpretation of source rock depositional environments based on water-washed oils. The origin o f tarmats

Tarmats consist of heavy, usually asphaltic, oils occurring near the oil-water contact (Dahl and

Speers, 1986) in many major oil fields worldwide (Hetherington and Horan, 1960; Haskett and Tartera, 1965; Jones and Speers, 1976; Killough et al., 1982; Bashbush et al., 1983; Dahl and Speers, 1985; among others). Geochemical processes proposed for tarmat formation include deasphalting, biodegradation, maturation, and water washing (Evans et al., 1971). Deasphalting is a process in which asphaltenerich oils are precipitated in response to pressure and/or temperature changes in the reservoir (Evans et aL, 1971; Hirschberg et al., 1982; Hirschberg, 1984). Deasphalting may occur as a result of geological forces (e.g. degassing, mixing of oils with different API gravities) or artificial factors (e.g. pressure drop during production, compositional changes due to miscible drive). Biodegradation typically occurs in reservoirs at temperatures of <90°C (Connan, 1984) in which aerobic bacteria carried by recharged groundwater thrive on hydrocarbons. Thermal maturation in deep reservoirs generates gases, which may cause deasphalting, and pyrobitumen (Rogers et al., 1974). Water washing and biodegradation frequently occur together in reservoirs. The water-washed oils in the present study show a trend of decreasing aromatic and saturate content which differs from that for tarmat formation by deasphalting (e.g. Jones and Speers, 1976; Dahl and Speers, 1985) (Fig. 10). However, asphaltene content increases in some oils washed in both sandstone and

476

LUNG-CHUAN KUO

PHEN

m/z 178,192

m / z 178,192

M2

M1

PHEN

2MPH

9MPH 2MPH 3MPH

(

30 Liters)

Lid3 ( 80 Uters)

SM7 (200 Uters)

W8 (240 Liters)

SM2

1MPH

= g e-

M

O o-

ScBn

=

Fig. 8. Mass chromatograms (m/z 178 and 192) of original and selected water-washed oils. Peak identification: PHEN, phenanthrene; 3MPH, 2MPH, 9MPH, and IMPH, 3-, 2-, 9-, and l-methylphenanthrene, respectively.

Crude oil alteration in reservoir rocks

DBT

MDBT r-~

m/z 184,198,212,226 DMDBT

i

MDBT

477

m/z 184,198,212,226

i

M2

M1

DBT

DMDBT !

i

TMDBT

SM2 ( 30 Uters)

LM3 ( 80 Uters)

SM7 (200 Uters)

LM8 (240 Uters)

] c o o. (n

n-

L

L

Scan

Fig. 9. Mass chromatograms (m/z 184, 198, 212, and 226) of original and selected water-washed oils. Peak identification: DBT, dibenzothiophene; MDBT, 4-, 3-, 2-, and l-methyldibenzothiophenes; DMDBT, dimethyldibenzothiophenes; TMDBT, trimethyldibenzothiophenes.

478

LUNG-CHUANKuo Sat+Atom

o SId series •

M2

.

NSO Asph Fig. 10. Compositional trends for water washing (from this study) and deasphalting [from Dahl and Speers (1986) and unpublished Conoco data]. limestone cores, and such increases may be greater with further increase in water volume and washing time. Therefore, tarmat formation by water washing over geological time cannot be ruled out based on short-term laboratory results. The effect o f water flooding on crude composition

Water flooding is one of the most commonly used methods for enhancing oil recovery. In a laboratory experiment, Eakin et al. (1990) found that water flooding decreases the residual oil volume while lowering the API gravity and bubble point and increasing the viscosity of the produced oil. Their results are similar to a field case in which the crude oils produced after water injection show lower API gravity (on average, 20 °) than those produced prior to water injection (on average, 30°). The results from the present study further confirm that the API gravity of the reservoired oils is reduced by water washing. The present data also suggest that the oil produced after water injection is likely to be of better quality due to the reduced sulfur and metals content. Associate E d i t o r - - K . PETERS Acknowledgements--The author thanks Conoco management for permission to publish this research. He is grateful to Lois Humble and Bob Coffee for their assistance in the laboratory; to Andre Bouchard; Eric Michael, Ray Mitchell, Janina Rafalska, Carolyn Thompson-Rizer, Bill Morgan, and Carol Walsh for helpful discussions; to Diane Anderson, John Davis, Ruth Engle, and Roger Woods for analytical support; and to Rexann Briggs and Cindy Larmer for preparing the manuscript. Critical reviews by K. E. Peters and R. J. Hwang greatly improve the paper. REFERENCES

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