J1
LS
Sw=0.19φ=0.32K=1287 mD
SW Perm
Fac
ies
Flow Units
METERSSW Por
LS
J2
DPHI
Sw=0.20φ=0.32K=1093 mD
PETROPHYSICAL ANALYSIS AND GEOLOGIC MODEL FOR THE BULLWINKLE J SANDS WITH IMPLICATIONS FOR TIME-LAPSE RESERVOIR MONITORING, GREEN CANYON BLOCK 65, OFFSHORE LOUISIANA
JOSEPH T. COMISKY
THE PENNSYLVANIA STATE UNIVERSITY
MAY, 2002
The Pennsylvania State University
The Graduate School
College of Earth and Mineral Sciences
PETROPHYSICAL ANALYSIS AND GEOLOGIC MODEL FOR THE
BULLWINKLE J SANDS WITH IMPLICATIONS FOR TIME-LAPSE
RESERVOIR MONITORING, GREEN CANYON BLOCK 65,
OFFSHORE LOUISIANA
A Thesis inGeosciences
by
Joseph T. Comisky
Copyright 2002 Joseph T. Comisky
Submitted in Partial Fulfillmentof the Requirements
for the Degree of
Master of Science
May 2002
We approve the thesis of Joseph T. Comisky.
Date of Signature
Peter B. FlemingsAssociate Professor of GeosciencesThesis Advisor
Phillip M. HalleckAssociate Professor of Petroleum and Natural Gas Engineering
Chris J. MaroneAssociate Professor of Geosciences
Peter DeinesProfessor of GeochemistryAssociate Head for Graduate Programs and Research
r the
c on
I grant The Pennsylvania State University the non-exclusive right to use this work fo
University’s own purposes and to make single copies of the work available to the publi
a not-for-profit basis if copies are not otherwise available.
Joseph T. Comisky
iii
mbi-
prop-
del to
prop-
ith an
onal
d J2
cut
es
ater
f the
1997
ctual
by
as-
much
e
peri-
ubble
cient
Abstract
The J1 and J2 reservoirs of the Bullwinkle field in Green Canyon 65 contain a co
nation of interconnected sheet and channel sands. Well log analysis shows that rock
erties are facies dependent and vary across the field. We used the depositional mo
break out the facies of the J1 and J2 into separate flow units, each with its own rock
erties. The thick, clean sheet sand facies has the most favorable rock properties, w
average porosity and permeability of 0.33 and 2400 mD, respectively. The depositi
model also sheds some insight into the nature of the connectivity between the J1 an
reservoirs. The J1 and J2 hydraulically communicate because channel facies have
through the shale separating both reservoirs.
Hydrocarbon production from the J1 and J2 reservoirs resulted in dynamic chang
which are resolvable with time-lapse seismic data. Between 1989 and 1997, the oil-w
contact (OWC) had moved vertically by as much as 284 m. We track the movement o
OWC using production and pulsed neutron logs and we show that the its position in
was not horizontal. The drainage scenario we develop from these data predict the a
produced volumes within 8%. The seismic properties of the J1 and J2 were effected
production because of changes in effective stress and saturation. We found using G
smann theory that water-swept areas exhibit an increase in acoustic impedance by as
as 30%. This 30% increase in acoustic impedance resulted in a 70% decrease in th
reflection coefficient at the top of the reservoirs. Areas in the reservoir which had ex
enced an increase in gas saturation due to the reservoir pressure falling below the b
point did not exhibit a noticeable change in acoustic impedance and reflection coeffi
between 1989 and 1997.
iv
Table of Contents
List of Figures vi
List of Tables xi
Acknowledgements xii
Chapter 1. INTRODUCTION 1
References 4
Chapter 2. FORMATION EVALUATION AND DEPOSITIONAL MODELFOR THE BULLWINKLE J SANDS, GREEN CANYON BLOCK
65, OFFSHORE LOUISIANA
6
Abstract 6
Introduction 6
Formation Evaluation 11
Porosity 11
Water Saturation 21
Permeability 29
Geologic Model 36
Facies and Depositional Environments 36
Amalgamated Sheet Sand 36
Layered Sheet Sand 36
Channel Sand 40
Levee 42
Geologic Evolution 42
Implications for Production and Sand Connectivity 44
Comparison with Other Deepwater Gulf of Mexico Fields 45
Flow Units 47
Conclusions 56
References 57
Nomenclature 60
Chapter 3. RESERVOIR MONITORING OF THE BULLWINKLE J SANDSUSING PRODUCTION DATA, PULSED NEUTRON LOGS,AND GASSMANN FLUID SUBSTITUTION MODELING WITHCOPMARISON TO TIME-LAPSE SEISMIC RESULTS, GREENCANYON BLOCK 65, OFFSHORE LOUISIANA
66
v
2
2
Abstract 66
Introduction 67
Production Characterization 69
J1 and J2 Initial Volumes 69
Drainage Analysis 72
OWC Movement: 1989-1992 78
OWC Movement: 1992-1993 78
OWC Movement: 1993-1994 80
OWC Movement: 1994-1995 80
OWC Movement: 1995-1996 82
OWC Movement: 1996-1997 82
General OWC Behavior 83
J1 and J2 Volumes, 1997 83
Drained Pay Volumes for the J1 and J2 87
Gassmann Model 92
Porosity, Effective Stress, and Vp Observations 95
Porosity, Effective Stress, and Kdry Observations 97
Effective Stress/Kdry Model 99
Velocity Model for Water-Saturated Rocks Under Pressure 10
Saturation Effects on Velocity and Amplitude 104
Coupled Pressure and Saturation Effects on the Acoustic Properties
107
Model of Acoustic Response Due to Water Sweep andChanges in Effective Stress
107
Modeling of Gas Exsolution and Effective Stress Changes 11
Summary of Gassmann Model 115
Conclusions 120
Nomenclature 121
References 126
Appendix A. PNC Log Methodology 129
References 132
Appendix B. Gassmann Model Outputs 133
vi
List of Figures
2.1 Bathymetric map showing the Gulf of Mexico and the BullwinkleField
7
2.2 J1 Structure map 9
2.3 J2 Structure map 10
2.4 Summary description of several types of turbidite reservoirs commonto the Gulf of Mexico
12
2.5 Type well log responses and whole core-measured porosities from theA32 BP well showing GR, ILD, NPHI, and RHOB
14
2.6 Crossplot of DPHI vs. whole core-measured porosites from the A32BP in the J3 Sand
15
2.7 Crossplot of DPHI vs. whole core-measured porosities from the J1and J2 sands in the A32 BP.
(a) DPHI vs. whole core data plotted from 0 to 1(b) DPHI vs. whole core data plotted only in the dashed area ofFigure 2.7a
16
2.8 Well log responses from the 65-1 18
2.9 DPHI vs. sidewall core porosities in oil and gas zones of the 65-1well
20
2.10 Well log responses from the A36 well in the J2 showing how F wascalculated from the ILD log.
23
2.11 Log-log plot of F vs.φ for the whole core data presented in Table 2.2and well log data from the A-36.
24
2.12 Log-log plot of Sw vs. I using the whole core data presented in Tables2.3 and 2.4
26
2.13 Pickett plot of resistivity data 28
2.14 Predicted Sw vs. measured Sw when a=0.72, n=1.85, and m=2.03 30
2.15 Semi-log crossplot of whole core measured K vs.φ for the A32 BPand 65-1 wells
32
vii
39
41
2.16 Crossplot of predicted K vs. measured K using whole core data fromthe A32 BP
34
2.17 Permeability transform presented in Equation 9 derived from stressedwhole core data from the A32 BP
(a) Permeability transform plotted with whole core data from theA32 BP(b) Permeability transform plotted with stressed whole core datafrom the A32 BP showing the dependence of K onφ for constantVsh
35
2.18 Type well log responses and facies map for the J2 sand(a) Type log response for the AS facies(b) Facies map of the J2 sand(c) Type log response for the LS facies(d) Type well log response for the CS facies(e) Type well log response for the LV facies
37
2.19 Type well log responses and facies map for the J1 sand(a) Type log response for the AS facies(b) Type well log response for the LV facies(c) Type log response for the LS facies(d) Type well log response for the CS facies(e) Facies map for the J1 sand
38
2.20 Cross sections flattened on the bottom of the J2 sand
2.21 Wireline responses of the CS and AS facies in the 109-1
2.22 Cross-sections through the J1 and J2 showing sand-on-sand contactsbetween the two reservoirs from the maps in Figures 2.18 and 2.19
46
2.23 Type well log responses for the flow units in the J2 sand(a) Type log for Unit 1(b) Flow unit map for the J2 sand(c) Type log for the Unit 2(d) Type logs for Unit 4(e) Type log for Unit 6
49
2.24 Type well log responses for the flow units in the J2 sand(a) Type log for Unit 1(b) Flow unit map for the J2 sand(c) Type log for the Unit 2(d) Type logs for Unit 4(e) Type log for Unit 6
50
viii
1
2
5
0
9
1
2.25 Wireline responses of the AS facies in the A32 BP 5
2.26 Wireline responses of the LS facies in the 65-1 5
2.27 Wireline responses of the LV facies in the 109-1-ST 5
3.1 J2 net pay in 1989 with seismic survey amplitudes 7
3.2 J1 net pay in 1989 71
3.3 Production data from the A32 BP 73
3.4 Date of initial water production, 50% water-cut, and shut-in for allwells producing from the J1 and J2
75
3.5 PNC log suite from the A32 BP 76
3.6 Floodout plot showing depths and times during which each well inthe J1 and J2 began showing water, either in the form of water pro-duction or from PNC log interpretation
77
3.7 Structural location of the OWC through time in the J2 7
3.8 Structural location of the OWC through time in the J1 8
3.9 Dip cross-section through the J1 and J2 sands illustrating verticalmovement of the OWC through time
84
3.10 Net pay map for the J2 in 1997 85
3.11 Net pay map for the J1 in 1997 86
3.12 Schematic illustrating the physical meaning of a net pay differencemap
88
3.13 Drained pay difference map for the J2 89
3.14 Drained pay difference map for the J1 90
3.15 Effective stress, porosity, and Vp observations from the J Sands(a) Porosity vs. effective stress(b) Vp vs. porosity(c) Vp vs. effective stress(d) Vp vs. porosity
96
ix
110
3.16 Relationships between Kdry, effective stress, and porosity for theBullwinkle J Sands
(a) Kdry vs. effective stress(b) Kdry vs. porosity
98
3.17 Kdry/effective stress model using laboratory data from Blangy (1992)(a) Kdry vs. effective stress(b) Kdry vs. effective stress paths
100
3.18 Vp/effective stress model(a) Vp vs. effective stress(b) Vp vs. effective stress paths
103
3.19 Expected changes in acoustic properties due to changes in Sw(a) Vp vs. Sw(b) Impedance vs. Sw(c) RFC vs. Sw
105
3.20 Acoustic property changes in the 109-1 J2 as a function of Sw andeffective stress
(a) Vp as a function of Sw and effective stress(b) Impedance as a function of Sw and effective stress(c) RFC as a function of Sw and effective stress
109
3.21 Gassmann fluid substitution logs for the J2 and J3 Sands in the 109-1
3.22 Seismic model for water-sweep in the 109-1 J2 Sand(a) Extracted traces from the 1988 survey and synthetic trace(b) Comparison of observed and modeled seismic differences
111
3.23 Acoustic property changes in the A33 as a function of Sw and effec-tive stress
(a) Vp as a function of Sw and effective stress(b) Impedance as a function of Sw and effective stress(c) RFC as a function of Sw and effective stress
114
3.24 Seismic model for gas exsolution in the A33(a) Extracted traces from the 1988 survey and synthetic trace(b) Comparison of observed and modeled seismic differences
116
x
1
3.25 Acoustic properties of the J2 as a function of depth at 1989 and 1997conditions
(a) Vp as a function depth(b) Impedance as a function depth(c) RFC as a function of depth
117
A.1 Openhole and PNC log analysis in the A-37 13
xi
1
3
5
3
125
25
3
4
List of Tables
2.1 Average petrophysical properties for each well 6
2.2 Whole core data from the A32 BP and 65-1 ST1 wells used in the anal-ysis of electrical resistivity data.
62
2.3 Drainage and imbibition data from the A32 BP and 65-1 ST1 wholecores
63
2.4 Resisitivity Data from A32 BP and 65-1 ST1 whole cores 6
2.5 Whole core porosity and permeability measured under 2100 psi effec-tive stress from the A32 BP well. Vsh was taken from GR log.
64
2.6 Average petrophysical properties for each flow unit 6
3.1 Reservoir Volumes for the J1 and J2 RB reservoirs at initial (1989) andpost-production (1997) conditions.
122
3.2 Production data summary for the J1 and J2 RB 12
3.3 Summary of sonic and porosity log data taken from the water leg of theJ1, J2 and J3 sands
124
3.4 Fluid properties used for investigating the influence on hydrocarbon sat-uration on the acoustic properties of the 109-1 J2 sand.
124
3.5 Elastic properties of the 109-1 J2 used in Gassmann modeling
3.6 Acoustic properties of the A33 used in Gassmann modeling 1
B.1 Parameters used for 1989 Conditions 13
B.2 Parameters used for 1997 Conditions 13
xii
spon-
,
ime-
Shell
oft-
hysi-
ny-
d to
o Tur-
Geo-
y fel-
ork
any
and
ther
s of
ir
Acknowledgements
This research is part of the Penn State Petroleum Geosystems Initiative, which is
sored by Shell Exploration and Production Company (SEPCo), the Shell Foundation
IBM, and Landmark Graphics. Additional support was provided by the Penn State T
Lapse Consortium, whose members include Chevron, Conoco, Statoil, and Texaco.
were very helpful in providing and releasing much of the data used in this project. S
ware support was supplied by Landmark Graphics Corporation and Paradigm Geop
cal.
I would first like to thank my advisor, Peter Flemings, for introducing me to the ma
faceted problems in petroleum geology and how they are solved. I am also indebte
my thesis committee members, Phil Halleck and Chris Marone. Thanks also goes t
gay Ertekin and Terry Engelder for their additional input and advice to the Petroleum
systems Initiative.
My research would not have been possible without the input and hard work of m
low Geosystems teammates, Alastair Swanston and Kevin Best. Much of Alastair’s w
lays the foundation for the time-lapse analysis of Chapter 3. Kevin and I have spent m
hours discussing and working through the reservoir engineering aspects of Bullwinkle
his insight, hard work, and diligence has been invaluable. Rachel Altemus and Hea
Johnson keep everything running and organized and have always been there in time
need. Additional thanks goes to Brandon Dugan, Jacek Lupa, and Xiaoli Liu for the
insights into compaction and fluid flow.
xiii
r-
to
at
Bill
nal-
e
ll of
The geoscientists at Shell who have helped the team along our two year journey
include Dave Miller, Mahdu Kholi, Tucker Burkhart, A.J. Durani, Tom Wilson, Mike Ba
onovic and Mike Kuzio.
Additional thanks go to the Formation Evaluation group at the Chevron Petroleum
Technology Company in San Ramon, CA. Bill Corea and Barry Reik introduced me
some of the more complicated aspects of well log analysis and made my internship
Chevron very rewarding. I would also like to thank Bruce Bilodeau, Simon Stonard,
Ballengee, and Rick Abegg at Chevron for all of their advice on careers and well log a
ysis.
Finally, I would like to thank my family and friends for all of their support and positiv
karma. My parents have been an instrumental part of my life and I thank them for a
their help.
1
Bull-
J
core
and I
ati-
d to
abil-
amic
cost
e at
high
reser-
ing
na-
ull-
ysis
and
ater-
eep
Chapter 1
INTRODUCTION
This thesis addresses both the static and dynamic behavior of the J Sands in the
winkle Field. Chapter 2 begins at the grain scale, where the initial conditions of the
Sands are characterized in terms of porosity, permeability, and water saturation using
and well log data. A depositional model for the turbiditic J Sands is then presented
show that rock properties in the field are spatially controlled by the distribution of str
graphic facies. The rock property observations and depositional model are then use
create the initial reservoir simulation model which incorporates the stratigraphic vari
ity inherent in deepwater turbidite reservoir systems. Chapter 3 characterizes the dyn
behavior of the Bullwinkle J Sands observed at the well and seismic scale. The high
of exploring and producing in the deepwater Gulf of Mexico requires that wells produc
rates greater than 5000 barrels of oil per day to be profitable (Lawrence, 1994). Such
sustained flow rates are achieved more frequently when the knowledge base of the
voir system is optimized over this wide variety of spatial and temporal scales.
The importance of relating different types of data at a variety of scales is a recurr
theme throughout this thesis. We relate core-measured properties to the well log sig
tures and then use these well log signatures to devise a depositional model for the B
winkle J Sands. Production data, cased hole well logs, and time-lapse seismic anal
provide us with tools which we used to characterize the dynamic behavior of the J S
reservoirs. Rock physics modeling aided in interpreting the time-lapse signature of w
sweep and gas exsolution. The rock physics model predicted that areas of water sw
2
water
in the
93)
d in
tional
er-
fields
nts
in
ron-
pes
h
ier
func-
er-
ty in
t the
how
fset)
experienced a dramatic decrease in seismic amplitude through time. These areas of
sweep were also verified by the production data and cased hole log analysis.
Characterization of deepwater turbidites has been the focus of many field studies
Gulf of Mexico (Holman and Robertson, 1994; Mahaffie, 1994). O’Connell et al. (19
addressed the importance of seismic survey design and acquisition parameters use
imaging the Bullwinkle J Sands. Holman and Robertson (1994) presented a deposi
model for the Bullwinkle J Sands and showed how their interpretation of turbidite res
voir connectivity and architecture fit into the slope mini-basin model of Prather et al.
(1998). McGee et al. (1994) and Kendrick (2000) characterized several deepwater
and show how the spatial and temporal changes in turbidite depositional environme
effect the production strategies used in each case. A similar study for the K40 sand
South Timbalier Block 295 demonstrated how subsurface turbidite depositional envi
ments can be compared with outcrop analogs (Hoover, 1997).
Rock properties for deepwater Gulf of Mexico turbidites are favorable for these ty
of integrated reservoir studies. In general, they consist of unconsolidated sands wit
extremely high porosity (0.28 to 0.34) and permeability (100 to 3000 mD). Osterme
(1995) studied the changes in porosity and permeability for these types of sands as a
tion of compressibility and effective stress. He found that highly porous turbidite res
voirs have extremely high compressibilities and that reduction in porosity due to
compaction drastically reduces permeability. Flemings et al. (2001) show that porosi
the J3 sand at Bullwinkle is stress controlled, in that higher porosity sands are found a
top of structure where the effective stress is lower. Blangy (1992) and Clark (1992) s
that direct hydrocarbon indicators such as bright spots and AVO (amplitude versus of
3
cous-
ears
es of
me.
on
n and
mi-
ter
l log
dy of
w)
ys.
n sim-
l out-
ain-
are a result of highly porous unconsolidated hydrocarbon sands having much lower a
tic impedances than the shales which bound them.
The dynamic behavior of reservoirs has been studied extensively in the past few y
in the form of time-lapse (4D) studies. Hoover et al., (1999) performed an integrated
time-lapse analysis for the K40 channel turbidite reservoir and demonstrated that zon
water-sweep were associated with strong decrease in seismic amplitudes through ti
Hoover et al. (1999) also tracked oil-water contact (OWC) movement using producti
and log data. Packwood (1997) used a rock physics model which combined saturatio
pressure changes to show how coning of gas during primary oil production was seis
cally visible for very high porosity rocks. Landro et al. (1999) demonstrated how wa
movement predicted on the basis of time-lapse seismic data were confirmed by wel
and production data observations. Behrens et al.(2001) performed a time-lapse stu
the Bay Marchand field in the Gulf of Mexico field and found that amplitude changes
through time were consistent with production data and rock physics models.
This thesis is part of a larger study of the Bullwinkle field. Swanston et al. (in revie
present a detailed time-lapse study of the Bullwinkle field using multiple seismic surve
They show that time-lapse analysis provides the best results when two surveys shot i
ilar directions are normalized and differenced. Best (2002) used the geologic mode
lined in this thesis as an input for the J1/J2 reservoir simulation. He found that
compaction-induced water influx and sand connectivity has played a major role in m
taining pressures in the reservoir during production.
4
ser-65,
in
ndan-
is ofpse
Tim-smic
lds,Char-
ks
o, Tur-
ery,
ogic
Tur-
References
Best, K.D., 2002, Development of an integrated model for compaction/water drive revoirs and its application to the J1 and J2 Sand at Bullwinkle, Green Canyon BlockGulf of Mexico: Masters thesis, The Pennsylvania State University.
Flemings, P.B., Comisky, J., Liu, X., and Lupa, J.A., 2001, Stress-controlled porosityoverpressured sands at Bullwinkle (GC65), Deepwater GoM.Offshore TechnologyConference, April 30- May 3, 2001.
Holman, W.E., and Robertson, S.S., 1994, Field development, depositional model, aproduction performance of the turbiditic “J” Sands at Prospect Bullwinkle, Green Cyon 65 Field, outer-shelf Gulf of Mexico,GCSSEPM Foundation 15th AnnualResearch Conference, Submarine Fans and Turbidite Systems, December 4-7, p. 139-150.
Hoover, A.R., Burkhart, T.B., Flemings, P.B., 1999, Reservoir and production analysthe K40 sand, South Timbalier 295, offshore Louisiana, with comparison to time-la(4-D) seismic results.AAPG Bulletin, v. 83, no. 10, pp. 1624-1641.
Hoover, A.R., 1997, Reservoir and production characteristics of the K40 sand, Southbalier 295, offshore Louisiana with outcrop analogues and comparison to 4D seiresults: Masters thesis, The Pennsylvania State University.
Kendrick, J.W., 2000, Turbidite reservoir architecture in the northern Gulf of Mexicodeepwater: insights from the development of Auger, Tahoe, and Ram/Powell FieGCSSEPM Foundation 20th Annual Research Conference Advanced Reservoir acterization, December 5-8, pp. 450-468.
Landro, M., Solheim, O.A., Hilde, E., Ekren, B.O., and Stronen, L.K., 1999, The Gulfa4D seismic study: Petroleum Geoscience, vol 5, pp. 213 - 226.
Lawrence, D.T., 1994, Turbidite technical challenges in the deepwater Gulf of MexicGCSSEPM Foundation 15th Annual Research Conference, Submarine Fans andbidite Systems, December 4-7, pp. 217-219.
Mahaffie, M.J., 1994, Reservoir classification for turbidite intervals at the Mars discovMississippi Canyon 807, Gulf of Mexico.GCSSEPM Foundation 15th AnnualResearch Conference, Submarine Fans and Turbidite Systems,December 4-7, p. 233-244.
McGee, D.T., Bilinski, P.B., Gary, P.S., Pfeiffer, D.S., and Sheiman. J.L., 1994, Geolmodels and reservoir geometries of Auger field, deepwater Gulf of Mexico,GCSSEPM Foundation 15th Annual Research Conference, Submarine Fans andbidite Systems, December 4-7, p. 245-256.
5
ros-
g
Ostermeier, R.M., 1995, Deepwater Gulf of Mexico turbidite compaction effects on poity and permeability.SPE Formation Evaluation, v. 10, No. 2, pp. 79-85.
Packwood, J.L., 1996, Feasibility of hydrocarbon recovery monitoring with increasinrock frame stiffness: SEG Expanded Abstract, pp. 876 - 878.
6
mbi-
all into
ive
alysis
d the
each
ble
spec-
tivity
e chan-
n
pths
as
Chapter 2
FORMATION EVALUATION AND DEPOSITIONAL MODEL FORTHE BULLWINKLE J SANDS, GREEN CANYON BLOCK 65, OFF-
SHORE LOUISIANA
Abstract
The J1 and J2 reservoirs of the Bullwinkle field in Green Canyon 65 contain a co
nation of interconnected sheet and channel sand facies. The J1 and J2 reservoirs f
the slope turbidite model of Prather et al. (1998) where deposition of laterally extens
sheet sands was followed by periods of channel cutting and deposition. Well log an
shows that rock properties are facies dependent and vary across the field. We use
depositional model to break out the facies of the J1 and J2 into separate flow units,
with its own rock properties. The thick, clean sheet sand facies has the most favora
rock properties, with an average porosity and permeability of 0.33 and 2400 mD, re
tively. The depositional model also sheds some insight into the nature of the connec
between the J1 and J2 reservoirs. The J1 and J2 hydraulically communicate becaus
nel facies have cut through the shale separating both reservoirs.
Introduction
The Bullwinkle field is located 240 km southwest of New Orleans in Green Canyo
Blocks 64, 65, and 109 (Figure 2.1). It is located on the slope-shelf break, in water de
ranging from 400 to 550 m (O’Connell et al., 1993). The initial discovery well (65-1) w
7
00 -
Figure 2.1 Bathymetric map showing the Gulf of Mexico and the Bullwinkle Field.Bathymetry contours are in meters. Bullwinkle lies 240 km southwest of New Orleans in 4550 m (1353 ft) water depth on the shelf/slope break.-2000
0
0
Abyssal Plain
264o
24o
26o
28o
30o N
266o 268o 270o 272o
Houston New Orleans
Mississippi Canyon
Sigsbee Escarpment
Bullwinkle
0 100 200
kilometers
3000
2000
1000
2000
8
d the
r the
ra-
9
r res-
ves
an-
ce
J1
-oil
n-
a
u-
tural
m
e J2
re
he
drilled in 1983 and it penetrated the J1 and J2 sands. O’Connell et al. (1993) describe
acquisition and interpretation of two orthogonal 3-D seismic surveys shot in 1988 fo
Bullwinkle field which were used for initial development mapping. Several other explo
tion wells (109-1, 109-1ST, 65-1-ST) were drilled and initial production began in 198
from the Bullwinkle platform. Production from the J Sands and several other smalle
ervoirs have produced over 130 MMBOE (million barrels of oil equivalent) with reser
estimated at 160 MMBOE (Holman and Robertson, 1994).
The J1 reservoir is located on the western flank of the basin, primarily in Green C
yon Blocks 109 and 65 (Figure 2.2). It has approximately 600 m (2000 ft) of vertical
relief with an original oil-water contact (OOWC) located at 3755 m (12230 ft) subsurfa
total vertical depth (TVDSS). A flow barrier separates the J1 into two reservoirs, the
RA and J1 RB, each with its own type of hydrocarbon fluids. The J1 RA original gas
contact (OGOC) is located at 3730 m. The presence of a gas cap in the J1 RA is co
firmed by well logs in the 65-1 and fluid samples. The J1 RB initially did not contain
gas cap. Well and production data in the J1 RB confirm that it was initially undersat
rated.
The J2 sand is volumetrically larger than the J1, but shows many of the same struc
characteristics (Figure 2.3). Seismic data and well control place the OOWC at 3784
(12415 ft). The J2 is also divided into two separate reservoirs (J2 RA and J2 RB). Th
RB is initially undersaturated and is separated from the J2 RA by a flow barrier (Figu
2.3). The J2 RA is a gas cap reservoir, with an OGOC located at 3714 m (3713). T
9
3755een Theles
ed the09-1,
Figure 2.2 J1 structure map based on well and seismic data. The outline of the J1 sandrepresents the edge of sand where its thickness is equal to 0 m. The OOWC in the J1 is atm (12320 ft) TVDSS and was imaged with seismic data. A barrier (solid black lines betwthe A38 ST and A60 wells) separates the J1 reservoir into the J1 RA and RB reservoirs. OGOC in the J1 RA is located at 3730 m. A thin oil rim is present in the J1 RA. Closed circrepresent wells which produce from the J1. Open circles represent wells which penetratJ1, but never produced from it. Wells located on the map which do not penetrate the J1 (1A2 BP, etc.) penetrate the top of the J2.
A31
A33
A32 BP
A38
A38 ST A4 BP65-1 ST
A60
65-1
A35
A3 BPA1
A41
A37
65
109108
64
0 0.5 1.0
(Kilometers)
N
A5 BP
109-1
A2 BP
C.I. = 50 m
A34
A11 BP
1ST
A42 ST
A39
A36
A10
A9
3500 36
00
3700
3800
3400
3300
OOWC
OGOC
J1 RA
J1 RB
10
is the J2arrierd by
Figure 2.3 J2 structure map based on well and seismic data. The outline of the J2 sandinferred 0’ thickness polygon. The OOWC in the J2 is at 3784 m TVDSS (12415 ft). Thesand is divided into two separate reservoirs (J2 RA and RB) and are separated by a flow bin the northeast section of the field. The OGOC is at 3714 m (12185 ft) and is constrainewell log data in the 65-1 exploration well.
N
109-1 ST1A1
A35
A11 BP
A41
A33A34
A37
A5 BP
A36
A3 BP109-1
A32 BP
A2 BP
A38
A10
A4 BP
65-1 ST
A60
65-1
A9
Injector
Producer
Exploration
0 0.5 1.0
(kilometers)
A42ST
A39A31
65
109108
64
C.I. = 50 m
3900
3800
3700
36003500
3400
OOWC
OGOC
J2 RA
J2 RB
11
in
han-
hitec-
re
). The
cribed
ell
ture,
facies
are
the
ort and
ulk
OGOC in the J2 RA was imaged with porosity logs in the initial exploration well (65-1
Figure 2.3).
The Bullwinkle J1 and J2 sands are composed of both amalgamated sheet and c
nelized turbidite sands. Sheet sands within the J1 and J2 follow the same type of arc
ture as the Auger Field described by McGee et al. (1994) and Kendrick (2000), whe
continuous sheet sands are vertically separated by thick muds and shales (Figure 2.4
log character of the channelized sands in the J1 and J2 are similar to the sands des
by Kendrick (2000) for the Ram-Powell field. However, the reservoirs within Ram-Pow
are highly compartmentalized due to the channelized nature of the reservoir architec
where perched water contacts and depletion style reservoirs are common.
The J1 and J2 sands are both strong water-drive reservoirs due to the sheet sand
which extend throughout the Bullwinkle basin. Some sheet sand individual reservoirs
not in hydraulic communication due to the thick layers of shale separating them. In
case of the J1 and J2, however, laterally extensive sheet sands provide water supp
the channel facies provide sand-on-sand contacts making hydraulic communication
between both reservoirs possible (Figure 2.4).
Formation Evaluation
Porosity
Log-based porosity calculations for the Bullwinkle J Sands were taken from the b
density log where
. (2.1)φρg ρb–
ρg ρ f–-----------------=
12
lf of
Figure 2.4 Summary description of several types of turbidite reservoirs common to the GuMexico.Channel Sands
Sand-on-Sand Connectivity
Compartmentalization is common, although vertical communication is possible.
Reservoirs have small, limited aquifers and perched water. Mostly deprtion-drive.
Large reservoirs with high degree of lateral continuity. Thick muds and shales inhibit vertical communication between sands
Reservoir have large aquifers with strong water-drive.
Sheet Sands
High degree of lateralcontinuity.
Vertical communication between sands is uncommon
High degree of lateralcontinuity
Channelization provides sand-on-sand contact and makesvertical communication possible
Large reservoirs with high degree of lateral continuity. Thick muds and shales do inhibit vertical commincation in some places. Channelization in some areas provide sand-on-sand contact and vertical communication between individual sands is possible
Reservoir have large aquifers with strong water-drive.
Description Stratal Architecture Examples
Auger "S", "Q", and "R" reservoirs, GB 426, 427, 470, and 471 (McGee et al., 1994)
Mars "Lower Green" reservoir, MC 807 (Mahaffie, 1994)
Ram/Powell "N" reservoir,VK 912 (Kendrick, 2000)
Jolliet, GC 184 (Schneider and Clifton, 1995)
Bullwinkle "J1" and "J2" reservoirs, GC 65,109(Holman and Robertson,1994)
Mars "Upper and Lower Yellow" reservoirs, MC 807(Mahaffie, 1994)
13
as
tool
sity
2.5).
ree-
uid
te
. A
(Bat-
.u.)
en a
re oil
e 2.7)
cc
fluid
0.98
ons
ed in
A grain density (ρg) of 2.65 g/cc (quartz) was assumed for all calculations. This value w
recorded by whole core pycnometer measurements. Fluid density (ρf) depends on the sat-
uration of brine and hydrocarbons present in the invaded zone where the bulk density
measures (Gaymard and Poupon, 1968; Wiley and Patchett, 1994).
Fluid density in the aquifer was estimated by calibrating log-derived density poro
calculations with stressed whole core measured porosities in the A32 BP well (Figure
Log-derived density porosities (DPHI) and whole core porosities showed the best ag
ment when a fluid density of 1.05 g/cc was used with Equation 2.1 (Figure 2.6). This fl
density is interpreted to result from a combination of high (230 kppm) salinity conna
water and lower (10-20 ppm) salinity mud filtrate which is present in the invaded zone
brine with a 230 kppm salinity has a density of 1.16 g/cc under reservoir conditions
zle and Wang, 1992). The apparent DPHI was overpredicted by ~ 2 porosity units (p
when a fluid density of 1.20 g/cc was assumed whereas DPHI is underpredicted wh
lower fluid density (0.70 in Figure 2.6) was assumed.
We used a similar approach to predict the fluid density in the J1 and J2 sands whe
was present in the A32 BP (Figure 2.5). There was more scatter in these data (Figur
and we show that DPHI calculated assuming fluid densities of 1.20 g/cc and 0.70 g/
encompasses almost all of the measurements. However, we aim to calibrate a single
density in the J1 and J2 oil leg for use with Equation 2.1. We chose a fluid density of
g/cc (Figure 2.7) because it minimized the error between log-derived DPHI calculati
and whole core porosity measurements. A fluid density of 0.73 g/cc would be expect
14
well
gshe60
Figure 2.5 Type well log responses and whole core-measured porosities from the A32 BPshowing gamma-ray (GR), resistivity (ILD), neutron porosity (NPHI), and bulk density(RHOB). J1 and J2 are both hydrocarbon sands. The J3 is water-saturated. Porosity lo(NPHI and RHOB in track 3) are shown with stressed whole core measured porosities. TRHOB log is scaled in sandstone porosity units, with 1.65 g/cc equivalent to a porosity 0.when a grain density of 2.65 g/cc and fluid density of 1.00 g/cc are assumed.
J3
J2
J1
METERS
Core Porosity
15
eksing
Figure 2.6 Crossplot of density porosity (DPHI) vs. whole core measured porosity from thA32 BP in the J3 sand. Each circle has a core-measured porosity and log-measured buldensity associated with it. DPHI for the circles was calculated from the bulk density log uEquation 2.1 assuming aρf of 1.05 g/cc. Apparent DPHI was also calculated from Equation2.1 assuming different values forρf (1.20 g/cc and 0.70 g/cc).
0.30 0.32 0.34 0.36 0.38 0.40
0.30
0.32
0.34
0.36
0.38
0.40
DP
HI
Core Porosity
ρ = 1.20 g/cc
f
ρ = 1.05 g/cc
f
ρ = 0.70 g/cc
f
0.280.28
16
coreanhow a
Figure 2.7 Crossplot of log-predicted density porosity (DPHI) vs. stressed whole coreporosities in the J1 and J2 sands from the A32 BP well (Figure 2.5). a) DPHI and wholeporosities have the best agreement when aρf of 0.98 g/cc is used with Equation 2.1. The datshow a very wide range of possibleρf (1.20 g/cc to 0.70 g/cc). b) Enlargement of boxed regioin Figure 2.7a. The core data are broken into J1 and J2 samples. Data from both sands sscatter about the 1:1 correlation line, corresponding to aρf of 0.98 g/cc.
0
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
DP
HI
Core Porosity
DP
HI
0.22 0.26 0.30 0.34 0.38
0.22
0.26
0.30
0.34
0.38 J1J2
Core Porosity
ρ = 1.20 g/cc
f
ρ = 0.98 g/cc
f
ρ = 0.70 g/cc
f
0.36
0.32
0.28
0.24
0.20
0.40
0 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
ρ = 1.20 g/cc
f
ρ = 0.98 g/cc
f
ρ = 0.70 g/cc
f
0.20 0.24 0.28 0.32 0.36 0.40
a)
b)
17
0.65
uid
l leg
to
i-
ma-
ume
g/cc.
ng
its vir-
ewall
bulk
roce-
he J1
re
ints
o-one
rify
the uninvaded zone of the oil-filled J Sands assuming typical values for oil density (
g/cc), connate water density (1.16 g/cc) and water saturation (0.15). However, the fl
density we calibrated using whole core and bulk density log measurements in the oi
(0.98 g/cc) is considerably higher than 0.73 g/cc. We infer that this difference is due
invasion of mud filtrate into the formation during drilling. The bulk density tool invest
gates the invaded zone of the formation, where mud filtrate flushes out the virgin for
tion fluids and leaves behind irreducible water and residual hydrocarbons. If we ass
that irreducible water (Sw = 0.15), mud filtrate (pmf = 1.05 g/cc), and residual oil (Sor =
0.25) are present in the invaded zone, we would expect a fluid density closer to 0.97
This value for fluid density in the oil leg is much closer to the value we calibrated usi
DPHI and core measurements and suggests that the formation has been flushed of
gin fluids during the drilling process.
Fluid density in the gas cap of the J1 and J2 reservoirs was constrained using sid
core data from the 65-1 well. The J1 in the 65-1 is interpreted as a gas zone due to
density/neutron porosity (RHOB/NPHI) crossover (Figure 2.8). We used the same p
dure presented in Figures 2.6 and 2.7 to predict the fluid density in the gas zone of t
and J2. A fluid density of 0.68 g/cc most closely matched the DPHI and sidewall co
porosities for the 65-1 in the gas zones (Figure 2.9). A fluid density of 0.98 g/cc was
assumed for calculating DPHI in the oil leg of the J2 from the 65-1. The oil leg data po
show the same type of scatter as in Figure 2.7 , but are distributed around the one-t
correlation line in Figure 2.9 . The oil leg data points in Figure 2.9 independently ve
the fluid density of 0.98 g/cc we calibrated in the A32 BP.
18
ones.
Figure 2.8 Well log responses from the 65-1 well which penetrated the J1 and J2 sands(Figures 2.2 and 2.3). Apparent RHOB/NPHI crossover in the J1 and J2 represent gas zSidewall core measurements of porosity show that NPHI is underpredicted and DPHI isoverpredicted in the gas zones assuming aρf of 1.00 g/cc for DPHI. The original gas-oilcontact (OGOC) was imaged in the J2 at 3714 m (12185 ft).Sidewall Por
METERS
J1
J2 OGOC
}
Gas Effect
}}
RHOB1.65 2.65G/C3
19
me-
lem.
found
appro-
leg
e
PHI
en
HI/
, we
ed
ch
erage
eabil-
Castle and Byrnes (1998) used this approach to predict porosities in the low per
ability Medina Sandstone of Northwestern Pennsylvania where gas invasion is a prob
Avseth (2000) documented the effects of invasion on North Sea turbidite sands and
the best approach was to use core and bulk density measurements to back calculate
priate fluid densities.
An approach used in Flemings et al. (2001) which predicted fluid density in the oil
of the J3 without the use of core data was applied to the J1 and J2 and agree with thρf
calibration of 0.98 g/cc in Figure 2.7. In their approach, a trend between NPHI and D
was established in the water leg of the J3 using a fluid density of 1.05 g/cc. They th
found that a fluid density of 0.94 g/cc in the oil leg of the J3 reproduced the same NP
DPHI trend as seen in the water leg. When that same method was applied to the J2
found that a fluid density of 0.98 g/cc in the oil leg matched the NPHI/DPHI trend deriv
in the water leg.
Average values of porosity calculated from the bulk density log were taken at ea
penetration of the J1 and J2 in reservoir zones and are shown in Table 2.1 . The av
porosity was taken for each well in the clean sand zones where the log-derived perm
ity was greater than 10 mD. Equation 2.1 was solved assuming aρg of 2.65 g/cc for all
wells. A ρf of 0.98 was used in the oil legs of the J1 and J2 and aρf of 1.05 g/cc was used
in the water legs. Aρf of 0.68 g/cc was used in the gas zones of the 65-1.
20
sa
Figure 2.9 65-1 sidewall core porosities in oil and gas zones. DPHI in the gas zones wacalculated using Equation 2.1 using aρf of 0.68 g/cc. DPHI in oil zones was calculated usingρf of 0.98 g/cc.
0.24 0.28 0.32 0.36
0.24
0.28
0.32
0.36Gas (0.68 g/cc)
Oil (0.98 g/cc)D
PH
I
Core Porosity
21
fec-
s that
ro-
53;
mula
tones.
prac-
in et
qua-
er,
Water Saturation
Archie’s equations (Archie, 1942) were used to calculate water saturation (Sw) at each
well with porosity and resistivity logs. The underlying assumption when applying
Archie’s Law is that electrical conduction takes place through brine trapped in the ef
tive porosity (Edmundson, 1988). This assumption limits this approach to clean sand
do not contain electrically conducting clays.
Archie (1942) proposed that the resistivity of a brine-saturated rock (Ro) is propor-
tional to the resistivity of the brine in the pores (Rw ):
, (2.2)
where the formation factor (F) was empirically constrained. The formation factor is p
portional to the porosity (Archie, 1942; Winsauer et. al., 1952; Wyllie and Gregory, 19
Carothers, 1968):
, (2.3)
where a and m are both empirical constants. Equation 2.3 is called the Humble for
and Winsauer et al. (1952) suggested a = 0.62 and m = 2.15 for a majority of sands
The Humble formula has become widely used in the industry and is routinely put to
tice in cases where there are no core data available for empirical calibrations (Dvork
al., 1999).
The formation factor can be directly calculated when only brine is present using E
tion 2.2. In this approach, the deep resistivity log (ILD) is assumed to record Ro and the
brine resistivity (Rw) is interpreted from standard log interpretation charts (Schlumberg
Ro FRw=
Fa
φm------=
22
late F
nd
ents
s,
was
e
or by
ls
-
al.,
1989) given a salinity and temperature. For the Bullwinkle J Sands, Rw has an average
value of 0.022 ohm-m with brine salinity ranging from 210 to 230 kppm at 160o F. The
A36 well penetrated the J2 sand in the water leg (Figure 2.3) and was used to calcu
directly from the ILD measurement. In the A36, F ranges from 10 to 30 for the J2 sa
(Figure 2.10).
The formation factor (F) was also calculated directly from whole core measurem
from the A32 BP and 65-1 ST1 wells using Equation 2.2 (Table 2.2). For these core
each sample was 100% saturated with brine and its brine-filled resistivity (Ro) was mea-
sured. A brine salinity of 210-230 kppm NaCl was used. The resistivity of the brine
measured at laboratory conditions (75o F) and ranges from 0.0438 to 0.0453 ohm-m. Th
formation factor (F) was then calculated using Equation 2.2 and ranges from 5.71 to
14.00.
Once the formation factor (F) was calculated, the constants a and m were solved f
rearranging Equation 2.3,
. (2.4)
A log-log plot of F vs.φ for the whole core data and the log data from the A36 well revea
that the intercept a = 0.72 and slope m = 2.06 with an R2 of 0.80 (Figure 2.11). These val
ues for a and m are similar to the Humble formula (a = 0.65, m = 2.16; Winsauer et
1952)
F( )log a( )log m φ( )log–=
23
ow
ity
nsity
Figure 2.10 Well logs from the A36 showing the J2 sand. The J2 interval at the A-36 is belthe OOWC and the deep resistivity tool (ILD) is assumed to be measuring the water-filledresistivity (Ro). The formation factor (F) was calculated by using a value for water-resistiv(Rw) and the ILD measurement. An Rw of 0.022 ohm-m was used because it represents theaverage water-resistivity at reservoir conditions along with Equation 2.1 to determine aformation factor. DPHI was calculated assuming a grain density of 2.65 g/cc and fluid deof 1.05 g/cc.
METERSDPHI
J2
Formation Factor (F)
24
logake
on an this bothta
Figure 2.11 Log-log plot of formation factor (F) as a function of porosity (φ) for the wholecore date presented in Table 2.2 and well log data from the A-36 (Figure 2.10). This log-plot is utilized when calibrating the constants a and m for Equation 2.3. The form used to mthe above figure is shown in Equation 2.4. When porosity and formation factor are plottedlog-log graph as above, the slope is equal to the constant m from Equations 2.3 and 2.4. Icase, an RMA (reduced major axis) fit to the data is used because there is uncertainty intheφ and F measurements from the whole core and well log data. The RMA fit to this dareveal that m = 2.06 and a = 0.72 with a correlation (R2) of 0.80.
100
101
102
F
φ0.20 0.30 0.40
Whole Core (65-1 ST1)Whole Core (A32 BP)Well Logs (A-36)
log(F) = -0.1424 - 2.06 log(φ) a = 0.72 m = 2.06 R = 0.80
2
25
t S
rved
satu-
a-
nage
d sat-
tests
e
ly. A
For rocks partially saturated with brine and hydrocarbon, Archie (1942) found thaw
was proportional to the resistivity ratio (I),
, (2.5)
where n is the saturation exponent. The resistivity ratio (I) is defined as
, (2.6)
where Ro is the resistivity of the rock when it is brine-filled and Rt is the resistivity of that
same rock when partially saturated with brine and hydrocarbon. Archie (1942) obse
that for water-wet Gulf Coast sands, n = 2.
Whole core data from both the A32 BP and 65-1 ST1 were used to determine the
ration exponent (n) in cases where Sw and resistivity ratio (I) were measured under labor
tory conditions (Tables 2.3 and 2.4). The data in Table 2.3 were acquired during drai
and imbibition tests on 9 whole core samples. The remaining resistivity index (I) an
uration data used to constrain the saturation exponent (n) were taken under various
and are presented in Table 2.4.
On log-log plot of Sw vs. I, the inverse of the slope is equal to n (Figure 2.12). Th
slope of the best fit line in Figure 2.12 reveals that n = 1.85 fits the data most close
saturation exponent (n) of 2 is also shown in Figure 2.12 for reference.
Swn–
I=
IRt
Ro------=
26
le.l
or n
Figure 2.12 Log-log plot of water saturation (Sw) vs. the resistivity ratio (I) using the whocore data presented in Tables 2.3 and 2.4. The resistivity ratio is defined in Equation 2.5According to Equation 2.5, on a log-log plot of Sw vs. I, the inverse of the slope should be equato the saturation exponent (n). A saturation exponent of 1.85 fit the data. A typical value fis 2 and is shown in the above plot as a comparison.
100
101
102
10−1
100
I
Sw
65 1ST Drainage 65−1ST Imbibition65−1−ST Other A32 BP Drainage A32BP Imbibition A32BP Other
n = 2
n = 1.85
27
t
rchie
tion
gure
ty
in pre-
s
ith
l-
ter
the
Pickett (1973) combined Equations 2.3 through 2.6 to show how bothφ and Sw affect
Rt:
. (2.7)
On a log-log plot of Rt vs.φ , the water saturation is represented by a series of straigh
lines, all with a slope equal to the constant m. This three-dimensional view of the A
equation shows the sensitivity of log-based Sw calculations to both its measured porosity
and resistivity.
The overall resistivity of a rock is dependent on both the porosity and water satura
(Pickett, 1973; Bhattacharya et al., 1999), as is represented by the Pickett plot in Fi
2.13 . As Rt decreases, the distance between the iso-Sw lines decreases on a Pickett plot.
This reveals that higher Sw, the true resistivity of the rock is more dependent on porosi
rather than Sw. At lower Sw, the distance between the iso-Sw lines in Figure 2.13 is
greater. This suggests that uncertainty in porosity does not severely produce errors
dicted Sw when saturations are at irreducible conditions. Whole core data from Table
2.2, 2.3, and 2.4 are plotted in Figure 2.13. Samples which were 100% saturated w
brine should lie along the Ro line in Figure 2.13, representing a Sw = 1. Samples with dif-
ferent saturations fall within the iso-Sw lines described by Equation 2.7.
The errors associated with the calculation of Sw depend on the uncertainty of the va
ues used for a, m, n,φ, Rw, and Rt (Chen and Fang, 1988). The most important parame
in causing uncertainty in the predicted Sw is the saturation exponent, n. When all of the
parameters (except n) have the same amount of uncertainty, it has been shown that
Rtlog m φlog– aRw( )log n Swlog–+=
28
6.
oreodelter. S
Figure 2.13 Pickett plot constructed using data from Tables 2.2, 2.3,2.4 and Equation 2.When true resistivity (Rt) is plotted vs. porosity (φ) on a log-log scale, the water saturation isrepresented by a family of straight lines. In the above figure, Sw is shown as percent porevolume. At an Sw = 100%, the straight line representing Sw in a Pickett plot is called the Roline and represents how the resistivity of a brine-filled rock depends on porosity. Whole cdata measured at various saturations are plotted to show the overall quality of the Archie mused for calculating saturation. The blue circles represent rocks saturated with 100% waThe yellow triangles, for example, represent rocks whose resistivity was measured with awranging from 5 to 10 percent.
Sw = 5 to 10 Sw = 10 to 20 Sw = 20 to 30
Sw = 30 to 40 Sw = 40 to 50 Sw = 50 to 60
Sw = 60 to 70 Sw = 70 to 80 Sw = 80 to 90
Sw = 100
10−1
100
101
5102030405060708090
0.25
0.40
Ro Line
a = 0.72 m = 2.06 n = 1.85
0.30
φ
R (ohm-m)t
29
s
ween
s
ppro-
ions
r
The
osity,
on
ri-
he J1
constant m is the most important variable in causing errors in Sw, followed byφ, a, Rw, and
Rt (Chen and Fang, 1988).
The method used here to calculated the uncertainty is to use the Archie equation
along with the calibrated constants (a = 0.72, m = 2.06, n = 1.85) to predict Sw based
solely on the measured whole core porosity (Tables 2.3 and 2.4). The rms error bet
the predicted Sw and measured Sw was then taken as the uncertainty. Figure 2.14 show
that the overall rms error associated with calculating Sw from the Archie equations is 0.05.
The rms error of the Sw predictions vary depending on saturation. When Sw < 0.4, the rms
error is much lower (0.02), whereas at higher Sw (Sw > 0.4), the rms error is higher (0.08).
Water saturation calculations in the J1 and J2 were performed in all wells with a
priate porosity and resistivity logs, using a = 0.72, m = 2.06, and n = 1.85 and Equat
2.3, 2.5, and 2.6. Average values for Sw were taken in reservoir zones and are shown fo
each well in Table 2.1.
Permeability
A two step approach was used to calculate permeability (K) from well log data.
first step involves a multiple regression between whole-core based permeability, por
and log-derived volume of shale (Vsh). The whole core properties (K,φ) were measured
under an effective stress of 14.5 MPa (2100 psi). The result of the multiple regressi
yielded a permeability transform which related K toφ and Vsh. The second step involved
comparing the results of the permeability transform to whole-core deformation expe
ments. Whole core deformation experiments were carried out on 7 samples within t
30
d
MS
Figure 2.14 Predicted Sw vs. measured Sw when a = 0.72, n = 1.85, and m = 2.06. The dasheline shows a one-to-one correlation. This model was used to calculate Sw from the porosity andresistivity (Rt) data in Tables 2.3 and 2.4. The RMS error was calculated between thepredicted and measured saturations. For all of the data, the RMS error was 0.05. The Rerror was lower at Sw < 0.4 and equals 0.02. At higher Sw (Sw > 0.4) the RMS error was 0.08.
Pre
dict
ed S
w
Measured Sw
a = 0.72 m = 2.06 n = 1.85
rms Error all points = 0.05 Sw < 0.4 = 0.02 Sw > 0.4 = 0.08
31
he
lus-
32
(Fig-
eir
atu-
ever,
well
the
orer
t
and J2 and relate the porosity loss through compaction to permeability reduction. T
advantage of these experiments are that they allow us to track the K,φ behavior of a single
sample whose Vsh is constant.
Porosity alone is a poor predictor for permeability in the J1 and J2 sands, as is il
trated with whole core data from the A32 BP and 65-1 ST wells (Figure 2.15). The A
BP data show a wide range of porosities for any given permeability above 1000 mD
ure 2.15). Permeability for the 65-1 ST samples are generally lower, even though th
porosities are not below 0.30.
Factors which control permeability include grain size, sorting, irreducible water s
ration, porosity, and shale content (Timur, 1968; Hearst, 1996; Veranda, 1999). How
not all of these factors (grain size and sorting) are directly obtainable from open-hole
log analysis. Porosity and Vsh, however, are readily available from openhole well log
analysis and are used to predict horizontal and vertical permeability where K =f(φ,Vsh):
(2.8)
Equation 2.8, although not explicitly, takes into account grain size and sorting through
Vsh term. Rocks can have the same porosity but different grainsizes. Rocks with po
sorting and smaller grain sizes tend to have higher Vsh and lower permeability, while a
cleaner sand with the same porosity may have low Vshhave higher permeability (Hearst e
al., 1996; Vernik, 2000).
K 10A B φ( )log CVsh+ +[ ]
=
32
P
mp the J2data
f the
Figure 2.15 Semi-log crossplot of stressed whole core permeability vs. porosity for A32 Band 65-1 ST wells. Closed circles represent data from the J1 and J2 in the A32 BP well.Closed circles with porosities less than 0.28 represent whole core data from the shale/sludeposit between the J1 and J2 in the A32 BP. Triangles represent whole core data fromin the 65-1 ST1. The sold lines are linear fits to the data. Line 1 represents a fit the A32BPonly. Line 2 represents a fit to the 65-1 ST1 data only. Line 3 represents a fit through all odata. The correlation coefficient for each fit is shown in parentheses in the key.
0.24 0.26 0.28 0.30 0.32 0.34 0.3610
0
101
102
103
104
K (
mD
)
φ
1
2
3
65-1 ST
A32 BP
A32 BP only (0.87)
65-1 ST only (0.65)
A32 BP and 65-1 ST (0.68)
1
2
3
33
d in
. A
ws
.9
V
y
and
is
rease
han
Permeability was estimated from porosity and Vsh using whole core data in the A32
BP for calibration of the constants A, B, and C in Equation 2.8 (Table 2.5). Vshwas calcu-
lated by linearly scaling the GR log. The 65-1 ST whole core samples were not use
the regression because poor core recovery would not allow for a reliable core-log tie
multiple regression of the stressed whole porosities and GR-derived Vsh with whole core
measured permeabilities predicted permeability with an R2 of 0.95 (Figure 2.16):
(2.9)
A graphical representation of the permeability relation presented in Equation 2.9 sho
that permeability is strongly affected by the Vshterm in Figure 2.17a (Vernik, 2000). The
Vsh contours in Figure 2.17a show that for a given Vsh, permeability exponentially
increases with an increase in porosity.
An independent test to show the validity of the permeability relation in Equation 2
and Figure 2.17a was done to show how porosity affects permeability at a constant sh.
Ostermeier (1995) demonstrated how both porosity and permeability were affected b
changes in the effective stress of unconsolidated sands. In these tests, the porosity
permeability of a given sample was measured under different effective stresses. Th
allows us to track the K-φ behavior of a single sample, whose Vsh remains constant
through the loading cycle. Each sample in Figure 2.17b follows the same general dec
in permeability through porosity loss. All of the samples in Figure 2.17b contain less t
10% Vsh as calculated by the GR log in the A32 BP.
K 107.432 8.060 φ( )log 5.508Vsh–+
=
34
e A32m the
Figure 2.16 Crossplot of predicted permeability to measured core permeability based onEquation 2.9. The dashed line is a one to one correlation. Whole core data are from thBP. The data points are coded depending on each sample’s Vsh, which was calculated froGR log.
100
101
102
103
104
100
101
102
103
104
Pre
dict
ed K
(m
D)
0 to 10%10 to 20%20 to 30%40 to 50%
Core K (mD)
35
orehole
s intoplesility is
Figure 2.17 Permeability transform presented in Equation 2.9 based on stressed whole cdata from the A32 BP (Table 2.5). Contours in both a) and b) are iso-Vsh lines. a) The wcore data are plotted with different symbols, depending on Vsh. Vsh for each whole coresample was taken by linearly scaling the GR log. The above permeability transform takeaccount both porosity and Vsh. b) Porosity and permeability for several whole core samwhich were measured under increasing effective stress. These data show how permeabreduced by changing the porosity under stress while at a constant value of Vsh.
0.24 0.26 0.28 0.30 0.32 0.34 0.36
0
1
2
3
10
10
10
10
104
K (
mD
)
φ
0
0.1
0.2
0.3
0.4
0.5
0.6
0 to 10%10 to 20%20 to 30%40 to 50%
0
1
2
3
10
10
10
10
104
0.26 0.30 0.34 0.380.22 0.40
0
0.1
0.2
0.3
0.4
0.5
0.6
16192133465156
Sample #
K (
mD
)
φ
a)
b)
Vsh
Vsh
36
ined
BP
e AS
J2
tur-
ini-
the J1
2 BP,
ed GR
high
the
the
sepa-
, as
fan
Geologic Model
Facies and Depositional Environments
Amalgamated Sheet Sand (AS)
The AS facies has a blocky GR and ILD log signature and is very fine to fine gra
(14% silt and clay, 45% fine, 22% very fine, 19% medium grain by weight). The A32
penetrated the J2 (Figure 2.18a) and J1 (Figure 2.19a) within a typical example of th
facies. Sand thickness in the AS facies ranges from 20 to 30 m (70 to 100 ft) in the
and 10 to 12 m (30 to 40 ft) in the J1 with a typically high net-to-gross of 98%.
The depositional environment of the AS facies is within the proximal portion of a
bidite fan. Multiple turbidites may pond themselves in a subsiding salt-withdrawal m
basin, depositing large amounts of sands in the form of sheets. The sheet sands in
and J2 are laterally continuous and are found to be amalgamated in the area of the A3
A4BP, and A38 (Figures 2.18 and 2.19).
Layered Sheet Sand (LS)
The AS facies grades into a layered and shale prone facies that has an interbedd
and ILD signature (Figure 2.20). Clean sands within the LS facies have low GR and
ILD values while the interbedded shales have lower GR and ILD values as shown in
65-1 (Figure 2.18c). Although net to gross is lower in the LS than AS facies (70%),
65-1 does contain several clean sand layers, typically 0.5 to 10 m (3 to 30 ft) thick,
rated by shales.
The LS facies is interpreted to record deposition at the distal portion of the fan lobe
opposed to the AS facies, which represents deposition in the proximal portion of the
37
e for) Typesands.
Figure 2.18 Type well log responses and facies map for the J2 sand. a) Type log responsthe AS facies. b) Facies map for the J2 sand. c) Type log response for the LS facies. dlog responses for the CS facies and its associated facies. e) Type log response for the LV
65
109108
64
0 0.5 1.0(Kilometers)
N
CS - Channel Sands
LV - Levee Sands
AS - Amalg. Sheet Sands
LS - Layered Sheet Sands
A5 BP
A36109-1
A32 BP
A2 BP
A38
A10
A4 BP 65-1 ST
A60 65-1
A9
A
A’
B’
B
109-1 ST1 A1
A35
A11 BP
A41
A33
A31
A34
A37
A3 BP5 m20 ft
J2
A32 BPAmalgamated Sheet Sand (AS)a)
Layered Sheet Sands (LS)65-1
5 m20 ft
J1
J2
c)
5 m20 ft
J2
CS
A1
J2
LV
CS
A3 BP 109-1
CS
AS
J2
Channel Sand (CS) and Associated Facies d)
5 m20 ft
J2
109-1 ST
Levee Sands (LV)e)
b)
C
C’
D’
D
38
e forcies.
the J1
Figure 2.19 Type well log responses and facies map for the J1 sand. a) Type log responsthe AS facies. b) Type log response for the LV facies. c) Type log response for the LS fad) Type log responses for the CS facies and its associated LV facies. e) Facies map for sand.
5 m20 ft AS
J1
A32 BP
Amalgamated Sheet Sand (AS)a)
J2
65-1
5 m20 ft
J1
Layered Sheet Sands (LS)c)
A33
5 m20 ft
J1
Levee Sands (LV) b)
5 m20 ft
J1
CS
LV
A1
Channel Sands (CS)d)
A-1
J2
65-1
5 m20 ft
J1
A-1
A31
A33
A32 BP
A38
A10
A9
A38 ST
A4 BP
65-1 ST
A60 65-1
A35
A11 BP
A3 BP A1
A41
A37
65
109108
64 0 0.5 1.0(Kilometers)
N
A34
A5 BP
109-1
A2 BP
A
A’
B’
B
109-1ST
CS - Channel Sands
LV - Levee Sands
AS - Amalg. Sheet Sands
LS - Layered Sheet Sands
e)
C
C’D’
D
39
-B’
low
Figure 2.20 Cross sections flattened on the bottom of the J2 horizon for lines A-A’ and B(Figure 2.18) showing facies relationships. For each well, a GR (left) and ILD (right) areshown. Some wells (A-10, 65-1-ST1) penetrated the J2 sand below the OWC and have ILD values. The color scheme denotes different facies within the J1 and J2. Erosionalunconformities are named Cuts 1 through 3.
00.5
1
Kilom
eters
109-1ST
A3 B
PA
37A
1
109-1A
1065-1S
T1
65-1
J3 J2 J1J1
Cut 3
Cut 1
Cut 2
LS - Layered S
heet
AS
- Am
alg. Sheet
CS
- Channel
LV - Levee
AA
’
A34
A2 B
P109-1
A32 B
PA
38A
4 BP
65 1
J1J2C
ut 1
Cut 3
J3
BB
’
100 ft30 m
100 ft30 m
40
sition
rgins
o-
y a
S
e CS
erly-
and
109-
and
ity in
ells
nd J2
other
. The
(Figures 2.18 and 2.20). The interbedded shale layers represent hemipelagic depo
in between flow events and debris slumps which more than likely came from the ma
of the rapidly filling Bullwinkle basin (Holman and Robertson, 1994).
Channel Sand (CS)
The Channel facies (CS) of the J2 in general contains thick sands with sharp, er
sional contacts with the beds they overlie. In some cases, the CS facies is capped b
thinner LV facies within the J1 and J2 (Figures 2.18 and 2.19). Within the J2, the C
facies may also overlie the AS facies (109-1 in Figure 2.21). The thickest part of th
facies in the J2 are in the A1, A37, and A31 wells, where it is interpreted that the und
ing AS facies has been entirely removed by channel erosion (Figure 2.20).
The AS facies is distinguished from the CS facies by a sharp increase in grain size
decrease in porosity. An example of this is in the 109-1 (Figure 2.21). The CS in the
1 is coarser grained (fine to medium) than the underlying AS facies and both DPHI
NPHI logs record a higher porosity in AS (~0.33) than the CS facies (~0.29). Poros
the AS facies is slightly greater than in the CS facies for the A34, A2BP, and A5 BP w
(Figure 2.20).
The CS facies is interpreted to result from channels which swept across the J1 a
AS facies. These channels cut into the underlying AS facies in some places, and in
places removed the AS facies completely, cutting into the shales above the J2 sand
CS facies in the J1 and J2 are found in the western portion of the field.
41
d at
lues.
Figure 2.21 Wireline response of the CS and AS facies in the 109-1. The J2 is finer grainethe base and has higher NPHI and DPHI values than the top. This jump in grainsize andporosity is interpreted as the contact between the AS and CS facies. Sidewall (SW) coreporosities and permeabilities are shown as open circles for comparison with log-derived va
J2CS
Unit 4Sw = 0.11φ = 0.31Kh = 1518 mDKv = 279 mDN/G = 0.98
SW PorSW Perm
METERS
Fac
ies
FlowUnit
ASJ2
DPHI
42
cies
. The
ure
ch
orm
ture is
e
her
d
.
t and
basin
on-
(LS).
by the
s of
Levee (LV)
There is also evidence for a levee/overbank (LV) facies associated with the CS fa
in the J2 in the 109-1 ST well (Figure 2.18 and Figure 2.19). The LV facies is finer
grained than the CS facies and contains 5 to 10 ft thick sands interbedded with shales
LV facies in some places overlie a thick CS facies (A3BP in Figure 2.18 and A37 in Fig
2.20).
The LV facies is interpreted to be deposited on the overbanks of the channel whi
swept across the J1 and J2 sands.
Geologic Evolution
Deposition of the J Sand package occurred in a salt withdrawal mini-basin in the f
of turbidite sheets and channels (Holman and Robertson, 1994). The stratal architec
similar to other deepwater Gulf of Mexico fields where primary deposition of turbidit
sheet sands within actively subsiding salt withdrawal minibasins was followed by hig
energy channel cutting and deposition after salt withdrawal had stopped (Holman an
Robertson, 1994; Prather et al., 1998; Hoover et al., 1999; Winker and Booth, 2000)
Early time deposition of the J2 sands was in the form of both amalgamated shee
layered sheet sands (Figures 2.18 and 2.20) which may have been directed into the
from the west by salt-cored bathymetric highs (Winker and Booth, 2000). This envir
ment was divided into two lithofacies: the amalgamated sheet (AS) and layered sheet
These sheets are laterally continuous across the field in the J2 and are represented
A32 BP, A4BP, A10, and A38 in Figure 2.20. The AS facies grades into the LS facie
the 65-1 and 65-1 ST to the east.
43
acies
is
sands
J2 CS
The
annel
e field
re
5 BP
out
(Fig-
ies
more
n of
ck to
n
in the
s in
quent
the
The J2 AS facies was cut by a subsequent channel (Cut 1, Figure 2.20). The CS f
in the J2 records a channel that flowed across the Bullwinkle basin (Figure 2.18). It
interpreted that there was no longer any accommodation space available to pond the
and as a result, the channel cut into the underlying deposits. The coarse base in the
facies in the 109-1 (Figure 2.21) may record a lag deposit (Beaubouef et al., 1999).
LV facies in the J2 record levee/overbank deposits which were associated with the ch
that swept across the J2. The LV facies is more prevalent on the western edge of th
where it was penetrated in the J2 in the A11BP, 109-1 ST, A41, and A33 wells (Figu
2.18). Some evidence for the LV facies was also recorded farther to the east in the A
where it overlies a thick section of CS facies. A west-to-east pattern of LV facies pinch
may indicate that the channel started cutting in the western edge of the field initially
ure 2.20). The channel then moved farther east, where it cut into the LV and AS fac
which were already present in the J2 and preserved the LV facies in the west
Subsidence and salt uplift during J2 channel sand cutting and deposition created
accommodation in the Bullwinkle basin (Holman and Robertson, 1994). The creatio
accommodation changed sand deposition from channel-style facies (CS and LV) ba
sheet in the J1 (AS and DS facies in Figures 2.19 and 2.20). Deposition of the J1 i
bathymetric lows occurred in the same way as J2, where AS facies were deposited
western edge of the field (109-1ST, A-10, A32 BP, A38 in Figure 2.19). The LS facie
the J1 was deposited in the distal part of the fan on the eastern edge of the field.
A bypass phase in the J1 led to erosion (Cut 2) of the J1 sheet sands and subse
deposition of CS and LV facies (Figure 2.20). The J1 channel/levee system cut into
44
nica-
the
osion
when
moda-
d the
998;
m-
20).
til sea
tson,
a-
envi-
e
ger
on
re
nt
uds
top of the J2 in some places (A37 in Figure 2.20) and made updip hydraulic commu
tion between the J1 and J2 possible. Unlike the J2, the AS facies was preserved to
east of the channel in the J1. (109-1ST in Figure 2.20).
Subsequent changes in either sea level or sediment supply eventually caused er
of the top of the J Sand package (Cut 3 in Figure 2.20). This bypass phase occured
there was no longer accommodation space left for sediment amalgamation. Accom
tion space was no longer created because the sediment accumulation rate exceede
rate at which the salt could deform (Holman and Robertson, 1994; Prather et al., 1
DeVay et al., 2000; Winker and Booth, 2000) The J1 in some places is bifurcated co
pletely and some of the cutting extends down to the top of the J2 (109-1 in Figure 2.
Channel/levee systems continually migrated across the top of the J Sand package un
level rose once again and the basin returned to a bathyl setting (Holman and Rober
1994).
Implications for Production and Sand Connectivity
Initially, all 4 of the J Sands (J1 through J4) were thought to be hydraulically sep
rated, due to the highly continuous nature of the sands and shales in the AS and LS
ronment (Holman and Robertson, 1994). The LS and AS facies of the J1 and J2 ar
similar to the facies described by McGee et al. (1994) and Kendrick (2000) in the Au
Field (Figure 2.4). There is a high degree of correlation of sands between wells and
seismic in the Auger field, indicating that sands and muds in the AS and LS facies a
highly continuous. Individual sands and reservoirs within the AS and LS environme
should show very little, if any, vertical communication between reservoirs, since the m
45
e
ta
s are
rvoir
g and
epo-
thick
te
te
op of
sional
ical
s a
t into
ars
).
Lower
are
bounding them are also continuous. This model was initially used when planning th
development of the Bullwinkle J Sands (Holman and Robertson, 1994). Pressure da
from subsequent development wells, however, show quite clearly that all of the J Sand
indeed connected and are in hydraulic communication, effectively acting as one rese
(Holman and Robertson, 1994).
Hydraulic communication between the J1 and J2 is a result of the channel cuttin
in-filling occurring during the deposition of the J1 (Figure 2.22). At the close of J2 d
sition, hemipelagic deposition and slumps from the margins of the basin covered the
sands of the J2 with muds and hydraulically separated them any subsequent turbidi
sheets. The AS and LS facies deposited in the J1 were initially hydraulically separa
from the J2. Subsequent erosion during deposition of the J1 CS facies cut into the t
the J2, making vertical communication between the two sands possible across an ero
unconformity (Cut 2 in Figure 2.22). There is evidence from well data showing a vert
sand-on-sand contact between the J1 and J2 in the A11 BP and A41 wells. There i
north to south deepening of the erosional unconformity at the base of the J1 which cu
the younger shales and J2 sand below (Figures 2.20b and 2.22).
Comparison with Other Deepwater Gulf of Mexico Fields
Another Gulf of Mexico analog similar to the Bullwinkle J1 and J2 sands is the M
field in Mississippi Canyon Block 807, which is described in detail by Mahaffie (1994
The Mars field contains several sheet and channel sand reservoirs. The Upper and
Yellow intervals at Mars are very similar to the Bullwinkle J1 and J2 sands in that they
46
n thethe
Figure 2.22 Cross-section through the J1 and J2 showing sand-on-sand contacts betweetwo reservoirs from the maps in Figures 2.18 and .2.19 These sections are flattened on bottom of the J2 horizon.
A37
A1
A11 B
P
A41
A33
J2 J1
J1J2
J300.5
1.0
Kilom
eters
J?
CC
’
Cut 1
Cut 2
Cut 1
Cut 2
109-1ST
A35
A11 B
P
A31
A34
DD
’
J2
J1J3
J2J2
Cut 1
Cut 1
Cut 2
Cut 2
Cut 3
J1
20 m
20 m
47
wer
d
inter-
o a
J1
nd. In
hannel
affie,
its.
e log-
h has
ellini
to
ed.
per-
ser-
thin
lithostratigraphically continuous, but are composed of both AS and CS facies. The Lo
Yellow interval is interpreted to be a laterally extensive amalgamated sheet sand an
would be analogous to the AS facies of the J1 and J2. The Upper Yellow horizon is
preted as a channel complex which cut into the top of the Lower Yellow (Figure 2.4).
Mars is also similar to Bullwinkle due to the fact that the basin at Mars returned t
sheet sand depositional setting after channelization of the Upper Yellow occurred
(Mahaffie, 1994). Similar to the transition at Bullwinkle from J2 channel sands back to
sheet facies, the Lower Green at Mars was deposited as a laterally extensive sheet sa
both cases, it has been inferred that basin subsidence started to outpace turbidite c
deposition when depositional facies switched from channel back to sheet facies (Mah
1994; Holman and Robertson, 1994).
Flow Units
For simulation purposes, the 4 facies in the J1 and J2 were grouped into 6 flow un
Homogeneous rock properties were then assigned to each flow unit by averaging th
derived values for porosity, water saturation, and permeability. This simple approac
been used in the past to simulate rock properties for use in reservoir simulation (Rov
et al., 1998; Slatt et al., 2000). Permeability calculated using Equation 2.9 was used
delineate reservoir zones from non-reservoir. A permeability cutoff of 10 mD was us
Zones within the J1 or J2 with a permeability below 10 mD were not included when
porosity, water saturation, and permeability were averaged in each well. Horizontal
meability was taken as the arithmetic average within zones which were flagged as re
voir. Vertical permeability values for each well were taken as the harmonic mean wi
48
in the
hile
teris-
3
Hor-
e of
AS
ough
sent
)
osity
has
t 1
abil-
er
due
ue of
the reservoir zones. Porosity and water saturation were taken as the arithmetic mean
reservoir zones. Table 2.6 is a summary of each flow unit’s petrophysical properties, w
Table 2.1 shows the average petrophysical properties for each well.
Unit 1 contains the AS facies of the J2 sand and overall has the best flow charac
tics (Figure 2.23). Three wells penetrated Unit 1, with the A32 BP showing the log-
derived petrophysical properties (Figure 2.25). Porosity has an average value of 0.3
(Table 2.6). Water saturation ranges from 0.14 to 0.18 with an average value of 0.16.
izontal permeability is excellent, ranging from 2300 to 2500 mD with an average valu
2400 mD. Vertical permeability is approximately 50% of the horizontal permeability,
with an average value of 1100 mD. The high vertical permeability is the result of the
facies high net-to-gross (0.99) within Unit 1.
Unit 2 contains the LS facies of the J1 and J2 sands (Figures 2.23 and 2.24). Alth
the LS facies contains many interbedded sands and shales, the sands which are pre
have decent flow properties. Three wells penetrated Unit 2, although only one (65-1
logged above the OOWC in the J1 and J2 (Figure 2.26). Table 2.6 indicates that por
ranges from 0.29 to 0.32 with an average value of 0.30. Water saturation in the 65-1
an average value of 0.20. Horizontal permeability is lower than the AS facies of Uni
and ranges from 724 to 1355 mD with an average value of 1056 mD. Vertical perme
ity ranges from 82 to 226 mD with an average value of 155 mD. Although the clean
sands in Unit 2 have excellent reservoir properties, the lower vertical permeability is
to the interbedded nature of the LS facies. Overall, net-to-gross has an average val
0.74.
49
it. c)he
Figure 2.23 Type well logs for the flow units in the J2. a) Type log from the A32 BP for Un1. b) Map of the J2 showing the distribution of flow units using in the reservoir simulationType log from the 65-1 for Unit 2. d) Type logs from the A1, A3 BP and 109-1 showing twireline signatures of Unit 4. e) Type logs from the 109-1-ST for Unit 6.
5 m20 ft
J2
A32 BPFlow Unit 1a)
Flow Unit 265-1
5 m20 ft
J1
J2
c)
5 m20 ft
J2
CS
A1
J2
LV
CS
A3 BP 109-1
CS
AS
J2
Flow Unit 4 d)
5 m20 ft
J2
109-1 ST
Flow Unit 6e)
b)
65
109108
64
0 0.5 1.0(Kilometers)
N
109-1 ST1 A1
A35
A11 BP
A41
A33
A31
A34
A37
A5 BP
A36
A3 BP
109-1
A32 BP
A2 BP
A38
A10
A4 BP 65-1 ST
A60 65-1
A9
A
A’
B’
B
1 0.16 0.33 2400 1120 0.99
2 0.20 0.30 1060 160 0.74
3 0.19 0.32 2260 920 0.95
4 0.14 0.32 1890 460 0.93
5 0.16 0.33 1700 200 0.69
6 0.25 0.28 420 50 0.56
Unit Sw φ Kh Kv N/G
50
mr
Figure 2.24 Flow Units for J1 sand. a) Type logs from A32 BP for Unit 3. b) Type logs frothe A33 for Unit 6. c) Type logs from the 65-1 for Flow Unit 2. d) Type logs from the A-1 foUnit 5. e) Flow unit map for the J1 sand showing the distribution of Units 2, 3, 5, and 6).
5 m20 ft AS
J1
A32 BP
Flow Unit 3a)
J2
65-1
5 m20 ft
J1
Flow Unit 2c)
A33
5 m20 ft
J1
Flow Unit 6b)
5 m20 ft
J1
CS
LV
A1
Flow Unit 5d)
A-1
J2
65-1
5 m20 ft
J1
A-1
e)
A31
A33
A32 BP
A38
A10
A9
A38 ST
A4 BP
65-1 ST
A60 65-1
A35
A11 BP
A3 BP A1
A41
A37
65
109108
64 0 0.5 1.0(Kilometers)
N
A34
A5 BP
109-1
A2 BP
A
A’
B’
B
1 0.16 0.33 2400 1120 0.99
2 0.20 0.30 1060 160 0.74
3 0.19 0.32 2260 920 0.95
4 0.14 0.32 1890 460 0.93
5 0.16 0.33 1700 200 0.69
6 0.25 0.28 420 50 0.56
Unit Sw φ Kh Kv N/G
51
filledsingn 2.9ed
Figure 2.25 Well logs for the A32 BP AS facies showing the relationship between wirelineresponse, facies, and flow units. The black bars represent areas in the J1 and J2 withpermeabilities exceeding 10 mD. Open circles are sidewall (SW) core measurements andcircles are whole core (WC) measurements. DPHI in the porosity track was calculated uEquation 2.1 and a fluid density of 0.98 g/cc. Permeability was calculated using Equatioand the Vshcurve next to the GR log. An upper limit of 3500 mD was chosen for the log-baspermeability prediction.
J1AS
J2AS
Sw = 0.16φ = 0.33Kh = 2315 mDKv = 1122 mDN/G = 0.99
Unit 1
Unit 3Sw = 0.23φ = 0.31Kh = 1567 mDKv = 806 mDN/G = 0.86
SW Por
WC Por
DPHIWC Perm
SW Perm
METERS Fac
ies
Flow Units
52
iestact.ing
Figure 2.26 Well logs for the 65-1 showing the relationship between wireline response, facand flow units in the LS facies. The 65-1 penetrates the J1 and J2 above the gas-oil conNPHI/DPHI crossover is seen in the J1 and J2. Porosity in gas zones was calculated usEquation 2.1 with a fluid density of 0.68 g/cc.
J1
LS
Unit 2Sw = 0.19φ = 0.32Kh = 1287 mDKv = 137 mDN/G = 0.76
SW Por
SW Perm
METERS Fac
ies
Flow Units
Sw = 0.20φ = 0.32Kh = 1093 mDKv = 82 mDN/G = 0.71
LS
J2
Unit 2
DPHI (0.98)
DPHI (0.68)
53
ry
me-
ly
age
of
ces
only
the
ies in
igh
32
Hor-
e
ith
es-
.98
CS
J1
ble
Unit 3 contains the AS facies of the J1 sand (Figures 2.24 and 2.25). Unit 3 is ve
similar in reservoir properties to the AS facies in Unit 1. Porosity and horizontal per
ability are comparable with Unit 1, with average values of 0.32 and 2260, respective
(Table 2.6). Unit 2 exhibits a slightly higher water saturation than Unit 1, with an aver
value of 0.19. Vertical permeability is also comparable with Unit 2, being about 50%
the horizontal permeability.
Unit 4 is largely made up of the CS facies of the J2, although it includes in some pla
the LV and AS facies. The A3 BP well shows an example in Unit 4 where a thick CS
facies is present below thinner LV facies (Figure 2.23). The A1 is an example where
thick, clean CS facies is present (Figure 2.23). The 109-1 well is an example where
CS facies is present above the AS facies (Figures 2.21 and 2.23). The rock propert
Unit 4 show some variability in terms of saturation and permeability, but overall it is h
quality reservoir rock. Porosity ranges from 0.31 to 0.33 with an average value of 0.
(Table 2.1). Water saturation varies from 0.08 to 0.19 with an average value of 0.14.
izontal permeability is highly variable, ranging from 1500 to 2200 mD with an averag
value of 1889 mD. Vertical permeability is about 25% of the horizontal permeability, w
an average value of 459 mD. The low vertical permeability in Unit 4 is due to the pr
ence of LV sands in some wells. Net-to-gross is still very high, ranging from 0.77 to 0
with an average value of 0.93.
The CS and LV facies in the J1 are grouped into Unit 5 and are distinct from the
and LV facies in Unit 4 in that Unit 5 exhibits an overall lower net-to-gross (0.69). The
sand in the A-1 well shows an example of Unit 5 (Figure 2.24). Porosity is compara
54
tal
erti-
erti-
nds
Fig-
n the
ple of
8
e of
nit 6
e to
value
with Unit 4 and has an average value of 0.33 (Table 2.6). Water saturation is slightly
higher than Unit 4, ranging from 0.13 to 0.22 with an average value of 0.16. Horizon
permeability ranges from 1495 mD to 1981 mD with an average value of 1715 mD. V
cal permeability is lower than Unit 4, with an average value of 211 mD. The lower v
cal permeability is the result of Unit 5 containing more wells with both CS and LV sa
present than Unit 4.
Unit 6 contains the low quality reservoir sands of the LV facies in the J1 and J2 (
ures 2.23 and 2.24). LV type facies are known to have poorer reservoir qualities tha
CS facies of Units 4 and 5 (Bourgeois et al., 1996). The 109-1-ST shows an exam
Unit 6 (Figure 2.27). Porosity ranges from 0.26 to 0.30 with an average value of 0.2
(Table 2.1). Water saturation is high, ranging from 0.20 to 0.35 with an average valu
0.25. Horizontal permeability in some places reaches as high as 990 mD, although U
has an average of 421 mD. Vertical permeability is extremely low compared with the
other flow units, with an average value of 52 mD. The low vertical permeability is du
the interbedded nature of the LV facies in Unit 6, where net-to-gross has an average
of 0.56.
55
Figure 2.27 Wireline response of the LV facies in the 109-1 ST J2 sand.
J2LV
Unit 6Sw = 0.21φ = 0.30Kh = 990 mDKv = 83 mDN/G = 0.49
SW PorSW Perm
METERS Fac
ies
FlowUnit
56
og
dep-
nds.
of
in the
n
h made
re
its for
ich
nnels
.
erties
Conclusions
We formulated a depositional and reservoir simulation model based on wireline l
interpretation for the J1 and J2 sands. Facies identification from well logs aided in a
ositional model which describes the overall reservoir architecture of the J1 and J2 sa
Both sands were deposited in rapidly subsiding salt withdrawal minibasin in the form
amalgamated turbidite sheets and channels. Initial deposition of the J1 and J2 were
form of amalgamated sheets which are laterally continuous. Lack of accommodatio
space during J1 and J2 deposition caused channelization into the sheet sands whic
vertical communication possible. Rock properties calculated by calibrating whole co
and well log data show that the J1 and J2 sands can be broken into 6 separate flow un
simulation purposes. Each of these flow units have characteristic rock properties wh
reflect depositional environment. Facies deposited in amalgamated sheets and cha
overall have very high porosities and permeabilities with low initial water saturations
Levee sands deposited during J1 and J2 channelization show less favorable rock prop
than amalgamated sheets and channels.
57
voir
arac-
.C.,nd-
om
Char-
avior
tone,
ater
dleco,oir
ion
ck.
References
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60
Nomenclature
Symbol Description Dimensions
a tortuosity v/v
m cementation exponent v/v
n saturation exponent v/v
DPHI density porosity v/v
F formation factor v/v
GR gamma ray log API
ILD deep resistivity log ohm-L
I resistivity ratio v/v
Kh horizontal permeability L2
Kv vertical permeability L2
NPHI neutron porosity log v/v
OOWC original oil-water contact L
OWC oil-water contact L
OGOC original gas-oil contact L
Ro resistivity of brine-filled rock ohm-L
Rw water resistivity ohm-L
Rt true resistivity ohm-L
RHOB bulk density log M/L3
Sor residual oil saturation v/v
Sw water saturation v/v
Swirr irreducible water saturation v/v
TVDSS subsurface total vertical depth L
Vsh shale volume v/v
φ porosity v/v
ρb bulk density M/L3
ρf fluid density M/L3
ρg grain density M/L3
61
Table 2.1: Average petrophysical properties for each well
FlowUnit
Well Sand Sw φKh
(mD)
Kv
(mD)N/G
Net Sand(ft)
1 A32 BP J2 0.16 0.33 2315 1147 0.99 96
1 A38 J2 0.14 0.32 2388 1176 0.98 87
1 A4 BP J2 0.18 0.33 2509 1042 0.99 73
Average 0.16 0.33 2404 1122 0.99 85
2 65-1 ST J1 1.00 0.29 821 226 0.69 28
2 65-1 ST J2 1.00 0.31 1355 193 0.94 65
2 65-1 J1 0.19 0.32 1287 137 0.76 22
2 65-1 J2 0.2 0.32 1093 82 0.71 46
2 A36 J2 1 0.29 724 138 0.60 67
Average 0.20 0.30 1056 155 0.74 45
3 109-1ST J1 0.10 0.32 2646 1506 1.00 38
3 A32 BP J1 0.23 0.31 1567 806 0.86 28
3 A38 J1 0.21 0.32 2418 1245 0.97 34
3 A4 BP J1 0.22 0.32 2409 135 0.96 35
Average 0.19 0.32 2260 923 0.95 34
4 109-1 J2 0.11 0.31 1518 279 0.98 69
4 A-1 J2 0.08 0.33 2032 891 0.98 97
4 A2 BP J2 0.18 0.31 1902 1180 0.97 74
4 A34 J2 0.12 0.32 2023 569 0.94 91
4 A35 J2 0.11 0.32 1717 237 0.95 29
4 A37 J2 0.18 0.32 2255 252 0.94 68
4 A3BP J2 0.19 0.33 1894 144 0.77 67
4 A5BP J2 0.14 0.31 1768 116 0.87 87
Average 0.14 0.32 1889 459 0.93 68
5 A1 J1 0.14 0.33 1631 106 0.68 67
5 A11 BP J1 0.14 0.33 1630 248 0.83 100
5 A35 J1 0.20 0.32 1495 108 0.43 23
5 A37 J1 0.22 0.33 1981 152 0.74 60
5 A3BP J1 0.16 0.33 1920 484 0.65 24
5 A41 J1 0.13 0.32 1630 170 0.84 64
Average 0.16 0.33 1715 211 0.69 57
6 109-1ST J2 0.21 0.30 990 83 0.49 40
6 A-11-BP J2 0.20 0.29 130 39 0.78 7
6 A33 J1 0.35 0.26 16 14 0.11 5
6 A33 J2 0.25 0.28 548 73 0.86 41
Average 0.25 0.28 421 52 0.56 23
62
Table 2.2: Whole core data from the A32 BP and 65-1 ST1 wells used in the analysisof electrical resistivity data.
WellCoreDepth
(ft)Sand φ F
Salinity(kppm)
Rw (lab)(ohm-m)
Ro (lab)(ohm-m)
Ro (res)(ohm-m)
A 32BP 12813.09 J1 0.306 9.03 210 0.0453 0.409 0.199
A 32BP 12813.07 J1 0.315 6.61 210 0.0453 0.299 0.145
A 32BP 12849.00 J2 0.294 8.45 210 0.0453 0.383 0.186
A 32BP 12884.10 J2 0.310 5.94 210 0.0453 0.269 0.131
A 32BP 12938.06 J2 0.342 7.01 210 0.0453 0.318 0.154
A 32BP 12873.04 J2 0.317 5.87 210 0.0453 0.266 0.129
A 32BP 12939.00 J2 0.326 5.89 210 0.0453 0.267 0.130
A 32BP 13006.01 J3 0.304 8.20 210 0.0453 0.371 0.180
65 1ST1 13086.05 J2 0.365 5.71 230 0.0438 0.250 0.126
65 1ST1 13086.11 J2 0.325 5.76 230 0.0445 0.256 0.127
65 1ST1 13089.08 J2 0.340 5.81 230 0.0445 0.259 0.128
65 1ST1 13090.03 J2 0.332 6.36 230 0.0438 0.279 0.140
65 1ST1 13090.11 J2 0.348 5.69 230 0.0438 0.249 0.125
65 1ST1 13092.03 J2 0.315 6.95 230 0.0438 0.304 0.153
65 1ST1 13094.01 J2 0.330 6.19 230 0.0438 0.271 0.136
65 1ST1 13095.01 J2 0.335 6.74 230 0.0438 0.295 0.148
65 1ST1 13095.06 J2 0.256 14.00 220 0.0445 0.623 0.308
65 1ST1 13101.06 J2 0.317 6.22 220 0.0445 0.277 0.137
65 1ST1 13102.05 J2 0.342 6.01 230 0.0438 0.263 0.132
65 1ST1 13107.03 J2 0.334 6.48 230 0.0438 0.284 0.143
65 1ST1 13108.04 J2 0.328 5.89 220 0.0445 0.262 0.130
65 1ST1 13116.09 J2 0.329 7.98 230 0.0438 0.350 0.176
65 1ST1 13118.01 J2 0.335 6.55 230 0.0438 0.287 0.144
65 1ST1 13120.01 J2 0.331 6.76 230 0.0438 0.296 0.149
65 1ST1 13122.00 J2 0.335 6.33 230 0.0438 0.277 0.139
65 1ST1 13124.01 J2 0.321 6.73 230 0.0438 0.295 0.148
65 1ST1 13126.00 J2 0.316 6.75 230 0.0438 0.296 0.149
65 1ST1 13139.00 J2 0.306 10.52 230 0.0438 0.461 0.231
65 1ST1 13140.05 J2 0.319 9.30 230 0.0438 0.407 0.205
63
Drainage Imbibition
Table 2.3: Drainage and imbibition data from the A32 BP and 65-1 ST1 whole cores
Well Core Depth FRo
(ohmm)I Swirr
Rt(ohmm)
I Sor SwRt
(ohmm)
A32 12813.07 J1 6.61 0.15 26.53 0.19 3.86 1.88 0.29 0.71 0.27
A32 12849.00 J2 8.45 0.19 21.17 0.21 3.94 2.13 0.32 0.68 0.40
A32 12884.10 J2 5.94 0.13 22.82 0.22 2.98 1.81 0.24 0.76 0.24
A32 12938.06 J2 7.01 0.15 24.52 0.19 3.78 1.96 0.26 0.74 0.30
65-1 ST1 13086.11 J2 5.76 0.13 19.60 0.23 2.48 1.46 0.18 0.83 0.19
65-1 ST1 13089.08 J2 5.81 0.13 15.20 0.24 1.94 1.45 0.18 0.82 0.19
65-1 ST1 13095.06 J2 14.00 0.31 2.04 0.72 0.63 1.47 0.14 0.86 0.45
65-1 ST1 13101.06 J2 6.22 0.14 7.73 0.35 1.06 1.48 0.18 0.82 0.20
65-1 ST1 13108.04 J2 5.89 0.13 13.10 0.22 1.70 1.46 0.19 0.81 0.19
Table 2.4: Resisitivity Data from A32 BP and 65-1 ST1 whole cores
Well Core Depth φ FRo
(ohmm)Sw I
Rt
(res)
A-32 12813.09 J1 0.306 9.03 0.199 0.072 96.55 19.18
A-32 12873.04 J2 0.317 5.87 0.129 0.057 134.00 17.30
A-32 12939.00 J2 0.326 5.89 0.130 0.079 151.24 19.60
A-32 13006.01 J3 0.304 8.20 0.180 0.082 88.53 15.97
65-1 ST! 13086.05 J2 0.365 5.71 0.126 0.207 15.80 1.98
65-1 ST1 13090.03 J2 0.332 6.36 0.140 0.274 11.13 1.56
65-1 ST1 13090.11 J2 0.348 5.69 0.125 0.261 12.09 1.51
65-1 ST1 13092.03 J2 0.315 6.95 0.153 0.303 8.31 1.27
65-1 ST1 13094.01 J2 0.330 6.19 0.136 0.282 10.16 1.38
65-1 ST1 13095.01 J2 0.335 6.74 0.148 0.298 10.00 1.48
65-1 ST1 13102.05 J2 0.342 6.01 0.132 0.315 9.38 1.24
65-1 ST1 13107.03 J2 0.334 6.48 0.143 0.334 8.69 1.24
65-1 ST1 13116.09 J2 0.329 7.98 0.176 0.449 5.06 0.89
65-1 ST1 13118.01 J2 0.335 6.55 0.144 0.369 6.64 0.96
65-1 ST1 13120.01 J2 0.331 6.76 0.149 0.350 6.73 1.00
65-1 ST1 13122.00 J2 0.335 6.33 0.139 0.355 6.69 0.93
65-1 ST1 13124.01 J2 0.321 6.73 0.148 0.321 7.84 1.16
65-1 ST1 13126.00 J2 0.316 6.75 0.149 0.307 9.16 1.36
65-1 ST1 13139.00 J2 0.306 10.52 0.231 0.595 3.38 0.78
65-1 ST1 13140.05 J2 0.319 9.30 0.205 0.528 4.23 0.87
64
Table 2.5: Whole core porosity and permeability measured under 2100 psi effectivestress from the A32 BP well. Vsh was taken from GR log.
Core DepthK
(mD)φ Vsh Sample
12813.330 2252 0.323 0.000 15
12813.420 2420 0.297 0.000 16
12819.000 2611 0.327 0.000 19
12833.580 1 0.244 0.429 22
12839.750 3 0.257 0.417 25
12841.080 4 0.260 0.405 26
12845.170 9 0.270 0.283 27
12845.250 4 0.255 0.272 28
12845.330 10 0.264 0.260 29
12845.830 765 0.288 0.194 31
12848.920 913 0.306 0.013 33
12869.060 1429 0.294 0.001 37
12869.330 1351 0.296 0.005 38
12870.000 2518 0.310 0.041 39
12870.420 2431 0.313 0.071 40
12871.420 2513 0.297 0.084 41
12872.080 2378 0.305 0.046 42
12873.000 2500 0.307 0.002 44
12873.170 2372 0.334 0.000 46
12874.250 1667 0.318 0.000 47
12874.830 1666 0.318 0.000 48
12875.170 691 0.289 0.000 49
12901.420 2177 0.318 0.074 51
12901.420 1775 0.324 0.074 52
12938.420 2701 0.341 0.014 56
12938.600 1656 0.342 0.011 57
12938.750 2539 0.329 0.008 59
12952.750 1209 0.342 0.046 61
65
Table 2.6: Average petrophysical properties for each flow unit
Flow Unit Sw φKh
(mD)
Kv
(mD)N/G
1 0.16 0.33 2400 1120 0.99
2 0.20 0.3 1060 160 0.74
3 0.19 0.32 2260 920 0.95
4 0.14 0.32 1890 460 0.93
5 0.16 0.33 1700 200 0.69
6 0.25 0.28 420 50 0.56
66
es
ater
f the
was
l pro-
pro-
has
ction of
in
reas
ervoir
ic
Chapter 3
RESERVOIR MONITORING OF THE BULLWINKLE J SANDSUSING PRODUCTION DATA, PULSED NEUTRON LOGS, AND
GASSMANN FLUID SUBSTITUTION MODELING WITH COMPAR-ISON TO TIME-LAPSE SEISMIC RESULTS, GREEN CANYON
BLOCK 65, OFFSHORE LOUISIANA
Abstract
Hydrocarbon production from the J1 and J2 reservoirs resulted in dynamic chang
which are resolvable with time-lapse seismic data. Between 1989 and 1997, the oil-w
contact (OWC) had moved vertically by as much as 284 m. We track the movement o
OWC using production and pulsed neutron logs and we show that the position in 1997
not horizontal. The drainage scenario we develop from these data predict the actua
duced volumes within 8%. The seismic properties of the J1 and J2 were effected by
duction because of changes in effective stress and saturation. Time-lapse results
(Swanston et al., in review) show that the seismic amplitude in regions of water sweep
decreased. We use the Gassmann Equations to model the rock properties as a fun
effective stress and saturation. We found that water-swept areas exhibit an increase
acoustic impedance by as much as 30%. This 30% increase in acoustic impedance
resulted in a 70% decrease in the reflection coefficient at the top of the reservoirs. A
in the reservoir which have experienced an increase in gas saturation due to the res
pressure falling below the bubble point did not exhibit a noticeable change in acoust
impedance and reflection coefficient between 1989 and 1997.
67
s in
ges is
nd J2
ock
g
nd J2
1
ion
on-
2.
over
e
the
nced
d
ompac-
seis-
ith
in
pro-
Introduction
The J1 and J2 sands are a natural laboratory over which time-dependent change
saturation and seismic amplitude are studied. The driving force causing these chan
production of hydrocarbons from the J1 and J2 reservoirs. Production from the J1 a
sands began in July 1989 from the Bullwinkle Platform, located in Green Canyon Bl
65 in 412 m (1353 ft) of water. A total of 15 wells produced or are currently producin
from the J1 and J2 RB reservoirs. Of these 15, 4 wells produced from both the J1 a
in a commingled production string. Two wells, A1 and A38-ST, produced from the J
sand only. The remaining wells produced from the J2. In addition to the 15 product
wells, 5 water injection wells were drilled and perforated below the original oil-water c
tact (OOWC). Only one of the injection wells (A-9) is perforated in both the J1 and J
The remaining 4 wells inject into the J2 exclusively.
Time-lapse seismic analysis is the study of two or more seismic surveys acquired
the same area at different times. At Bullwinkle, two orthogonal seismic surveys wer
acquired prior to production in 1988. An additional seismic survey was acquired over
field in 1997, after 8 years of production. These surveys were normalized and differe
by Swanston et al. (in review) and show that it is possible to image production relate
changes in seismic response. These production related changes include reservoir c
tion and fluid contact movement.
The time-lapse analysis by Swanston et al. (in review) shows areas of widespread
mic dimming in places where oil has been drained from the J2 sand and replaced w
water. This chapter provides additional background to the work of Swanston et al. (
review) by tracking the movement of the oil-water contact (OWC) through time using
68
m
and
at
perfo-
they
ar-
ampli-
tic
d by
951)
ure.
c
mag-
urvey
n the
V
of the
of the
, that
duction data from individual wells and cased-hole wireline logs. Production data fro
individual wells record the amount of fluids (oil, water, and gas) extracted from the J1
J2 sands in terms of flow rate (barrels of fluid/day). We show that water production
each well increased when the OWC had moved updip to the same depth as the sand
rations in the well. Cased-hole wireline logs further aid in tracking the OWC because
can detect water in the formation while the well is still producing.
The acoustic properties of rocks dramatically change at Bullwinkle due to hydroc
bon production. Changes in saturation and effective stress will change the seismic
tude of the reservoir. This is because seismic amplitude is proportional to the acous
impedance contrast in the sand. The impedance behavior in turn is strongly affecte
the p-wave velocity (Vp) in the sand. We used the Gassmann Equations (Gassmann, 1
to model changes in Vp and impedance associated with changes in saturation and press
An increase in Sw and effective stress accompanied by a decrease in oil saturation
increases the velocity and acoustic impedance in the rock. This increase in acousti
impedance makes the reflection coefficient (RFC) at the top of the sand decrease in
nitude. The smaller RFC at the top of the sand was recorded in the second seismic s
in areas where oil had been drained from the J2 as a smaller amplitude.
Exsolution of gas during production has been shown to have the opposite effect o
seismic properties of a rock. While replacement of oil with water increases the Vp and
impedance, the presence of a free gas phase in the pore space dramatically reducesp and
impedance and increases the magnitude of the RFC. The increase in RFC at the top
sand should be imaged as a seismic brightening through time, where the magnitude
seismic amplitude in 1997 is greater than the amplitude in 1988. We show, however
69
s has
quired
inal
is
WC
con-
than
al
filled
WC
o des-
0 m,
aces
igh as
stiffening of the rock due to compaction is enough to cancel out the effect that free ga
on the acoustic properties.
Production Characterization
J1 and J2 Initial Volumes
Structure maps of the J1 and J2 sands were constructed using 3D seismic data ac
before production began at Bullwinkle in 1988 (Swanston et al., in review). The orig
oil-water contact (OOWC) was imaged with seismic data and its subsurface position
supported by well penetrations in both the reservoir and aquifer of each sand. The OO
in both sands is delineated by a sharp break in seismic amplitude along a structural
tour. The magnitude of the seismic amplitude in the reservoir is 5 to 10 times greater
in the aquifer. The OOWC was placed at 3,755 m (12,320 ft) subsurface total vertic
depth (TVDSS) in the J1 and 3,784 m (12,415 ft) TVDSS in the J2.
Net pay within the J1 and J2 is defined as the vertical thickness of hydrocarbon-
sand and it is derived from well log measurements. There is 0 m of net pay at the OO
(Figures 3.1 and 3.2) . The outline which defines the areal extent of each sand is als
ignated with 0 m net pay (Figures 3.1 and 3.2). Net pay in the J2 ranges from 0 to 3
with maximum values near the A34 and A1 wells (Figure 3.1). The J1 sand in most pl
is not as thick as the J2, although net pay in the vicinity of the A11 BP reaches as h
30 m (Figure 3.2).
70
Neting adessgainstis not of
d not
Figure 3.1 J2 net meters of pay sand in 1989 with amplitudes (Swanston et al., in review).pay is illustrated on the well log from the A4 BP. The net pay map was constructed assumhorizontal OWC located at 3784 m (12415 ft) TVDSS. “Hot” colors represent high amplituevents, while the “colder” colors represent lower amplitude events. The bright amplitudecorrespond to areas of thick net pay in the J2 in 1989. The net pay contours terminate aan east-to-west trending sub-seismic fault south of the A33 well. We interpret that there pay south of this sub-seismic fault. The “seismic” limit of each sand is defined by the extenmappable seismic amplitudes while the black polygon outline is the inferred extent of sanresolvable with seismic data.
.
71
ontal
Figure 3.2 Net pay in the J1 in 1989. The net pay map was constructed assuming a horizOOWC at 3755 m (12320 ft) TVDSS.A31
A33
A32 BP
A38
A4 BP65-1 ST
A60
65-1
A35
A3 BP A1
A41
0 0.5 1.0
(Kilometers)
N
A5 BP
109-1
A2 BP
C.I. = 5 m
A34
A11 BP
1ST
A42 ST
A39
A36
A10
A9
A38 ST
A37
Injector
Producer
Other
0
0
5
10
15
J1 RABlock A
Block B
J1 RB10
72
e J1
d
2 RB
C
n the
g of
ced
ges in
ea-
ure
g
OWC
nd is
Initial oil volumes (Voil) were calculated using the bulk volume (Vb) of rock taken
from the net pay maps (Figures 3.1 and 3.2) and rock properties (φ, Sw) with the following
equation:
. (3.1)
Rock properties (φ,Sw) for use in Equation 3.1 are facies-dependent and vary across th
and J2 reservoirs. Constantφ and Sw are assumed within each flow unit (Figures 2.23 an
2.24, Table 2.6). The term (1-Sw) refers to the hydrocarbon saturation . The J1 and J
reservoirs initial volumes are summarized in Table 3.1 at subsurface conditions.
Drainage Analysis
Production data and cased-hole logs were used to track the movement of the OW
through time in the J1 and J2 sands. This provides us with an independent check o
time-lapse seismic work of Swanston et al. (in review) which shows pervasive dimmin
seismic amplitudes in areas where oil has been drained from the reservoir and repla
with water. A similar approach was used in Landro et al. (1999) for the Gulfaks field
where the engineering interpretation of drained areas correspond to timelapse chan
amplitude. Production of oil, water, and gas was monitored in each well and was m
sured at surface conditions on a monthly basis.
The A32 BP produced exclusively from the J2 RB reservoir from 7/89 to 6/94 (Fig
3.3). Water production began in 12/93. The date at which the well started producin
water is a significant benchmark because it denotes the time and depth at which the
had reached the well. The A32 BP started producing > 100 bbls/d of water in 12/93 a
Voil Vbφ 1 Sw–( )=
73
swellcut in
Figure 3.3 Production data from the A32 BP. Both water and oil are shown in bbls/d. Gaproduction is represented in MSCF/d. Production in the A32 BP began in Aug, 1991. Thebegan producing greater than 100 bbls/d of water in 12/93 and experienced a 50% water-3/94. Two PNC log runs were performed, 1 prior to shut-in, and one after.
A-32-BP Production (J2-RB)
Pro
duct
ion
(Sur
face
Vol
umes
)Run #16/20/94
Run #210/6/94
Water (bbl/day)
Oil (bbl/day)
Gas (MSCF/day)
50% Water-Cut
100 bbl/d Water Prod.
74
on
phi-
acteris-
ue
g after
ogs
e J1
at
ows
uration
inter-
J1
il satu-
ction
3.6
blue
per-
er ear-
h
denoted as the “significant water-cut”. The point at which the volumetric oil producti
rate is equal to the water production rate is called the “50% water-cut”. Figure 3.4 gra
cally illustrates the production timescales for the well data in Table 3.2.
Pulsed neutron capture (PNC) logs were also used to investigate drainage char
tics and to track the movement of the oil-water contact (OWC). These logs are uniq
because they can detect the presence of hydrocarbons in the formation behind casin
the well has been producing. Additional information concerning the theory of PNC l
and their use in interpretation is found in Appendix A.
The openhole logs acquired when the A32 BP was drilled in 2/91 show that both th
and J2 are initially oil-filled (Figure 3.5). The PNC run in 6/94 for the A32 BP shows th
the J1 was still oil-filled and the J2 had been water swept. The PNC run in 10/94 sh
that the J1 had been water-swept and the J2 experienced a slight increase in oil-sat
at the top of the sand. This increase in oil saturation at the top of the J2 in 10/94 is
preted to result from bypassed oil migrating upstructure. The remaining oil left in the
and J2 sands after the last PNC log run in 1994 is given a specific name: residual o
ration (Sor). For the A32 BP, Sor is variable and ranges from 0.20 to 0.50 (Figure 3.5).
We compared the depths and times at which wells began significant water produ
(> 100 bbls/d) to PNC log interpretations (Figure 3.6). The solid back lines in Figure
represent the time and depth interval over which a well began producing water. The
and green lines represent the time and depth interval over which PNC log runs were
formed. In general, we observed that wells lower on structure began producing wat
lier than wells located farther updip. The PNC interpretations show that sands whic
75
nd
ts thets thethehich
ate atl wasand isells
Figure 3.4 Plot showing the date of initial water production (100 bbls/d), 50% water-cut, ashut-in for all wells producing from the J1 and J2. Solid boxes represent wells whichexperienced 100 bbls/d water production before 4/2000. The left side of the box represendate at which the well began producing 100 bbls/d water. The line inside the box represendate at which the well produced as much water as oil (50% water-cut). The right side of box represents the date at which each well was shut-in. Dashed boxes represent wells wnever experienced significant water production. The left side of the box represents the dwhich each well began producing oil. The right side of the box represents the date the welshut-in. The TVDSS depth range each box covers represents the interval over which the sperforated. Some wells (A34) may have several perforations in the same sand. Other w(A37, A31, A11 BP, and A35) are perforated and produce from both the J1 and J2.
3350
3400
3450
3500
3550
3600
3650
3700
3750
3800
A1
A2BP
A4BP
A5BPA32BP
A38
A34
A11BPJ1
A31J1
A31J2
A37J1 A35J2
A35J1
A3BP
A38ST
A41
A33
A11BPJ2
A37J2
90 91 92 93 94 95 96 97 98 99 00
TV
DS
S (
m)
Date
100 bbl/d water
50%water
shut-in
begin production
shut-in
76
bars
ther
Figure 3.5 PNC log suite from the A32 BP well. Reservoir zones are represented by blacknext to the GR log. The entire length of the J2 is perforated and was initially drilled andopenhole logged in 11/89. Two PNC log runs were performed within 4 months of each o(6/94 and 10/94). Sw from the openhole ILD and two PNC log runs show that Sw increasedfrom 0.15 to as high as 0.80 in the J2 from 1989 to 10/94. BVO is bulk volume of oil.
Sw PNC (10/94)
Sw PNC (6/94)
Sw OH (11/89)
Sigma (6/94)
Sigma (10/94)
BVO BVO BVO11/89 6/94 10/94
J1
J2
77
J2n.
errawn
resentsand oilesent
J1
Figure 3.6 Floodout plot showing depths and times during which each well in the J1 and began showing water, either in the form of water production or from PNC log interpretatioThe thick black lines indicate the depth range over which the J2 is perforated. The thinnblack lines represent perforations in the J1. The date at which each of the black lines are drepresents the beginning of water production (100 bbls/d). The green and blue lines repthe dates and depth ranges over which PNC logs were run. A green line shows that the was oil-filled at the time of the PNC run. A blue line represents that the sand was initiallyfilled and has since been water-swept by the time of the PNC run. The open circles reprthe OOWC for the J1 and J2. All wells except the A1 produced from the J2 RB. The A-1produced from the J1 RB only. The A31, A37, A11 BP, and A35 produced from both theand J2 RB.
89 90 91 92 93 94 95 96 97
3420
3460
3500
3540
3580
3620
3660
3700
3740
3780
A35
A35
A1
A2BP
A4BP
A5BP
A38
A32BP
A34
A11BP
A31
A37
J1 A32BP
J2 A32BP
J2 A34
J1 A41
J2 A41J1 A31
J2 A31
J1 A4BP
J2 A4BP
J1 A4BP
J2 A4BP
J1 A4BP
J2 A4BP
J1 A37
J2 A37
J2 A5BP
J2 A5BP
J1 A35
J2 A35
J1 A38
J2 A38
J1 A38
J2 A38
J1 A38ST
A31
A3BP
A11BP
J1 OOWC
J2 OOWC
J2 perforated interval
J1 perforated interval
PNC shows oil
PNC shows water}}
OOWC
TV
DS
S (
m)
Date
78
1,
well
P.
ion
m
ince
ure
/92
S
he
ntil
een
aced
s the
ure
were completely oil-filled were not producing water at the time of the logging run (A4
A37, A31, A35 in Figure 3.6). PNC logs imaged water-swept sands after a particular
began producing water (A5 BP, A38, A32 BP, A34, A4 BP in Figure 3.6).
OWC Movement: 1989-1992
Initial hydrocarbon production in the J2 RB reservoir began in 7/89 with the A4 B
The A2 BP began producing from the J2 RB 1 month later, followed by initial product
in the J1 RB from the A-1 well in 9/89. The first significant water production came fro
the A4 BP in 1/91 (Figure 3.6). In the vicinity of the A4 BP well, we show that the
OOWC had moved upwards 24 m to 3760 m TVDSS by 1/91 in the J2 (Figure 3.7). S
we only have one datum point, we assume that this contact was horizontal.
OWC Movement: 1992-1993
By 1993, there is sufficient data to interpret that the OWC was is not horizontal (Fig
3.7). Water production began in the southern portion of the J2 RB with the A5 BP in 4
(Figure 3.6) . A PNC log run in 5/92 in the A5 BP imaged an OWC at 3694 m TVDS
(Figure 3.6). However, a PNC log run in 5/92 still showed oil downdip of the A5 BP in t
J2 and J1 of the A38. In fact, the A38 did not begin water production from the J2 RB u
12/92. Downdip of the A38, a PNC run in the A4 B in 5/92 indicated that the J2 had b
completely water-swept and that the J1 was still oil-filled. Based on these data, we pl
the OWC in 1993 at the top of the J2 perforations in the area of the A4 BP. This wa
highest level water reached in the compartment just above the A4 BP (Block B in Fig
3.7). The OWC in the vicinity of the A38 in 1993 was placed at the bottom of the
79
d atRB
Figure 3.7 Structural location of the OWC through time in the J2. The OOWC was locate3784 m TVDSS (12415 ft). Shaded areas represent bypassed oil at 1997 time in the J2 reservoir.
3900
3800
3700
3600
3500
3400
N
109-1 ST1A1
A35
A11 BP
A41
A33A34
A37
A5 BP
A36
A3 BP109-1
A32 BP
A2 BP
A38
A10
A4 BP
65-1 ST
A60
65-1
A9
OO
WC
Injector
Producer
Exploration
0 0.5 1.0(kilometers)
899193
95
97
??
??
93
A42ST
A39A31
A
A’
80
1993
no
ve-
C log
n in
n the
,
SS in
7).
e end
sed
2
(Fig-
l had
ion as
perforations (3720 m TVDSS). In the southern portion of the J2 RB, we placed the
OWC within the upper portion of the A5 BP perforations (3690 m TVDSS). There are
data to constrain a 1993 OWC in the J1, however, we still interpret some vertical mo
ment (Figure 3.8).
OWC Movement: 1993-1994
First signs of water movement in the J1 RB at the A4 BP was recorded by a PN
run in 6/93 (Figures 3.6 and 3.8). Also in 6/93, water was imaged with a PNC log ru
the A38 J2 RB just as it reached its 50% water-cut in 6/93. Updip, the A31 and A37
started producing from both the J1 and J2. PNC log runs were also performed updip i
A41, A37 and A31, all of which imaged oil in both the J1 and J2. By the end of 1993
water production began in the A32 BP and A2 BP from the J2.
OWC Movement: 1994-1995
Water encroachment by the end of 1995 in the J2 reached as high as 3540 m TVD
the vicinity of the A31 well which began water production in 7/94. (Figures 3.6 and 3.
The OWC above the A32 BP, however, was interpreted to lie at 3650 m. Other wells
updip of the A32 BP had also begun water production, or had even been shut-in by th
of 1995 (A2 BP and A34 in Figure 3.6).
We interpret the non-horizontal behavior of the OWC in the J2 to result from bypas
oil downdip of the A32 BP migrating up structure. The PNC log run in 6/94 in the A3
BP showed that the J2 was almost completely water-swept and the J1 was oil filled
ures 3.5 and 3.6). However, the A32 BP was PNC logged again in 10/94 after the wel
been shut-in and showed that water had swept completely through the J1. Oil saturat
81
s attionspay as
Figure 3.8 Structural location of the OWC in the J1 through time. The OOWC for the J1 i3755 m (21320 ft) TVDSS in 1989. Well penetrations outside of the J1 sand are penetrainto the top of the J2 where no J1 was present. Green areas represent regions of unsweptdetermined from the analysis in Figure 3.6.
A31
A33
A32 BP
A38
A4 BP65-1 ST
A60
65-1
A35
A3 BPA1
A41
0 0.5 1.0
(Kilometers)
N
A5 BP
109-1
A2 BP
C.I. = 50 m
A34
A11 BP
1ST
A42 ST
A39
A36
A10
A9
3500
3600
3700
3800
3400
3300
OOWC
A38 ST
A37
89
9597
95
A
A’91
93
82
th the
cing
of
ntly
lat-
he
cing
A3
ny
on.
P,
P to
ns
imaged by the PNC log in the J2 sand of the A32 BP shows an increase compared wi
run in 6/94. We interpret this reintroduction of oil into the A32 BP area to result from
trapped oil just above the now shut-in A38 migrating upstructure.
OWC Movement: 1995 to 1996
We have two very good constraints for the J1 1995 OWC. The A-1 started produ
water in 1/95 (Figure 3.6). At that same time, the A38 ST1 was drilled 175 m downdip
the A1 and imaged an OWC at 3700 m TVDSS (Figure 3.8) . This well was subseque
perforated in the top 1m of the J1 and it produced oil with very little water through our
est production report in 4/2000.
There was very little vertical movement of the OWC from 1995 to 1996 in the J2. T
only new developments in terms of water occured at the A37, where it started produ
water from the J2 in 6/95 (Figure 3.6).
OWC Movement: 1996-1997
The updip region of the J2 began producing water during 1996 (A11 BP, A35, and
BP in Figure 3.6). The A33 had been producing from the J2 through 1996 without a
water. That well sanded up in 6/96, still without any signs of significant water producti
We placed the J2 1997 OWC close to 3500 m TVDSS in the vicinity of the A35, A11 B
and A41. The J2 1997 OWC reaches down to 3550 m TVDSS northeast of the A3 B
reflect the late movement of the downdip oil seen in 1994 and 1995.
The 1997 OWC in the J1 is at the same depth as the J2 OWC, with slight variatio
seen near the A37 and A31 wells.
83
s into
of
l
re
ough
) to
of
do
t the
both
areas.
d 3.8
ove
nes.
the
0).
cal-
ical
General OWC Behavior
The drainage analysis presented in Figures 3.7 and 3.8 provides several insight
the dynamic behavior of the OWC through time in the J1 and J2 sands. Production
hydrocarbons and water influx from the underlying aquifer has resulted in the vertica
movement of the OWC by 284 m (932 ft) in the J2 and 255 m (837 ft) in the J1 (Figu
3.9). Initially, the OOWC in the J1 and J2 were not located at the same depth, even th
both sands are connected in the reservoir. This behavior is explained by Best (2002
result from perched water present in the J1 not being displaced during the charging
both sands. Movement of the OWC from 1989 through 1992 in the J1 and J2 initially
not track each other (Figure3.9). By 1993, the OWCs for both sands were located a
same depth (3720 m). We interpret that the OWC equilibrated to the same depth in
sands by 1993 because they are hydraulically connected above the aquifer in some
J1 and J2 Volumes, 1997
J1 and J2 net pay maps were constructed using the 1997 OWC in Figures 3.7 an
(Figures 3.10 and 3.). Net pay in Figure 3.10 shows the amount of oil-filled sand ab
the 1997 OWC and does not take into account the oil left behind in the water-swept zo
Net pay within the J1 in 1997 ranged from 0 to 30 m, with the thickest area of pay in
A11 BP area (Figure 3.11). Net pay within the J2 ranged from 0 to 20 m (Figure 3.1
The bulk volumes of reservoir rock and oil in place above the OWC in 1997 were
culated using the net pay maps in Figures 3.10 and 3.11 and the flow unit petrophys
84
Figure 3.9 Dip cross-section through the J1 and J2 sands illustrating the movement of theOWC through time. Cross-section taken from Figures 3.7 and 3.8.
89
8991
93
97
91
93
95
Dep
th (
m)
0 0.5 1.0
Kilometers
A A’
95
97
Year J2 J1 (m) (m)
1989 3784 37551991 3760 37351993 3720 37201995 3547 35401997 3500 3500
Subsurface Depth of OWCThrough Time
J1
J2
Deepest J1 and J2 Connection
85
the 1997
Figure 3.10 Net pay map for the J2 horizon in 1997. This map was constructed assumingdrainage scenario in Figure 3.7. The 0m net pay contour corresponds in map view to theOWC in Figure 3.7.
N
109-1 ST1A1
A35A11 BPA41
A33A34
A37
A5 BP
A36
A3 BP
109-1
A32 BP
A2 BP
A38
A10
A4 BP 65-1 ST
A60
65-1
A9
Injector
Producer
Exploration
0 0.5 1.0
(kilometers)
A42ST
A39A31
0
0
0
010
1020
5
1015
20
0
5
105
5
5
15
0
0
15
C.I. = 5 m
J2 RA
Block A
Block B
J2 RB
86
eC in
ed in
Figure 3.11 Net pay for the J1 in 1997. This map was constructed assuming the drainagscenario in Figure 3.8. The 0m net pay contour corresponds in map view to the 1997 OWFigure 3.8. We assume that since no wells produce from the J1 RA that net pay has notchanged since 1989. There is some (< 5m) of net pay in the A38 ST area which was logg1995. We also show that oil remains updip of the A4 BP in Block B and that Block neverexperienced a change in net pay.
A31
A33
A32 BP
A38
A4 BP65-1 ST
A60
65-1
A35
A3 BPA1
A41
0 0.5 1.0
(Kilometers)
N
A5 BP
109-1
A2 BP
C.I. = 5 m
A34
A11 BP
1ST
A42 ST
A39
A36
A10
A9
A38 ST
A37
Injector
Producer
Other
J1 RABlock A
Block B
J1 RB10
15
5
5
0
00
05
5
5
0
87
nd
f
3.14)
the
ickest
igure
a in
igure
d in
een
9 is
ining
eser-
for
en
properties (φ and 1-Sw) of Figures 2.23 and 2.24 and Table 2.6. Volumes of reservoir a
recoverable oil in 1997 for the J1 and J2 are summarized in Table 3.1.
Drained Pay Volumes for J1 and J2
A drained pay map shows the vertical thickness of sand that has been drained o
hydrocarbons (Figure 3.12). Drained pay maps for the J1 and J2 (Figures 3.13 and
were constructed by subtracting the 1997 net pay maps (Figures 3.10 and 3.11) from
1988 net pay maps (Figures 3.1 and 3.2). The J2 drained pay map shows that the th
areas of drained pay correspond to areas of intense seismic dimming (blue colors in F
3.13). Although movement of water was recorded from well logs and production dat
the J1, areas of drained pay do not correspond as well to areas of seismic dimming (F
3.14).
The ultimate goal in this drainage analysis is to compute from the maps presente
Figures 3.13 and 3.14 the volume of oil drained from the J1 and J2 reservoirs betw
1989 and 1997. This is accomplished by considering that the total volume of oil in 198
broken into 3 separate volumes:
(1) Volume of oil in place above the 1997 contact(2) Volume of non-recoverable oil remaining in place below the 1997 contact(3) Volume of oil recovered between 1989 and 1997
The bulk volume of reservoir which has been water-swept was calculated using the
drained pay maps in Figures 3.13 and 3.14. The volume of non-recoverable oil rema
in place below the 1997 OWC was calculated from the bulk volume of water-swept r
voir assuming a residual oil saturation (Sor of 0.25) and flow unit-dependent values
porosity (Figures 2.23 and 2.24 and Table 2.6). The volume of recovered oil was th
88
f
n 1989own
Figure 3.12 Schematic illustrating the physical meaning of a net pay difference map. TheOOWC is at 3784 m (12415 ft) TVDSS in 1989 before production started. After 7 years oproduction, the OWC in this model has moved updip 279 m (915 ft) to 3505 m (11500 ft)TVDSS. The hatchured area shows the net feet of pay sand that has been drained betweeand 1997. There is both an updip and downdip “feather” in this cross-section which is shon the net pay maps as the closely spaced net pay contours near 0 m pay.
3784 m TVDSS
3500 m TVDSS
1989 OOWC
1997 OWC
Net Pay Diff
Net Pay ’97
89
rtionresentith
wherers
ll
Figure 3.13 Drained pay difference map for the J2. The drained pay map represents the poof the reservoir which has been water-swept between 1989 and 1997. The amplitudes repthe difference map from the N-S LF normalization (Swanston et al, in review) displayed w90%, 95%, 99%, and 99.9% and 99.99% prediction bands. Hot colors represent places the J2 event has increased in absolute amplitude (brightened) over time while cooler colorepresent a decrease in amplitude through time (dimming). Gray indicates areas of smachanges in amplitude through time which are indistinguishable from noise.
90
ion ofesentith
wherers
ll
Figure 3.14 Net pay difference in the J1 Sand. The drained pay map represents the portthe reservoir which has been water-swept between 1989 and 1997. The amplitudes reprthe difference map from the N-S LF normalization (Swanston et al, in review) displayed w90%, 95%, 99%, and 99.9% and 99.99% prediction bands. Hot colors represent places the J2 event has increased in absolute amplitude (brightened) over time while cooler colorepresent a decrease in amplitude through time (dimming). Gray indicates areas of smachanges in amplitude through time which are indistinguishable from noise.
91
ve
the
ble
il-
997
om
in
ser-
-ft of
an
istory
mes
calculated by subtracting the total amount of oil remaining in the reservoirs both abo
and below the 1997 OWC from the initial 1989 volumes.
We compared the volume of drained oil we calculated using our drainage model to
measured cumulative production from the J1 and J2 RB reservoirs through 1997 (Ta
3.1). Actual cumulative production of oil from both reservoirs totalled 68.8 MMstb (m
lions of stock tank barrels). Cumulative production of oil at reservoir conditions by 1
was 98.8 MMrb. Our drainage model predicts that 90 MMrb of oil were extracted fr
both reservoirs. The drainage model predicts the actual amount of oil produced with
8%. The recovery factor (RF) is a ratio of the drained oil volume to the volume of re
voir rock which has been water-swept in terms of stb/ac-ft (stock tank barrels per ac
reservoir). For the J1 and J2 RB, this number is equal to 1058 stb/ac-ft.
The drainage model which predicts actual produced volumes within 8% assumes
Sor of 0.25. There is some uncertainty regarding the exact values for Sor, although our
assumption of 0.25 agrees with core data. Best (2002) produced the most accurate h
match for the J1 and J2 simulation when he used an Sor of 0.25 in all flow units besides
Unit 4 (Figures 2.23 and 2.24). Best (2002) used an Sor of 0.11 in Unit 4. We used the
drainage analysis presented in Table 2.1 to determine an average Sor for the J1 and J2 RB
reservoirs which would result in a perfect match between our predicted drained volu
and observed produced oil volumes. An Sor of 0.20 is needed to exactly match the pro-
duced volumes to the observed produced volumes.
92
of
ted
ll
rvoir
ation
e gas
on is
cous-
per-
ered.
ease
tic
al.,
rent
the
e to
puts
ids,
ct the
re.
Gassmann Model
Saturation and pressure changes have a significant effect on acoustic velocity
unconsolidated reservoir sands (Domenico, 1977; Landro, 2001). In an undersatura
reservoir, an increase in Sw and decrease in So due to water sweep will increase the overa
acoustic velocity (Gregory, 1976). In the case where an initially undersaturated rese
drops below the bubble-point, gas saturation will increase. An increase in gas satur
will dramatically decrease the velocity because of the presence highly compressibl
in the pore space (Domenico, 1977; Whitman and Towle, 1992). Even when saturati
held constant, changes in the elastic properties of the saturating fluid also affect the a
tic velocity of a rock (Jones et al., 1988; Clark, 1992; Alberty, 1996). The elastic pro
ties of the rock frame also change when the effective stress state of the reservoir is alt
Rock property changes include porosity reduction and frame stiffening due to a decr
in reservoir pressure and increase in vertical effective stress (Landro, 2001). Acous
velocity will increase as the rock frame is stiffened and porosity is reduced (Wyllie et
1956; Christensen and Wang, 1985; Zhang and Bentley, 2000).
Gassmann fluid substitution modeling uses the elastic moduli of the dry rock to
describe the overall changes in acoustic velocity when that rock is saturated with diffe
fluids (Gassmann, 1951; Domenico, 1977; Mavko et al., 1995; Alberty, 1996). We use
Gassmann Equations to model changes in the acoustic properties of the J Sands du
production-related changes in reservoir pressure, effective stress, and saturation. In
into the Gassmann Equations include porosity and the moduli of the solid grains, flu
and dry rock. When those parameters are known, the Gassmann Equation will predi
bulk p-wave modulus of the saturated rock for any changes in saturation and pressu
93
ulk
mod-
e
Acoustic P-wave (Vp) velocity is then calculated from the bulk P-wave modulus and b
density of the saturated rock.
Gassmann (1951) formulated a relation between a saturated rock’s bulk p-wave
ulus (M) and its corresponding dry frame (Kdry), grain (Ko), and pore fluid (Kfl) moduli,
. (3.2)
The constant S depends on the dry rock Poisson’s ratio (ν),
. (3.3)
The modulus of the composite fluid mixture (Kfl) is determined using the Reuss average
(Dvorkin et al., 1999) of each fluid’s modulus (oil, gas, and water):
. (3.4)
Acoustic p-wave velocity (Vp) is related to the bulk p-wave modulus (M) solved in th
Gassmann Equation (Equation 3.2) and the bulk density (ρb):
. (3.5)
M SKdry
1Kdry
Ko-----------–
2
φK fl-------- 1 φ–( )
Ko----------------
Kdry
Ko2
-----------–+
-------------------------------------------------+=
S3 1 υ–( )
1 υ+( )--------------------=
1K fl--------
Sw
Kw-------
So
Koil---------
Sg
Kg------+ +=
VpMρb-----=
94
con-
d-
.2.
us
rela-
e rock
e the
es
e last
e
(1952)
count
ump-
ugh-
000).
a one-
For application of Equations 3.2 through 3.5, we need to know the basic elastic
stants of the rock and fluids. Ko is the modulus for pure quartz (38000 MPa). Fluid mo
uli for oil (Koil), gas (Kg), and water (Kw) were computed from known correlations
(Batzle and Wang, 1992). The dry rock poisson ratio (ν) is unknown and we assume a
value based on previous studies. Kdry is also unknown, but can be calculated when the
bulk density and Vp of a rock has been measured using Equation 3.5 with Equation 3
There are several assumptions when applying the Gassmann Equations to poro
rocks. The pores of the rock all must be interconnected and its fluid must not move
tive to the frame during the onset of an acoustic wave (Gassmann, 1951). Second, th
must be under undrained conditions, where pore fluids are not allowed to enter or leav
system. Third, the shear modulus (µ) is independent of fluid saturation and only chang
as a function of porosity and effective stress (Gassmann, 1951; Berryman, 1999). Th
assumption is that the pore fluid does not cause chemical changes in the rock’s fram
(Gassmann, 1952; Wang, 2000).
Frequency is also an issue when applying the Gassmann equations. Gassmann
derived his equations assuming zero-frequency (infinite wavelength) and does not ac
for dispersion. High porosity and permeability sands have been shown to fit the ass
tions of the Gassmann Equations because the fluids equilibrate and allow for flow thro
out the pore space during the onset of a compressional wave (Blangy, 1992; Wang, 2
For example, Blangy (1992) compared ultrasonic laboratory measurements of Vp in
unconsolidated sands with Gassmann predictions and showed that there is close to
to-one correlation.
95
a).
i/ft in
rved
ess is
her.
.
g of
pene-
ses
sim-
ver-
e
74)
80;
s in
s of
Porosity, Effective Stress, and Vp Observations
Porosity in the Bullwinkle J Sands is proportional to effective stress (Figure 3.15
Effective stress was calculated assuming a constant hydrostatic gradient of 0.465 ps
the water leg and a constant overpressure of 20.1 Mpa. Flemings et al. (2001) obse
higher porosities in the J3 sand at the top of structure where the vertical effective str
low and lower porosities at the base of the sand where vertical effective stress is hig
The dashed line in Figure 3.15a is the compaction trend observed by Flemings et al
(2001) for the J3 sand. The two wells with porosity logs that penetrated the water le
the J2 demonstrate that porosity in the J2 may also be stress-controlled. One well
trated the water leg of the J1 in the 65-1 (Figure 2.2)
Acoustic velocity (Vp) in the water leg of the J Sands increases as porosity decrea
(Figure 3.15b). A linear regression between porosity and Vp for all the data points shows
that Vp tends to be higher for sands with lower porosities. Blangy (1992) observed a
ilar trend in the Troll sands (dashed line in Figure 3.15b). The Troll sands are not o
pressured, but are at approximately the same effective stress state (~15 MPa) as th
Bullwinkle J Sands (Blangy, 1992). A universal trend observed by Gardner et al. (19
overpredicts porosity for the J Sands based on Vp. The Vp scale in Figure 3.15b is
expanded in Figure 3.15d to show how the Bullwinkle Vp/porosity relationship compares
with some other well known porosity transforms (Wyllie et al., 1956; Raymer et al., 19
Han et al., 1986). The Wyllie et al., Raymer et al., and Han et al. porosity transform
Figure 3.15d are all empirical and were derived in cemented and consolidated sand
various porosities. They all grossly underpredict the porosity/Vp behavior exhibited at
Bullwinkle because they were not meant to be applied to unconsolidated sands.
96
nity waswell
ments
Figure 3.15 Effective stress, porosity, and Vp observations from the Bullwinkle J Sands. Opecircles represent J3, black circles represent J2, and gray circle represents the J1. Poroscalculated from the RHOB log and an average value for DPHI and DT were taken in eachwhich penetrated each sand below the OWC. Effective stress for the J3 was taken fromFlemings et al., 2001. Effective stress in the J1 and J2 were inferred from RFT measurein the 109-1 J2 sands.
14 15 16 170.28
0.29
0.3
0.31
0.32
0.33
0.34
Vertical Effective Stress (Mpa)
Por
osity
A5 BP
A4 BP
65-1 ST
A36
A36
109-1 A2 BP
A32 BP
65-1 ST
0.30 0.32 0.342500
2550
2600
2650
2700
2750
Vp (
m/s
)Porosity
14 15 16 172500
2550
2600
2650
2700
2750
Vertical Effective Stress (Mpa)0.28 0.30 0.32 0.34
2200
2400
2600
2800
3000
3200
3400
3600
3800
65-1 ST
Blangy, 1992
Vp = 3384 - 2415φ R = 0.40
Wyllie et al. (1956)Raymer et al. (1980)Han et al. (1986)
Blangy (1992)
Gardner et al. (1974)
Gardner et al. (1974)
Porosity
Vp (
m/s
)
Vp (
m/s
)Flemings et al. (2001)
0.28
0.322
0.310
0.336
0.301
0.310
0.290
0.319
0.324
0.316
0.290
a) b)
c) d)
Vp = 63
σ + 16
70 R
= 0.
75
v
2
97
ss
and
nd
ction,
the
ress
y,
ant
-
tions
9).
a. A
Velocity in the water-saturated J Sands is strongly controlled by the effective stre
state (Figure 3.15c). Rocks at a lower effective stress overall have a higher porosity
lower Vp (Figure 3.15c) while rocks with higher effective stress have a lower porosity a
higher Vp. This behavior is important because it suggests that Vp will increase in the res-
ervoir as the pore pressure is reduced and effective stress is increased due to produ
even while saturations remain constant.
Porosity, Effective Stress and Kdry Observations
The key to understanding the behavior seen in Figure 3.15c is to recognize that
overall modulus (incompressibility) of a rock increases with an increase in effective st
(Gregory, 1976; Eberhart-Phillips et al., 1989). The incompressibility of the dry rock
devoid of fluids is termed Kdry and can be calculated from sonic log data when porosit
Ko, Kfl, andν are known from Equation 3.2. For the water leg data, we assumed that Ko =
38000 MPa (quartz), Kfl = 3800 MPa (brine with salinity of 220 kppm), andν = 0.18. Vp
, φ, andρb were taken from well log measurements (Table 3.3) We assumed a const
value for the dry rock poisson’s ratio (ν) of 0.18 because it is a typical value for uncon
solidated Gulf of Mexico reservoir sands (Spencer et al., 1994). Under these assump
Equation 3.2 is solved for Kdry in Table 3.3 using a method first developed by Gregory
(1977) and put to use in similar studies by Burkhart (1997) and Benson and Wu (199
The J Sand water-leg data show that Kdry increases at higher effective stress. Kdry in
Figure 3.16a ranges from 2.98 to 3.3 GPa over an effective stress interval of 2.2 MP
first order fit to the data in Figure 3.16a reveals a linear relationship between Kdry andσv
98
rclesin
ion.
Figure 3.16 Relationships between Kdry, effective stress and porosity for the Bullwinkle JSands. Open circles represent J3 sand, black circles represent J2 sand, and the gray cirepresents J1 sand well penetrations. a) Kdry as a function of effective stress using the data
Table 3.3. DPHI is labeled for each well penetration. A first order fit to all data give an R2 of0.61. b) Kdry as a function of porosity. The effective stress is labeled for each well penetrat
A first order fit to the data give an R2 of 0.21.
13 14 15 16 17
2.6
2.8
3.0
3.2
3.4
3.6
0.319
0.336
0.310
0.301
0.290
0.322
0.324
0.316
0.310
0.290
Vertical Effective Stress (MPa)
Kdr
y (G
Pa)
0.30 0.32 0.34
2.6
2.8
3.0
3.2
3.4
3.6
15
15.6
16
16.6
15.6
14.7
14.4
14.7
15.1
15
Porosity0.28
Kdr
y =
0.39
74*σ
- 2.
9284
R =
0.6
1
v
Kdry = -10.49φ + 6.4107 R = 0.21
a) b)
J1J2J3
99
K
have
stress
la-
uc-
Pa in
ure
e ini-
92).
ver
ngy
ed his
d
mic
33
r
over the initial effective stress state in the water leg of the J Sands (14 to 16.5 MPa).dry
shows a weak dependence with regards to porosity in Figure 3.16b. Other workers
documented Kdry/porosity relationships and show that Kdry increases as porosity
decreases (Murphy et al., 1985; Nur, 1998). Their models assume that the effective
state of the rock is constant and that porosity is the only variable.
Effective Stress/Kdry Model
Our goal in analyzing the Kdry and effective stress data in Figure 3.16a is to find a re
tionship which describes how Vp changes as the effective stress is increased over prod
tion time scales. Effective stress for the Bullwinkle J Sands reached as high as 30 M
1997 due to production-related changes in pore pressure. The data we show in Fig
3.16a was taken from a very limited range of effective stresses (14 to 16.5 MPa) at th
tial conditions of the reservoir. Kdry for the Bullwinkle data increase much more rapidly
than what has been shown in the lab for similar unconsolidated sands by Blangy (19
The J Sand data trend in Figure 3.16a is interpreted to result from deformation o
geologic time scales rather than production time scales (Flemings et al., 2001). Bla
(1992) demonstrated through laboratory measurements how the dry rock Vp and Vs
increase due to an increase in the effective stress for unconsolidated sands. We us
data to calculate Kdry as a function of effective stress under laboratory conditions and
show how this compares to the observations at Bullwinkle (Figure 3.17a). Packwoo
(1996) also utilized the data from Blangy (1992) to investigate frame stiffening for seis
modeling of the Troll Field. Sample 29 from Blangy (1992) has an initial porosity of 0.
and Kdry of 3 GPa under an effective stress of 15 MPa. This falls within the values fo
100
ryationth
and9-1
ase inould
o
Figure 3.17 a) Kdry as a function of effective stress for Bullwinkle data (circles) and laboratodata from Blangy (1992) (solid triangles). The solid lines are empirical fits based on Equ6. The dashed line is a theoretical Kdry/effective stress model for a pack of quartz spheres wia porosity of 0.315 and a critical porosity of 0.40 (Dvorkin et al., 1999). b) Stress pathsexpected for the 109-1 and A36. The point A represents initial conditions for the 109-1 J3point B represents initial conditions for the A36 J3. The Bullwinkle data suggest that the 10would progress from A to B as the effective stress is increased. We propose that this increKdry for such a small increase in the effective stress is unreasonable and that the 109-1 wactually follow the path from A to A’. The A36 would follow the path B to B’. The paths A tA’ and B to B’ are were determined using Equation 6.
10 15 20 25 302.0
2.5
3.0
3.5
4.0
4.5
Vertical Effective Stress (MPa)
Kdr
y (G
pa)
Sample 29 (Blangy, 1992)J SandsUncemented Sand Model (Dvorkin et al., 1999)
10 15 20 25 30Vertical Effective Stress (MPa)
A
A’B
B’
a) b)
2.0
2.5
3.0
3.5
4.0
4.5
109-1
A36
101
ffective
.17a
hang
rela-
the
sing
for
797,
edict
Kdry we calculated from the sonic log data for the J Sands at ~15 MPa. Kdry increased for
the sample as the effective stress increased and reached as high as 4 GPa under an e
stress of 30 MPa. The rate at which Kdry increased for Sample 29 was much less than
what is suggested by the Bullwinkle data (open circles). The solid lines in Figures 3
and 3.17b are empirical fits to the Blangy (1992) data using a method proposed by Z
and Bentley (2000).
Zhang and Bentley (2000) used the data of Han et al. (1985) to derive empirical
tions between Kdry and effective stress. They show that the change in Kdry as a function of
the effective stress could be approximated by
, (3.6)
where A and B are empirically derived constants, Kdry is in GPa andσv is in MPa. Inte-
gration of Equation 5 allows for Kdry to be solved for any effective stress,
, (3.7)
where C is a constant from the integration. Zhang and Bentley (2000) show that for
data of Han et al., 1985, A = 0.746 and B = -0.0773. They then tested Equation 3.7 u
the data of Gregory, 1977 and found that it predicted Kdry within 10 %.
We used the Blangy (1992) data in Figure 3.17a to derive the constants A and B
Equation 3.7. The constants A and B for the Blangy (1992) data are 0.362 and -0.0
respectively. The constant C for the Blangy (1992) data was calculated since Kdry is
known at 10 MPa. We then used our values for A and B along with Equation 6 to pr
Kdryd
σvd-------------- Ae
Bσv=
KdrydAB---e
Bσv C+=
102
ate C
arate
ur
.17b.
effec-
posed
ath of
er
how
to 30
ed
m-
al
the Kdry behavior of the 109-1 and A36, using the data in Table 3.3 to derive a separ
for each well. Solving for a separate value for C allows us to exactly match the Kdry at ini-
tial conditions for both the 109-1 and A36, and then model the rock’s stress path sep
from one another.
The stress path taken by the 109-1 and A36 data points will differ according to o
model (Figure 3.17b). For the 109-1 at initial conditions,σv = 14.7 MPa and Kdry = 2.5
GPa. The in-situ measurements of Kdry in the Bullwinkle J Sands as a function of effec-
tive stress would suggest that the 109-1 would take the stress path A to B on Figure 3
We propose that production related changes rock properties due to the increase in
tive stress take place over time scales much closer to laboratory measurements as op
to geologic time. Under production-induced changes in effective stress, the stress p
the 109-1 would be to follow A to A’ (Figure 3.17b). Rocks which are initially at a high
effective stress state (A36 in Figure 3.17a), will take the path B to B’. Both models s
an increase of Kdry between 1.5 and 2.0 GPa as the effective stress increases from 15
MPa.
Velocity Model for Water-Saturated Rocks Under Pressure
The Kdry relationship we found for the 109-1 and A36 wells in Figure 3.17a was us
to model how Vp increased in rocks 100% saturated with water as the effective stress
increased from 15 to 30 MPa. Vp was calculated using Equations 3.2 through 3.5 assu
ing Kfl = 3800 MPa and Ko = 38000 MPa. Kdry was calculated for each well, using the
paths A to A’ and B to B’ in Figure 3.17b for the 109-1 and A36, respectively. At initi
103
s
e
.
Figure 3.18a) Data from the J Sands showing how Vp increases as a function of effective stresassuming for both the solid and dashed lines that the stress path (increase in Kdry as a functionof effective stress) would follow A to A’ for the 109-1 and B to B’ for the A36. The dashed linassumes that the porosity remains constant, even though Kdry is increasing. The solid linerepresents the increase in Vp as both Kdry is increased and the porosity is reduced by ~3 p.udue to compaction.
10 15 20 25 302500
2550
2600
2650
2700
2750
2800
2850
Vertical Effective Stress (MPa)
Vp (
m/s
)
10 15 20 25 302500
2550
2600
2650
2700
2750
2800
2850
Vertical Effective Stress (MPa)
A
A’A’’
B
B’B’’
109-1
A36
a) b)
With porosity change
Without porosity change
104
ir-
d
ased
to
e
to
odu-
le
er
how
h a
f
conditions for both wells, Kdry is taken from Table 3.2, and corresponds to the black c
cles in Figure 3.18a.
We calculated Vp under two conditions (Figure 3.18a). For the first condition, we
model the change in Kdry as shown in Figure 3.17b, but keep porosity constant (dashe
lines in Figure 3.18a). For the second condition, we model the change in Kdry as shown in
Figure 3.17b, but also decrease the porosity by 3 p.u. as the effective stress is incre
from 15 to 30 MPa (solid lines in Figure 3.18). This porosity reduction corresponds
pore compressibility of 50x10-6 psi-1 . Vp in both the 109-1 and A36 increases as the
effective stress and Kdry increase. Overall, we observe about 200 m/s increase in Vp using
this model as each well travels from A to A’ and B to B’ in Figure 3.18b. If we assum
that porosity reduction is occurring in addition to frame stiffening, we show that Vp
increases by ~10 m/s more than it would if we kept porosity constant (A to A’’ and B
B’’ in Figure 3.18b).
Saturation Effects on Velocity and Seismic Amplitude
The saturated bulk modulus of unconsolidated sands is highly dependent on the m
lus of the saturating fluid (Gregory, 1976; Domenico, 1977; Alberty, 1997). Bullwink
oils have moduli which are ~1/3 that of brine. As a result, oil sands have a much low
value for Vp, impedance and higher absolute value for RFC than brine sands. We s
the effect of saturation on Vp, acoustic impedance, and RFC by considering a rock wit
Kdry of 2570 MPa and a porosity of 0.31 (Figure 3.19). Vp was calculated over a range o
water saturations using Equations 3.2 through 3.5. Porosity and Kdry were kept constant.
105
gas.
Figure 3.19 Expected changes in Vp, impedance and RFC due to decrease in Sw. Three fluidsare considered (Table 3.4): 1) oil at initial J2 conditions, 2) oil at 1997 J2 conditions, and 3)0 0.2 0.4 0.6 0.8 11700
1800
1900
2000
2100
2200
2300
2400
2500
2600
Sw
Vel
ocity
(m
/s)
0 0.2 0.4 0.6 0.8 1−0.35
−0.3
−0.25
−0.2
−0.15
−0.1
−0.05
0
Sw
RF
C
0 0.2 0.4 0.6 0.8 13.0
3.5
4.0
4.5
5.0
5.5
6.0
Sw
Impe
danc
e (k
g−m
/s e
6)
a) b)
c)
12
3
1 2
3
1 2
3
Oil (1989 Conditions)Oil (1997 Conditions)Gas (1989 Conditions)
Oil (1989 Conditions)Oil (1997 Conditions)Gas (1989 Conditions)
Oil (1989 Conditions)Oil (1997 Conditions)Gas (1989 Conditions)
106
ure has
xpand,
ion
he
for a
d has
the
modu-
d rock
Case #1 represents the J2 in the 109-1 at initial conditions where Koil = 1300 MPa. Case
#2 represents that same sand, this time with a lighter oil (Koil = 1050 MPa). The lighter oil
in Case #2 has the same GOR as the oil in Case #1, except that the reservoir press
been decreased by 15 MPa. This decrease in reservoir pressure causes the oil to e
which in turn causes it to have a lower density and Koil (Batzle and Wang, 1992). Case #3
is a gas sand with no oil present.
Gassmann fluid substitution in Figure 3.19 shows that both fluid type and saturat
have a significant effect on the acoustic signature of the reservoir. At an Sw = 1, all three
cases show the same values because the rock is 100% saturated with water. As Sw
decreases and the hydrocarbon saturation increases, Vp and impedance decrease and the
magnitude of the RFC increases for all 3 cases.
The degree to which the acoustic properties of the rock change is controlled by t
fluid type (Figure 3.19). For Case #1, velocity decreased from 2550 m/s to 2080 m/s
saturation change from 1 to 0. Impedance decreased from 5.50 to 4.25 kg/m2s x 106. The
RFC changed from -0.05 to -0.18 as the oil saturation increased (Sw decreased). For Case
#2, Vp at 100% oil saturation was 80 m/s less than it was for Case #1. The lower Vp at
100% oil saturation occurs because the hydrocarbon saturating the pores is lighter an
a lower modulus. The lower Vp for Case #2 decreased the impedance by 2 kg/m2s x 106
and increased the magnitude of the RFC by 0.02. The gas sand in Case #3 showed
greatest impact on the acoustic properties because gas has much lower density and
lus than oil. For Case #3, as the gas saturation increased from a 100% brine saturate
107
is
5.
hit-
idly
e and
was
ce
by as
rby
9-1
tion
ining
to 20% gas saturation (0.80 Sw), Vp decreased from 2550 m/s to 1850 m/s. Impedance
also drastically dropped from 5.5 to 3.4 kg/m2s x 106 as the gas saturation increased. Th
large difference in the impedance then increased the magnitude of the RFC to -0.29
Changes in Vp for Case #3 shows at first some non-intuitive behavior at lower Sw. Vp
actually starts to increase slightly as Sw is reduced from 0.30 to 0 (Figure 3.19a). This
behavior has been documented by Domenico (1977) in the lab and is explained by W
man and Towle (1992) in terms of Equation 3.5. At higher Sw, as the gas saturation
increases (Sw decreases), the p-wave modulus (M) of the rock decreases more rap
than the bulk density. The slight increase in Vp from Sw = 0.3 to Sw = 0 occurs because
the bulk density now is decreasing faster than the p-wave modulus. Both impedanc
RFC still show a decrease as Sw decreases (Figure 3.19b,c)
Coupled Pressure and Saturation Effects on the Acoustic Properties
Model of Acoustic Response due to Water Sweep and Changes in Effective Stress
We consider first the acoustic property changes in the 109-1 J2, where the sand
initially oil-saturated in 1989 and then water swept by 1997. The time-lapse differen
amplitude map in Figure 3.13 shows that the 109-1 area had decreased in amplitude
much as 70% between 1989 and 1997. Production and PNC log data from the nea
A32 BP well (Figures 3.3, 3.5, 3.6, and 3.7) show that the OWC had reached the 10
level by 1994. Initial porosity in the 109-1 J2 has an average value of 0.31. Compac
due to an increase in effective stress reduced the porosity to 0.28 by 1997. The rema
rock and fluid properties are summarized in Table 3.5.
108
h
il pro-
as
-
from
, the
e in
el the
ted
97,
e
the
the
The modeled acoustic properties within the 109-1 follow two distinct paths throug
time. The acoustic properties followed the path A to A’ while Sw was constant and the
effective stress increased from 12 to 25 MPa (Figure 3.20). This path represents o
duction with no change in saturation and changes in pressure only while the OWC w
still located downdip of the 109-1. During this time, the model predicts a Vp increase
from 2080 m/s to 2210 m/s (Figure 3.20a). This increase in Vp results in an increase of
the impedance from 4.30 to 4.6 kg/m2s x 106 (Figure 3.20b) and decrease in the magni
tude of the RFC from -0.18 to 0.14 (Figure 3.20c).
The path A’ to A’’ represents water-sweep in the 109-1 area, where Sw increased
0.10 to 0.75 and the effective stress increased from 25 to 30 MPa. During this time
model predicts a Vp increase from 2210 m/s to 2490 m/s (Figure 3.20a). This increas
Vp results in an increase of the impedance from 4.60 to 5.45 kg/m2s x 106 (Figure 3.20b)
and decrease in the magnitude of the RFC from -0.14 to -0.06 (Figure 3.20c).
The modeled acoustic properties for 1989 and 1997 conditions were used to mod
seismic response in the 109-1 (Figure 3.21). The J2 is initially oil-filled and the predic
Vp for 1989 conditions agree with the sonic log measurements (Figure 3.21). By 19
the J2 was water-swept and the model predicts an increase in Vp. Impedance increased by
27% from 4.30 to 5.45 kg/m2s x 106 in the 109-1 (Figure 3.21) and the magnitude of th
RFC decreased by 70% from -0.18 to -0.06 (Figure 3.20c) from 1989 to 1997.
Synthetic seismic modeling of this 70% decrease in the magnitude of the RFC in
J2 agrees with time-lapse seismic observations (Figure 3.22). Extracted traces from
109
l are
cing toint A’y in
Figure 3.20 Acoustic property changes in the 109-1 J2 sand as a function of Sw and effectivestress. Contours lines are iso-Sw lines. The rock and fluid properties used for this modeshown in Table 3.5. a) Changes in Vp as a function of Sw and effective stress. b) Changes inimpedance as a function of Sw and effective stress. c) Changes in RFC as a function of Sw andeffective stress. The J2 sand in the 109-1 follows the path A to A’ while the well is produoil without water. Sw remains constant and the only changes in acoustic properties from AA’ are due to changes in effective stress. The 109-1 J2 begins producing water at the poand we assume that Sw increases from 0.10 to 0.75 at the time of the second seismic surve1997.
15 20 25 30
2100
2200
2300
2400
2500
2600
2700
15 20 25 30
−0.18
−0.16
−0.14
−0.12
−0.10
−0.08
−0.06
−0.04
−0.02
15 20 25 30
4.4
4.6
4.8
5.0
5.2
5.4
5.6
5.8
6.0
0
0.2
0.4
0.6
0.8
1.0
0
0.2
0.4
0.6
0.8
1.0
0
0.2
0.4
0.6
0.8
1.0
a) b)
c)
A
A’’
A
A’’
A
A’’
A’
A’ A’
Effective Stress (MPa) Effective Stress (MPa)
Impe
danc
e (k
g/s2
m)
1x10
6
Effective Stress (MPa)
RF
C
V (
m/s
)p
110
15tion in4. inckcurve
Vn
Figure 3.21 Fluid substitution for the 109-1. The J2 is initially oil-saturated and the J3 iswater-saturated at initial conditions in 1989. By 1997, both reservoirs had experienced aMPa increase in effective stress causing both sands to compact by ~3 p.u. Water saturathe J2 increased from 0.11 to 0.75 after the OWC swept through the 109-1 region in 199Gassmann fluid substitution was performed in the J2 and J3 for both the initial conditions1989 and the post-production conditions in 1997 (Table 3.5). The gray line in the right trarepresents the sonic measurements taken when the 109-1 was drilled in 1984. The blackrepresents the modeled Vp log assuming 1989 conditions. The dashed line represents the plog after fluid substitution and frame stiffening were taken into account with the GassmanEquations and represents the acoustic properties of the J2 in 1997.
Vp (Sonic Log)(m/s)
Vp (’89)
Vp (’97)
(’89) (’97)
J2
J3
(m/s)
(m/s)
ρv ’97
ρv ’89METERS
kg/s m 1e62
kg/s m 1e62
111
the
aree wasre
ch lies and
Figure 3.22 Seismic model for water-sweep in the 109-1 J2 sand. a) Extracted traces fromNS LF normalization (Swanston et al, in review) and synthetic traces obtained from fluidsubstitution modeling. b) Observed seismic difference from the N-S LF normalizationcompared with the modeled synthetic difference. RFC calculated under 1989 conditionsshown as the gray bars while RFC under 1997 conditions are solid black bars. Impedanccalculated from the modeled Vp and RHOB logs. The gray boxes which overlie the traces athe prediction bands as calculated by Swanston et al. (in review). Seismic differences whioutside the box are statistically shown to be caused by changes in rock and fluid propertienot noise (Burkhart et al., 1999; Swanston et al., in review).
NSLF ’89 Synth ’89 NSLF ’97 Synth ’97METERS
J2
J3
NSLF Diff.
Synth Diff.
METERS
J2
J3
a)
b)
Imped. (’97)
Imped. (’88) RFC (’88)
RFC (’97)kg-m/s 1e6
kg-m/s 1e6
112
ed as
ained
The
97
997
ed
eals
33.
ugh
n 100
ring
rvoir
free
under
the
as
time-
1988 and 1997 surveys (Swanston et al., in review) show that the top of the J2 is imag
a zero-crossing. The synthetic seismic traces for 1988 and 1997 conditions were obt
by convolving a 90 degrees phase shifted 15 Hz. Ricker wavelet with the RFC values.
observed and modeled amplitudes within the J2 are higher in the 1988 case than 19
(Figure 3.22a). Both the observed and modeled difference between the 1989 and 1
amplitudes show a 70% decrease in amplitude.
Acoustic Modeling of Gas Exsolution and Effective Stress Changes in the J2
There is a markedly different time-lapse signature in the A33 well region compar
with the 109-1 (Figure 3.13). The time-lapse work of Swanston et al. (in review) rev
that there has been no noticeable change in seismic amplitude through time at the A
The drainage analysis in the J2 shows that the A33 remained hydrocarbon-filled thro
1997 (Figure 3.7). Production data reveal that the A33 never experienced greater tha
bbl/d water production (Figure 3.4), although the well did sand up and was shut-in du
1996 (Table 3.2). It appears from production data in the A33 that this area of the rese
had dropped below the bubblepoint pressure of the reservoir in 1992. At this point, a
gas phase began to form in the pore space. We modeled the effect of gas exsolution
constant porosity and effective stress and showed that both Vp and impedance should
decrease with an increase in gas saturation (Figure 3.19) and that the magnitude of
RFC should increase. An increase in RFC through gas exsolution should be visible
brightening through time, although there is no noticeable change in amplitude in the
lapse difference map in the A33 area (Figure 3.13).
113
ction
ges in
lution
n stiff-
. We
ove
the
.7)
gan to
point
corre-
tant,
gas
n the
We propose for the A33 that the competing effects of gas exsolution and compa
cause no detectable changes in the acoustic impedance and RFC. These two chan
rock and fluid properties have opposite effects on the acoustic properties. Gas exso
decreases the impedance and increases the magnitude of the RFC while compactio
ens the rock and increases the impedance while reducing the magnitude of the RFC
use the Gassmann Equations coupled with the Kdry model in Figure 3.17 to show that it is
possible to explain the time lapse signature in Figure 3.13.
The Gassmann model for the A33 predicts an increase in Vp and impedance while the
reservoir remains undersaturated (Figure 3.23). Initially, the reservoir pressure is ab
the bubblepoint (Table 3.6). From 1989 to 1992, the acoustic properties follow along
path A to A’ in Figure 3.23. Along A to A’, there are no changes in saturation (Table 3
and the effective stress increases from 10 to 20 MPa. The modeled Vp increases from
2030 m/s to 2210 m/s due to changes in the effective stress only. This increase in Vp
results in an increase of the impedance from 4.31 to 4.75 kg/s2m x 106 (Figure 3.23b) and
decrease in the magnitude of the RFC from -0.19 to -0.145 (Figure 3.23c).
The acoustic properties changed drastically in the A33 once a free gas phase be
form. Gas exsolution began when the reservoir pressure dropped below the bubble
pressure in 1992 and the reservoir entered the saturated region of Figure 3.23. This
sponds to an effective stress of 20 MPa (Figure 3.23). At this point, Sw remains cons
but the gas saturation (Sg) increases. For any given effective stress, Vp and impedance
decrease as Sg increases. Vp and impedance decrease because the presence of a free
phase reduces the bulk modulus of the rock. There is uncertainty in Sg in 1997 whe
114
Thelepoinrhes thewhile
ervoirr equal
thece the
’ to B
hanges
Figure 3.23 Acoustic property changes in the A33 J2 using Gassmann fluid substitution. dashed line represents the effective stress state of the reservoir when it reaches the bubbpressure. Pore pressure is 42 MPa and the effective stress is 19.8 MPa when the J2 reacbubblepoinr pressure at the A33. The contours represent gas saturation (Sg). Sg equals 0the reservoir is still above the bubblepoint pressure (undersaturated region). When the respore pressure drops below the bubblepoint pressure, free gas exsolves and Sg is no longeto 0. The acoustic properties follow the path A to A’ while the reservoir is still above thebubblepoint pressure (undersaturated). All saturations from A to A’ remain constant, andonly changes in acoustic properties occur because of changes in the effective stress. Onreservoir reaches the bubbleponit pressure, the acoustic properties will follow the paths Aor A’ to B’, depending on what Sg is in 1997. a) Changes in Vp as a function of Sg andeffective stress. b) Changes in impedance as a function of Sg and effective stress. c) Cin RFC as a function of Sg and effective stress.
B
B’
a) b)
A’
10 15 20 252000
2050
2100
2150
2200
2250
2300
Effective Stress (MPa)
pV
(m
/s)
10 15 20 254.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
5.0
Effective Stress (MPa)
Impe
danc
e (k
g/s2
m)
1x10
6
0
0
0.2
0.3
0.4
0.5
A
B0.1
B’
c)
0
0.2
0.3
0.4
0.5
0.1
A’
A
0
Undersaturated Saturated Undersaturated Saturated
10 15 20 25−0.20
−0.19
−0.18
−0.17
−0.16
−0.15
−0.14
−0.13
Effective Stress (MPa)
RF
C
0
0.2
0.3
0.4
0.5
0.1
A’
B
B’
A
0
Undersaturated Saturated
115
nd Sg
.20
oth
.24b).
atch
been
ismic
both
erty
pres-
e 15
ective
tant
s at
he
el
A33 has reached an effective stress of 25 MPa, so we consider two cases: Sg = 0.20 a
= 0.40. The acoustic properties of the reservoir will follow the path A’ to B for Sg = 0
or A to B’’ for Sg = 0.40 when an effective stress of 25 MPa is reached in 1997.
The seismic modeling for the A33 includes the two cases shown in Figure 3.23. B
cases predict very little change in the impedance between 1989 and 1997 (Figure 3
Synthetic seismograms computed from the model for the 1989 and 1997 conditions m
actual seismic traces (Figure 3.24a). It is apparent from Figure 3.24a that there has
very little change in the seismic amplitude between 1989 and 1997. The modeled se
responses for both cases agree with the observed difference (Figure 3.24b).
Summary of Gassmann Model
The acoustic properties of the J2 sand were calculated as a function of depth at
initial (1989) and post-production (1997) conditions (Figure 3.25). The acoustic prop
profiles in Figure 3.24 were constructed using Equations 3.2 through 3.5. Reservoir
sure decreased by 15 MPa due to production of fluids between 1989 and 1997. Th
MPa decrease in reservoir pressure resulted in a 15 MPa increase in the vertical eff
stress. Initial porosity in 1989 is held constant as a function of depth at 0.32 and
decreased to 0.28 by 1997 as a result of compaction. Water saturation is held cons
above the OOWC in 1989 at 0.15. Water saturation above the OWC in 1997 remain
0.15 while Sw in the water-swept zone changes from 0.15 in 1989 to 0.75 in 1997. T
dry rock modulus (Kdry) was calculated as a function of effective stress using the mod
presented in Figure 3.17.
116
).
Figure 3.24 Seismic modeling of gas coming out of solution in the A33 well. a) Extractedtraces near the A33 well from the N-S LF ‘89 and ‘97 surveys (Swanston et al., in reviewSynthetic traces were obtained using a 15 Hz Ricker wavelet and the acoustic propertiescalculated with the Gassmann Equations.NS-LF ’89
Synth ’89
NSLF ’97
Synth ’97Sg = 0.20
J2
Synth ’97Sg = 0.40
a)
NS-LF Diff.
Synth Diff.Sg = 0.20
METERS
Imped. (’97)
Imped. (’97)
kg/s m 1e62
Imped. (’89)
kg/s m 1e62
kg/s m 1e62
Synth Diff.Sg = 0.40
Sg = 0.20Sg = 0.40
b)
J2
117
ted9 and89 and is
Figure 3.25 Acoustic properties of the J2 sand as a function of depth at 1989 and 1997conditions. The OOWC is located at 3784 m (12415 ft ) TVDSS. The OWC in 1997 is locaat 3500 m (11480 ft) TVDSS. There is a 15 MPa increase in effective stress between 1981997. Three distinct zones are present. Zone A represents oil saturated sand at both 191997 conditions. Zone B is oil-filled sand in 1988 and water swept sand in 1997. Zone Cwater-filled sand at both 1989 and 1997 conditions. a) Vp as a function of depth. Vp wascalculated using the rock properties in Table and Equations 3.2 through 3.5. b) Acousticimpedance as a function of depth. c) RFC as a function of depth for the top of the sandassuming a shale impedance of 6.4x106 kg/s2m.
−0.25 −0.20 −0.15 −0.10 −0.05 0
3400
3500
3600
3700
3800
3900
4000
Dep
th (
m)
RFC
OOWC ’88
OWC ’97
c)
4.0 4.5 5.0 5.5 6.0 6.5
3400
3500
3600
3700
3800
3900
4000
Dep
th (
m)
OOWC ’88
OWC ’97
Impedance (kg/s2m) 1x106
b)
Zone A
Zone B
Zone C
Zone A
Zone B
Zone C
1800 2200 2600 3000
3400
3500
3600
3700
3800
3900
4000
Dep
th (
m)
Vp (m/s)
OOWC ’88
OWC ’97
a)
Zone A
Zone B
Zone C
118
itial
gly.
. We
time,
and
ges
e pre-
neral
lysis
ly
ear the
fluid
sent in
s. Sat-
of
d in
effec-
. By
in V
Best (2002) demonstrated that oil composition varies as a function of depth at in
conditions for the J2 and we model the initial acoustic properties of the fluids accordin
Oil properties also change through time as a result of decreasing reservoir pressure
assume that the oil composition as a function of depth do not change as a function of
but vary properties as a function of reservoir pressure using the correlations of Batzle
Wang (1992).
The model we present in Figure 3.25 is a general summary of the acoustic chan
throughout the field and does not exactly reflect the detailed rock physics analysis w
sented for the 109-1 (Figure 3.20) and for the A33 (Figure 3.23). For example, the ge
model in Figure 3.25 does not take into account the formation of a gas cap like the ana
for the A33 in Figure 3.23. We assume for the general model that gas exsolution on
occured in localized areas, such as the A33, because of an increased pressure drop n
wellbore.
Acoustic properties in the J2 sand vary as a function of depth due to changes in
type, saturation, reservoir pressure, and effective stress. Three distinct zones are pre
Figure 3.25. Zone A represents oil-saturated sand at both 1989 and 1997 condition
uration remains constant in Zone A, although the oil properties do vary as a function
reservoir pressure (Batzle and Wang, 1992). Zone B represents initially oil-filled san
1989 and water-swept sand in 1997. Zone C represents the water leg.
Acoustic properties change in Zone A due to changes in reservoir pressure and
tive stress. In 1989, Vp ranges from 1970 to 1990 m/s (Figure 3.25a). Vp varies as a
function of depth in Zone A because oil density and GOR as also functions of depth
1997, Vp increased by 10% due to changes in reservoir pressure. The 10% increasep
119
ase in
erties
n
e
FC at
ming
effec-
d-
resulted in a 12% increase in the acoustic impedance (Figure 3.25b) and 25% decre
the RFC (Figure 3.25c).
Zone B is the water-swept zone and exhibits the greatest changes in acoustic prop
from 1989 to 1997 (Figure 3.25). In 1989, Zone B is initially oil-filled and Vp ranges from
1990 to 2070 m/s (Figure 3.25a). By 1997, Zone B experienced water-sweep and a
increase in effective stress. Vp increased by 20% in between 1989 and 1997 (Figure
3.25a). The 20% increase in Vp also increased the acoustic impedance by 28% (Figur
3.25b) and decreased the RFC by 60% (Figure 3.25c). The 60% decrease in the R
the top of the sand between 1989 and 1997 produced the wide areas of seismic dim
seen in Figure 3.13.
Zone C experiences no saturation or fluid property changes, although changes in
tive stress still effect the acoustic properties (Figure3.25). Vp ranges from 2613 and 2716
m/s in 1989. As the effective stress increases, Vp increases by 5% and the acoustic impe
ance increases by 8%.
120
as
duc-
n the
ntal
97.
and
e of
dicted
rame
ch as
d in a
iew).
1997
fluid
that
-lapse
sfully
Conclusions
We show that the OOWC in the J2 migrated upstructure from 3784 m to as high
3500 m TVDSS between 1989 and 1997. This movement of the OWC was due to pro
tion of oil from the J1 and J2 reservoirs and the encroachment of water from below i
aquifer. PNC log and production data also show that the OWC did not remain horizo
through 1997 and that small areas of undrained pay remained below the OWC in 19
The drainage model we formulate predicted that 90 MMrb were produced from the J1
J2 RB reservoir between 1989 and 1997. This value is within 8% of the actual volum
produced fluids (97.8 MMrb).
Gassmann fluid substitution of water sweep and gas exsolution successfully pre
the time-lapse changes observed by Swanston et al. (in review). We show that both f
stiffening, compaction, and water sweep increase the acoustic impedance by as mu
27% between 1989 and 1997. This 27% increase in the acoustic impedance resulte
70% decrease in the seismic amplitude which was observed by Swanston et al. (in rev
Production data suggested that free gas began exsolving in the area of the A33 before
and time-lapse data show no significant changes in amplitude. We used Gassmann
substitution to show that the frame stiffening effects cancelled out the gas effect and
between 1989 and 1997, the acoustic impedance only decreased slightly in the A33
region. The small changes in acoustic impedance resulted in a non-detectable time
signature, which was observed by Swanston et al. (in review) in the A33 and succes
modeled using the Gassmann Equations.
121
Nomenclature
Symbol Description Dimensions
A empirical constant v/v
B empirical constant v/v
C empirical constant v/v
BVO bulk volume oil v/v
DPHI density porosity v/v
GR gamma ray log API
ILD deep resistivity log ohm-L
Ko solid grain modulus M/T2L
Kw water modulus M/T2L
Koil oil modulus M/T2L
Kg gas modulus M/T2L
Kdry dry rock modulus M/T2L
Kfl composite fluid modulus M/T2L
M p-wave modulus M/T2L
NPHI neutron porosity log v/v
RHOB bulk density log M/L3
RF recovery factor v/v
S constant v/v
Sor residual oil saturation v/v
Sv overburden stress M/T2L
Sw water saturation v/v
Swirr irreducible water saturation v/v
TVDSS subsurface total vertical depth L
Vb bulk volume L3
Vdrained model-predicted drained volume of oil L3
Vp P-wave velocity L/T
Vproduced produced volume of oil L3
Voil volume of oil L3
Vs S-wave velocity L/T
φ porosity v/v
ρb bulk density M/L3
ρf fluid density M/L3
ρg grain density M/L3
σv vertical effective stress M/T2L
122
ac-ft = acre-feetMMrb = millions of reservoir barrels under subsurface conditionsMMstb = millions of stock tank barrels under standard conditions1 ac-ft = 7758 barrels
Table 3.1: Reservoir Volumes for the J1 and J2 RB reservoirs at initial (1989) andpost-production (1997) conditions.
Units J2 J1 Total Description
1989 Vb ac-ft 65133 22132 87265 Bulk volume of reservoir above 1989OOWC
1989 Voil MMrb 134.7 45.1 179.8 Volume of oil above 1989 OOWC
1997 Vb ac-ft 14205 12941 27146 Bulk volume of reservoir above 1997OWC
1997 Voil MMrb 25.1 26.2 51.3 Volume of oil above 1997 OWC
1989 Vb - 1997 Vb ac-ft 50928 9190 60118 Volume of drained reservoir
Vdrained (model) MMrb 77.1 13.2 90.3 Predicted drained volume of oil
Vproduced MMstb 68.8 Actual produced volume of oil at sur-face conditions between 1989 and 1997
Vproduced MMrb 97.8 Actual produced volume of oil at reser-voir conditions between 1989 and 1997
RF stb/ac-ft 1066 1011 1058 Recovery factor
123
Table 3.2: Production data summary for the J1 and J2 RB
WellName Sand
Perf TopTVDSS
(ft.)
Perf BotTVDSS
(ft.)Date of
PerfProduction
Period
BeginWaterDate
Date of50% Water
A1 J1 11562.2 11593.7 8/14/89 9/89 - 9/96 1/95 6/95
A2BP J2 11886.6 11924.6 7/29/89 8/89 - 4/94 12/94 3/94
A3BP J2 11463.4 11511.4 1/8/90 1/90 - 6/98 9/96 -
A4BP J2 12300.7 12337.0 7/11/89 7/89 - 4/00 1/91 7/92
A5BP J2 12099.2 12160.0 12/26/89 1/90 - 5/93 4/92 11/92
A11BP J1 11383.8 11464.9 1/15/91 1/91 - 11/98 3/96 11/96
J2 11488.7 11498.3 1/15/91
A31 J1 11494.1 11538.8 8/25/93 8/93 - 6/98 7/94 2/96
J2 11561.5 11604.9 8/25/93
A32BP J2 11973.7 12070.9 2/13/91 8/91 - 6/94 12/93 3/94
A33 J2 11082.3 11130.6 11/12/91 12/91 - 6/96 - -
A34 J2 11770.9 11822.1 2/24/91 8/91 - 2/95 4/94 8/94
J2 11840.8 11847.9 2/24/91
A35 J1 11309.9 11316.8 6/28/94 7/94 - 4/00 7/96 -
J1 11324.4 11351.7 6/28/94
J2 11404.8 11434.4 6/28/94
A37 J1 11455.2 11535.8 9/10/93 9/93 - 10/97 7/95 2/96
J2 11535.8 11610.6 9/10/93
A38 J1 12122.9 12143.6 5/27/94 5/94 - 5/94 -
J2 12171.2 12222.9 2/1/91 8/91 - 3/94 12/92 6/93
A38ST J1 12180.8 12189.5 1/12/95 1/95 - 4/00 - -
A41 J2 11461.5 11465.5 5/15/99 5/99 - 4/00 6/99 -
124
Table 3.3: Summary of sonic and porosity log data taken from the water leg of theJ1, J2 and J3 sands
Well Sand DPHI DT Vp σv RHOB Kdry
(µs/ft) (m/s) (MPa) (kg/m3) (GPa)
A5 BP J3 0.319 115.30 2643 15.0 2174 3.265
A4 BP J3 0.336 117.01 2604 15.6 2149 3.093
65-1 ST1 J3 0.310 113.32 2689 16.0 2188 3.537
A36 J3 0.301 112.00 2721 16.6 2201 3.710
A36 J2 0.290 114.23 2668 15.6 2217 3.249
109-1 J3 0.322 120.00 2539 14.7 2170 2.580
A2 BP J3 0.324 117.20 2600 14.4 2167 3.000
A32 BP J3 0.316 117.80 2587 14.7 2179 2.861
65-1 ST1 J2 0.310 117.91 2584 15.1 2188 2.805
65-1 ST1 J1 0.290 113.97 2674 14.9 2217 3.292
Table 3.4: Fluid properties used for investigating the influence on hydrocarbonsaturation on the acoustic properties of the 109-1 J2 sand.
φ = 0.31Kdry = 2570 MPa
Reservoir PorePressure GOR ρhyd Khyd Gas Gravity
(MPa) SCF/STB (kg/m3) (MPa)
Case #1 (Oil, 1989) 58.6 750 730 1300 0.625
Case #2 (Oil, 1997) 43.6 750 720 1050 0.625
Case #3 (Gas, 1989) 58.6 - 285 180 0.625
125
Table 3.5: Elastic properties of the 109-1 J2 used in Gassmann modeling
ParameterValue in1989
Value in1997
(MPa) (MPa)
σv (MPa) 13 28
Ko (MPa) 38000 38000
Κoil (MPa) 1300 1050
Kdry (MPa) 2570 3662
Kw (MPa) 3800 3800
ρoil (g/cc) 730 720
Sw 0.10 0.75
Table 3.6: Acoustic properties of the A33 used in Gassmann modeling
ParameterValue in1989
Value in1997
(MPa) (MPa)
σv (MPa) 10 25
Pp (MPa) 57 42
Pb (MPa) 47 47
Ko (MPa) 38000 38000
GOR 1240 1000
Κoil (MPa) 873 700
Kdry (MPa) 2775 4187
Kw (MPa) 3800 3800
ρoil (g/cc) 676 648
Sg 0 0.20,0.40
Sw 0.20 0.20
So 0.80 0.60,0.40
Kgas - 120
ρgas - 240
126
nic
oni-ld:
lus,id-
ser-65,
is,
ringre
re,
ng
of
nts:
References
Alberty, M., 1996, The influence of the borehole environment upon compressional sologs:The Log Analyst, vol. 37 no. 4, pp. 30 - 45.
Batzle, M. and Wang, Z., 1992, Seismic properties of pore fluids:Geophysics, vol. 57 no.11, pp1396 - 1408.
Behrens, R., Condon, P., Haworth, W., Bergeron, M., Wang, Z., 2001, 4D seismic mtoring of water influx at Bay Marchand: the practical use of 4D in an imperfect worSPE 71329.
Benson, A.K., and Wu, J., 1999, A modeling solution for predicting a) dry rock modurigidity modulus and b) seismic velocities and reflection coefficients in porous, flufilled rocks with applications to rock samples and well logs:Journal of Applied Geo-physics, vol. 41, pp. 49 - 73.
Berryman, J.G., Origin of Gassmann’s equations: Geophysics, vol. 64 no. 5, pp. 1627 -1629.
Best, K.D., 2002, Development of an integrated model for compaction/water drive revoirs and its application to the J1 and J2 Sand at Bullwinkle, Green Canyon BlockGulf of Mexico: Masters thesis, The Pennsylvania State University.
Blangy, J.P., 1992, Integrated seismic lithologic interpretation: the petrophysical basStanford University Phd thesis, 414 pp.
Burkhart, T., Hoover, A.R., and Flemings, P.B., 1998, Time-lapse (4D) seismic monitoof primary production of turbidite reservoirs at South Timbalier Block 295, offshoLouisiana, Gulf of Mexico:Geophysics, vol. 65 no. 2, pp. 351 - 367.
Burkhart, T, 1997, Time lapse monitoring of the South Timbalier block 295 field, offshoLouisiana: Masters these, The Pennsylvania State University.
Christensen, N.I., and Wang, H.F., 1985, The influence of pore pressure and confinipressure on dynamic elastic properties of Berea sandstone: Geophysics, vol. 50 no. 2,pp. 207-213.
Clark, V.A., 1992, The effect of oil under in-situ conditions on the seismic propertiesrocks:Geophysics, vol.57 no. 7, pp. 894 - 901.
Domenico N., 1977, Elastic properties of unconsolidated porous sand reservoirs:Geo-physics, vol. 42 no. 7, pp. 1339 - 1368.
Dvorkin, J., Prasad, M., Sakai, A., and Lavoie, D., 1998, Elasticity of marine sedimeJournal of Geophysical Research, vol. 26, pp. 1781 - 1784.
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Flemings, P.B., Comisky, J., Liu, X., and Lupa, J.A., 2001, Stress-controlled porosityoverpressured sands at Bullwinkle (GC65), Deepwater GoM.Offshore TechnologyConference, April 30- May 3, 2001.
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129
y are
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e
Appendix A - PNC Log Methodology
PNC logs are useful tools for investigating water saturation changes because the
most sensitive to the presence of NaCl in formation water. The PNC log measurem
used to determine Sw is based on the ability of the formation to capture thermal neutro
emitted by the tool sonde (Smolen, 1996) and is called the cross-section (Σ). When high-
energy thermal neutrons are introduced into the formation, they interact with the nucl
different formation materials. These nuclear interactions or captures result in the cre
of a gamma-ray which is measured by a counter in the tool (Bateman, 1984; Smolen
1996). The rate at which thermal neutrons are captured by the formation is proportion
its cross-section or sigma. A formation with a given porosity will capture more therm
neutrons when it is 100% water saturated, so the sigma value recorded by the tool is h
than in an oil-filled formation with the same porosity.
I use a volume-average approach for calculating Sw from PNC logs. The simple for-
mation model includes sigma responses from the solid grains, and the effective poro
filled with water and hydrocarbon,
. (A.1)
Using the porosity from the bulk density log, Sw was calculated by rearranging the abov
equation to:
(A.2)
Σ 1 φ–( )Σm φ 1 Sw–( )Σh φSwΣw+ +=
Sw
Σ Σm–( ) φ Σh Σm–( )–
φ Σw Σh–( )------------------------------------------------------=
130
ion
ull-
-
d is
.
l
d by
989)
n the
ave
hat no
open-
n top
een
The sigma value for water was taken from published charts. An average salinity of
225,000 ppm at 165 F corresponds to a value of 110 C.U. for water. The cross-sect
value for liquid hydrocarbon is less variable and is a function of mainly GOR. The B
winkle oils have GORs ranging from 800 to 1200 SCF/STB at initial conditions, corre
sponding to a cross-section value of 20 C.U. The cross-section value for quartz san
less well constrained and is reported as 8 to 14 C.U. in the literature (Clavier, 1971)
Calibration of the matrix cross-section is back-calculated from Equation A.2 in a wel
where the water saturation is known from openhole log analysis and has not change
the time a PNC log run is conducted. This methodology is used by Schlumberger (1
and is discussed in detail by Clavier et al. (1971) and Hearst et al. (1985).
We tested our methodology of calculating Sw by examining a well where PNC logs
were run before the well started producing in the J1 and J2 intervals. This was done i
A-37, which was cased-hole logged in 9/93 and began producing from the J1 and J2
shortly after (Figure A.1). Saturations calculated from the openhole resistivity log h
an average value of 15% in the cleanest parts of the J1/J2 interval. We assume here t
changes in saturation have occurred in the J1 and J2 in the time interval between the
hole and the PNC log runs. Saturations from the PNC log in 9/93 are shown plotted o
of the Sw from resistivity curve in Figure A.1. There is a very strong agreement betw
the water saturations calculated from both the resistivity and PNC logs in the A-37.
131
ilityNon- is/93ILDolid
Figure A.1 Openhole and PNC log analysis in the A-37. Openhole log analysis of permeabreveal reservoir zones which are represented by the black lines to the right of the GR log.reservoir zones are in white. The ILD log was run in 3/90. Water saturation from the ILDshown as the black-hashed lines in the right-most track. The PNC log run took place in 9and the log-measured formation cross-section (Sigma) is shown directly to the right of thelog. Water saturation from the Sigma log are shown in the rightmost track as a thick gray sline
J1
J2
Sw from ILD
Sw from SIGMASigmaCU
132
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ring:
eu-
eu-apse
References
Smolen, J.J., 1996, Cased Hole and Production Log Evaluation: Penn Well PublishinCompany, 365 p.
Bateman, R.M., 1985, Cased-Hole Log Analysis and Reservoir Performance MonitoInternational Human Resources Development Corporation, 319 p.
Clavier, C, Hoyle, W., and Meunier, D., 1971, Quantitative interpretation of thermal ntron decay logs, Part I: Fundamentals and techniques,Journal of Petroleum Technol-ogy, vol. 23, June, pp. 743-755.
Clavier, C, Hoyle, W., and Meunier, D., 1971, Quantitative interpretation of thermal ntron decay logs, Part II: Interpretation example, interpretation accuracy, and time-ltechnique, Journal of Petroleum Technology, vol. 23, June, pp. 743-755.
133
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Appendix B - Gassmann Output
Table B.1: Parameters used for 1989 Conditions
Depth Depth Pp Sv σv GOR ρoil Koil Sw Vp Imp RFC
ft m MPa MPa MPa SCF/STB kg/m3 MPa m/s kg/m2s
11155 3400 56.7 67.1 10.3 1211 679 889 0.15 1974 4.03 -0.21
11200 3414 56.9 67.4 10.5 1187 681 900 0.15 1977 4.04 -0.21
11300 3444 57.1 68.0 10.9 1132 687 927 0.15 1985 4.06 -0.20
11400 3475 57.4 68.6 11.3 1077 693 954 0.15 1993 4.08 -0.20
11500 3505 57.6 69.3 11.6 1023 698 984 0.15 2002 4.10 -0.20
11600 3536 57.9 69.9 12.0 968 705 1015 0.15 2011 4.12 -0.20
11700 3566 58.1 70.5 12.4 913 711 1048 0.15 2020 4.14 -0.19
11800 3596 58.4 71.1 12.8 859 718 1082 0.15 2030 4.17 -0.19
11900 3627 58.7 71.8 13.1 804 724 1120 0.15 2041 4.19 -0.19
12000 3657 58.9 72.4 13.5 749 732 1159 0.15 2052 4.22 -0.19
12100 3688 59.2 73.0 13.9 695 739 1201 0.15 2067 4.26 -0.18
12200 3718 59.4 73.7 14.3 640 747 1246 0.15 2112 4.35 -0.17
12300 3749 59.7 74.3 14.6 585 755 1294 0.15 2156 4.45 -0.16
12400 3779 59.9 74.9 15.0 531 763 1346 0.15 2200 4.54 -0.15
12415 3784 60.0 75.0 15.1 523 765 1354 0.15 2207 4.56 -0.15
12450 3795 60.1 75.2 15.2 1.00 2620 5.69 -0.043
12500 3810 60.2 75.6 15.3 1.00 2629 5.71 -0.041
12550 3825 60.4 75.9 15.5 1.00 2638 5.73 -0.039
12600 3840 60.5 76.2 15.7 1.00 2647 5.75 -0.037
12650 3856 60.7 76.5 15.8 1.00 2656 5.77 -0.036
12700 3871 60.9 76.8 16.0 1.00 2665 5.79 -0.034
12750 3886 61.0 77.1 16.1 1.00 2673 5.81 -0.032
12800 3901 61.2 77.5 16.3 1.00 2682 5.83 -0.031
12850 3916 61.3 77.8 16.4 1.00 2691 5.85 -0.029
12900 3932 61.5 78.1 16.6 1.00 2700 5.87 -0.028
12950 3947 61.7 78.4 16.7 1.00 2708 5.89 -0.026
13000 3962 61.8 78.7 16.9 1.00 2717 5.91 -0.024
134
4
3
1
9
7
5
3
0
8
6
4
2
9
7
6
Table B.2: Parameters used for 1997 Conditions
Depth Depth Pp Sv σv GOR ρoil Koil Sw Vp Imp RFC
ft m MPa MPa MPa SCF/STB kg/m3 MPa m/s kg/m2s
11155 3400 41.7 67.1 25.3 1211 669 705 0.75 2365 5.20 -0.10
11200 3414 41.9 67.4 25.5 1187 671 715 0.75 2369 5.21 -0.10
11300 3444 42.1 68.0 25.9 1132 677 740 0.75 2378 5.23 -0.10
11400 3475 42.4 68.6 26.3 1077 683 766 0.75 2387 5.25 -0.09
11500 3505 42.6 69.3 26.6 1023 689 794 0.75 2396 5.27 -0.09
11600 3536 42.9 69.9 27.0 968 695 823 0.75 2406 5.29 -0.09
11700 3566 43.1 70.5 27.4 913 702 854 0.75 2415 5.32 -0.09
11800 3596 43.4 71.1 27.8 859 709 887 0.75 2425 5.34 -0.09
11900 3627 43.7 71.8 28.1 804 716 923 0.75 2435 5.36 -0.08
12000 3657 43.9 72.4 28.5 749 723 960 0.75 2446 5.39 -0.08
12100 3688 44.2 73.0 28.9 695 731 1000 0.75 2456 5.41 -0.08
12200 3718 44.4 73.7 29.3 640 739 1043 0.75 2467 5.44 -0.08
12300 3749 44.7 74.3 29.6 585 747 1089 0.75 2478 5.46 -0.07
12400 3779 44.9 74.9 30.0 531 755 1139 0.75 2489 5.49 -0.07
12415 3784 45.0 75.0 30.1 523 757 1146 0.75 2491 5.49 -0.07
12450 3795 45.1 75.2 30.2 1.00 2786 6.22 -0.014
12500 3810 45.2 75.6 30.4 1.00 2793 6.24 -0.013
12550 3825 45.3 75.9 30.6 1.00 2799 6.25 -0.012
12600 3840 45.4 76.2 30.7 1.00 2805 6.26 -0.011
12650 3856 45.6 76.5 30.9 1.00 2811 6.28 -0.010
12700 3871 45.7 76.8 31.1 1.00 2818 6.29 -0.009
12750 3886 45.8 77.1 31.3 1.00 2824 6.31 -0.007
12800 3901 46.0 77.5 31.5 1.00 2830 6.32 -0.006
12850 3916 46.1 77.8 31.7 1.00 2837 6.33 -0.005
12900 3932 46.2 78.1 31.9 1.00 2843 6.35 -0.004
12950 3947 46.3 78.4 32.1 1.00 2849 6.36 -0.003
13000 3962 46.5 78.7 32.2 1.00 2856 6.38 -0.002
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