Upload
christian-narvaez-barajas
View
245
Download
0
Embed Size (px)
Citation preview
8/10/2019 Articulos Yac de Gas
1/27
Integrated Study for Water Management in a Highly Heterogeneous
Water-Flooded Reservoir Western Desert Egypt
Ahmed Aly and W John Lee,
S.A. Holditch Associates, Znc.
rnanagement in a highly heterogeneous, multilayered,
ihase reservoir becomes complicated when poor
--i:rrization of the reservoir by conventional methods
.T:S
fine-scale resolution of the model.
o b l e mecomes evident when the oil production rate
-C
Xayat-Yasser,LowerBaharyiaresefvoir in the western
c
f
Egypt dropped 30 , and water cut increasedfrom
'7 .
Conventional14-layermodelingcouldnot explain
-qd changes in reservoir behavior.
: z ~ t i o nof well-log analysis, geology, and two-
--onal seismic through geostatistic modeling techniques
A?
a 30-layered reservoir model that was used to calibrate
2
,-dimensional, three-phase numerical stimulation
X
greater resolution in the model, we were able to
L
r.
match the reservoir performance on three levels; field
L individual well level, and zona1 level (production
r z g data).
y u l t of this study, we were able to identify promising
far redevelopment, plan strategies for optimizing
>ir management, and visualize approaches for
m= uture management and development of similar
-Y~'ods in the area.
:3per presents details of this study and our
L n n d a t i o n s for future field development.
Khalda Petroleum Co. (Khalda) discovered the Hayat field
in 1986, when the Hayat-1X was dnlled. The Yasser field
was discovered in 1987 when Yasser-1 was drilled. The Hayat
Yasser field is located in the southeastern portion of the
Khalda West Concession, south of the Salam field, in the
Western Desert of Egypt. Oil production in this field peaked
in August 1995, at an average of 10,000 STBID, f r ~ mhe
Lower Bahariya formation, and then started to declie rapidly.
The reservoir fluid in the Lower Bahariya reservoir is a
volatile oil that may grade into black oil in the deeper poftion
of the reservoir. Khalda has requested that the reservoir
simulation model use a black oil configuration. This is an
adequate representation of the reservoir fluid if the pressure
throughout the simulation model remains above the
bubblepoint. As the reservoir pressure in the field drops below
the bubblepoint, large amounts of gas will come out of
solution and will ovemde the oil production. This may result
in a loss of oil production and production of a large amount
of gas. In addition, our reservoir simulation model will not
be adequate to handle this situation. As a result, one of our
main objectives in developing this field is to maintain the
reservoir pressure above the bubblepoint. In addition, we
need to develop the optimal scenario to recover the maximum
amount of oil.
In the rest of the paper we will present the results of the Hayat
Yasser, Lower Bahariya study &d present our conclusions
and recommendations based on these results.
In this section, we describe the reservoir model used to
simulate the history of the Lower Bahariya reservoir in the
Hayat Yasser field.
8/10/2019 Articulos Yac de Gas
2/27
Memorias
/
Proceedings
On a basis of our experience with grid design and optirnization
and after considering various smaller grid-block sizes, we
built the final fine-grid model using comer-point geometry
grids to honor the faults in the field. We also applied local
grid refinement (LGR) around the severa1 wells. Fig 1
presents the grid we used over the geostatistical model. We
applied LGR to help with our history match. .Based on the
geostatistical study, we preserved the vertical layering profile
of 30 simulation layers. The resulting model dimensions were
39 x 23 x 30. This resulted in a reservoir simulation model
with 26,910 main grid cells coupled with 32 locally refined
grid cells.
The PVT data, the relative permeability and the capillary
pressure data for the reservoir simulation mbdel were
developed and discussedby McCain.
In this section we present the results of our history match of
the Lower Bahariya reservoir. The reservoir performance
history match helped us in determining the original oil in
place for the Hayat Yasser field with great accuracy.
For the field history match, we attempted to honor the
observed oil and watej production rates and water injection
rates. In general, we matched the production performance
as a function of time at the field level to a tighter tolerance
than at the well level. A tighter tolerance at the field level is
reasonable because field data generally have less error than
individual well data. Well data usually have more uncertainty
because of production testing measurement errors and
inaccuracies associated with allocating field data to individual
wells and further to individual reservoirs.
Initial history matching adjustments focused on overall
reservoir performance including oil, gas, and water
production and pressure. Subsequent adjustments were made
to improve individual well matches.
Table
presents our history matching adjustment pararneters
and the history matching criteria.
Fig 2
shows the field oil, water, and gas production rates.
We can see from Fig 2 that the reservoir simulation model
honored the observed field oil and water rates. There is much
uncertainty in the recorded gas rate data, and the model
matched the field performance adequately, given the
uncertainty in these data.
Fig 3
shows the gasloil ratio (GOR). The match is good and
confirms our bubblepoint match.
Fig 4
shows the water-cut plot match, which is also gooc
We can see that we matched the arrival time of the watt-
well.
Fig
5
shows the history match of the cumulative oil, water
and gas production for the Hayat Yasser field.
Fig 6
shows the history match of the field water injectic-
rate and cumulative water injection. The match is good.
Fig
7
shows the pressure history match for the Hayat Yassc-
field. Al1 the observed and simulated pressure data ar
adjusted to the datum level (-5475 subsea true vertical depti-.
Fig
6 shows the pressure match for the A-sand (whic-
incorporates most of the hydrocarbon-bearing formation. Tr::
pressure matches for the C sand (which is mostly below tk
oil/water contact and represents the bottom part of the C
sar..
geological layers) are also presented in
Fig 7. Fig
7 shoii
a good pressure history match and adds confidence to
ti :
volumetric estimate of the OOIP from this reser\-c
simulation model.
WellPerforinance istory Match
In this sectionwe discuss the individualwellhistory match?.
This added a second level of history matching on individu-
wells to the field-wide history match. This ensured g k .
history matches in different parts of the field @eally). 1
addition, this will assist with accurate forecasting, resen
development, and management of the Hayat Yasser, Lou:
Bahariya reservoir.
Figs 8
to
1
show some representative individual well histc:
matches for this field.
The good individual well history matches provided the ba-
for forecasting using the reservoir model.
uroduction Logging istc
The production logging (PLT) historymatch provides a
th-.
level of history match. Matching the PLT flow rate u.:
depth ensures a history match at the zonal level afterachiel
an acceptablehistory match at the total field level and at rr
individual well level areally. This third-leve1 history ma.
adds more verification and validity to the geostatistic
integrated model for the Lower Bahariya reservoir.
Accuracy of rates from production logs depends on
flui:
produced:
m For single-phase flow (especially water injection), intc
preted results are quantitative and potentially accurats
m
For two-phase, waterloil flow, results are less accurart
m For flow with a gas phase, results are only qualitativf
8/10/2019 Articulos Yac de Gas
3/27
ms
inproduction log interpretation are as follows:
= m - p h a s e njection wells,
f
0
w phax
liquid flow (oillwater),f 0
-mxphase flow (oil/water/gas),
f
0
~ g p i m e
low in deviated wells, very large errors
I.s
U
3
present some representativeproduction logging
LT
m h e s . These figures show that the model did a
-
_ xi
job of matching the zona1 production.
For the Lower Bahariya reservoir, we determined the movable
hydrocarbon for the A-sand (simulation layers 1 to lo), where
most of the hydrocarbon lies. In addition, we summed the
MHPV distribution of each layer into a summed MHPV for
the entire reservoir. Fig
14
presents the distribution of the
sumrned MHPV for the Lower Bahariya A-sand (layers 1 to
10) initially (1989) before any production from the Hayat
Yasser field.
Fig 15
presents the summed MHPV at the end
of the history match (-1997). As shown in
Fig
15
severa1
areas in the Hayat Yasser field have much more highly
movable oil (marked in red and yellow) than the rest of the
reservo.: We focused on those areas for our redevelopment
and infill drilling locations in the forecast runs.
sr y matching the historical reservoir performance,
u
t ~
ovable hydrocarbon technique2 to optirnize
~mu @ormance of this reservoir. The biggest challenge
r phase of the project was the complexity and
L N
of the reservoirsystem. Wellswere selectively
sony a few layers at a time, rather than in al1
3 x cmce.
Thus, the developmentof each reservoir layer
We needed a simple and systematic approach
1s
e anking the areas of the reservoir that were most
mmmsq or future development and infill drilling.
w
history match of this reservoir resulted in a layer-
.. m= distributionof current water saturation. However,
jlrmation alone is not sufficient to identify the most
mamaqareas
for redevelopment. Abetter indicatorwould
a m s related to potentially recoverable oil volume,
Aes into account porosity, net pay, and fluid
mmmm We selected the movable hydrocarbon technique
n
calculated it foreach grid block in the simulation
apier mg the following equation.
Forecasts
In this section we present the different forecast cases. We
designed our cases to forecastuntil the year 2008 and to shut
in and abandon the field when the field's total oil production
drops below 1,000 STBD.
We illustrate our optimal recovery case, which results in a
recovery factorof43 at theyear 2006. The optimalrecovery
case shows an additional recovery factor of more than 10
over the base (as-is) case. The optimal recovery case will
require drilling 11 new producers and 3 new injectors and
recompleting 6 shut-in wells as injectors.
Fig 16 shows field oil production forecast comparisons for
the base case, the recompletions case, and the optimal
recovery case. This showsthat we can increaseoil production
by around 160 . The field oil rate will go from around4,000
STBD to around 6,700 STBD if we develop the Lower
Bahariya using the optimal recovery scenario.
7758xhx@x S0 S,,)
ST acre =
Fig 17
is the field cumulative oil production forecast
O
(')
comparison for the three cases.
Fig 18
is a comparison of the forecasted gas production for
kas the follOwingadvantages for hel~ing ngineers
the three forecast scenarios. This indicates that even for the
6 ~ o f
reservoirforredevelo~mentandinfilldriuing
optimal recovery case, the gas production does not increase
above the levels we had in 1995, which means the pressure
m s a volumetriccalculation,which providesa direct
in this aggressive case did not drop below the bubblepoint.
bare of the amount of potentially recoverable oil in
The pressure-forecastplot illustrates this.
m
m of the reservoir.
Fig 19
is a comparison of the forecasted A-sand pressures
forthe forecast cases. This figure shows that the piesure in
d d r e p r e s e n t s movable oil, MHPV takes into account
the optimal
recovery
c se does not drhp below the
11that can be affectedby changes in wat~rflood
bubblepoint as we have aggressively manzged the reservoir
d n s .
and replaced the withdrawl volums with injected water.
m s equal to or less than zero for any areas of the
=oir that has oil saturationbelow Sdr, such as near
r an oil/water contact. The calculation of MHPV
The base case represents the as-is scenario. The base case
=
sclude a filter to automaticallyeliminate values of showeda recovery factor of around 33 at the end of the run
~ ~ i i ~ -ear or below zero.
(2004). We assumed that we would produce this field under
8/10/2019 Articulos Yac de Gas
4/27
Memorias
/
Proceedings
the current operating conditions. In this case we have 9
producing wells and 10 injection wells.
The summed movable hydrocarbon pore volume map for the
A-sand at the end of the base case (2004) is presented in
Fig
20. We still see some red spots in the field, which means that
if we apply the base-case development scenario, we will leave
some unrecoverable reserves in the Lower Bahariya reservoirs
at the year 2004 when we abandon the field. Thus, we
conclude that this development scenario may not be the
optimal scenario for the development of the Lower Bahariya
reservoir in the Hayat Yasser field.
In this case we recompleted some of the watered-out
producers as injectors. The recompletion-forecast case
showed a recovery factor of around 32 at the end of the run
(2003). In this case we used the same number of injectors
and producers as the base case, and we recompleted some
watered-out wells as injectors.
We optirnized the recompletion case by doing severa1 runs
where we injected into the C sand in the wells that are down
structure. This resulted in helping the pressure in the field
without losing production due to early breakthrough and
watering-outof producing wells.
Fig
21
is the sumrned movable hydrocarbon pore volume
map for the
A
sand. We can see that at the end of this
recompletioncase in the year 2003 we have some bypassed
oil and reservesin the ground. Thisencouragedus to develop
the optimalrecoverycase and to go after the remainingoil in
the Lower Bahariya reservoir.
The optimal recovery case was designed as follows:
Recomplete
6
shut-in wells to injectors.
Drill 3 new injection wells.
Drill 11 new production wells.
Recomplete one new producer in the Hayat area
an injector to help maintain the field pressi.
after the well waters out.
Fig
22 shows the summed movable hydrocarbon pc
volume map for the optimal recovery case in the year
2 1
In this optimal run we effectively produce the hi-
accumulation pockets of movable oil.
The optimal recovery case resulted in a recovery factor of
around 43 at the end of the run (2006).
The optimal recovery case was developed after performing
multiple runs to investigate the optimal scenario to develop
the Lower Bahariya reservoirs. It included the input from
the Hayat Yasser team and the Production Enhancement Team
(PET) and the experience of the Holditch team3 in developing
heterogeneous, waterfiooded reservoirs.
We tried most of the possible locations for new wells
suggested by our movable hydrocarbon maps and the
independent work of the Production Enhancement Team. We
had two main objectives when developing this case.
Maintaining pressure above the bubblepoint.
Producing the maximum feasible cumulative oil from the
Lower Bahariya in the Hayat Yasser field.
This case proved to be the optimal case as it exceeded
economic lirnits set by the operatingcompany by a factoi
2.
As a result, we believe that the optimal recovery case will
the best scenario to develop the Lower Bahariya reservoi:
produce the maximum cumulative oil and to maint.
pressure above the bubblepoint. Also, we must take i:
consideration that the Lower Bahariya reservoir is higi-
heterogeneous and that it requires a phased developni.
approach and updating of the model periodically as new
L
become available (e.g., 3D seismic, new well logs, and y
data). We also recommend an aggressive managen?:
program of this field using the reservoir simulation
o
developed in this study.
Horizontal Well ase
In this case we investigated the feasibility of drill
horizontal wells to produce some undrained pocket.
movable oil in the Lower Bahariya reservoir. We found
two well-placed vertical wells will outperform a horizor
well in draining the Lower Bahariya reservoir. Thi.
reasonable because of the heterogeneous nature of the
L o
Bahariy a reservoir.
The development scenario of this case is the same a
y
las nuevas oportunidades que de ello se derivan.
'iicimientos de este campo son arenas compactas de
~ z i l i d a denor a 1mD y es prctica comnfracturarlas
r i c a m e n t e para obtener una produccin comercial de
Y ntegracin de la interpretacin de la ssmica
3D
del
in? n la caracterizacin de los yacimientos , el estudio
permiti proporcionar localizaciones de nuevos pozos
zrc
la marcha del estudio. Estos pozos, una vez
c . d o s , mostraron presiones de poro muy cercanas a la
- :a inicial de los yacimientos,
450
Kg/cm2. La estrategia
110 inicial, basada en la integracin de informacin
=a de ingeniera del campo, asegur el xito de la
etapa del desarrollo del Arcabuz-Culebra. A partir
r el
estudio integral jug un papel muy importante en
rt-arrollo de este campo. La produccin, que
---damente en un
70
proviene de la arena Wilcox
4,
:
k z e n t en mas de 600 ; se ha establecido un plan de
i
a l l o que involucra la perforacin de mas de
300
pozos
Zzw
y
extensin en un trmino de tres aos. En general
S 'r-ac7amiento de los nuevos pozos es de alrededor a
400
TC x las nuevas prcticas de fracturamiento ofrecen
-
de hasta
500
pies de extensin, lo cual favorece la
T~YL-vidadon relacin al espaciamiento.
g g
tapa del estudio integral se ha concentrado en
n modelo numrico de simulacin para las arenas
Wilcox, que ha permitido entender mejor la dinmica de los
compartimentos que definen los yacimientos compactos del
campo. En este sentido, la simulacin ha proporcionado
elementos que confirman que la ssmica
3D
en este campo,
no ha logrado definir algunas barreras o fallas que influyen
en el comportamiento dinmico del flujo. Es decir, se ha
observado que existen fallas o barreras subssmicas asociadas
a compartimentos. Estas observaciones han permitido
posicionar mejor los pozos de relleno en el desarrollo del
campo.
El modelo numrico construido en esta etapa ha sido validado,
ya que reproduce la historia de presin-produccin que el
campo ha experimentado durante su vida productiva. La
representacin espacial de las fracturas hidrulicas asociadas
a los pozos del campo represent un reto en la simulacin,
ya que no fue fcil garantizar soluciones numricas adecuadas
con un refinamiento local de malla arbitrario, adems del
alto costo de la simulacin bajo este concepto. Una vez
calibrado el modelo, se analizaron los siguientes escenarios
d produccin : es-amiento e m e pozos, lGgitud de
f r a c x y uso de compresin. Se realizaron corridas de
ensibilidad, con diferentes espaciamientos entre pozos, a
. .
fin de o~t imizar sta variable. Asimismo, se investia el
efecto de diferentes longitudes de fractura en la producci6p.
Finalmente se analizaron diferentes niveles de contrapresin
en los pozos y su rela cison la produccion. La t i g b 1
muestra la Cecuencia metodolgica aplicada en la etapa de
simulacin. Todos estnc pcrpnnrir\rre analizaron
econmicamente a fin de observar su impacto en los costos
de vroduccin.
La Figura 2 muestra un resumen de estos resultados.
Una tercera etapa del estudio integral, an en desarrollo, es
la simulacin dinmica de sistema integral yacimientos-
tubera-redes superficiales. El anlisis de escenarios de
produccin utilizando esta modalidad integral ofrecer una
mejor calidad en los estudios integrales de yacimientos de
Arcabuz-Culebra.
Los beneficios de un estudio integral utilizando tecnologa
moderna y una organizacin interdisciplinaria muestran en
los resultados del desarrollo del Campo Arcabuz-Culebra un
excelente ejemplo. Un incremento sustancial en la
productividad del campo se ha visto apoyada por una
organizacin basada en prcticas modernas de administracin
de yacimientos.
Las administracin moderna de yacimientos ha propiciado
cambios importantes en la organizacin y esquemas de
trabajo de las empresas petroleras, coadyuvando a maxi-
mizar el valor econmico de sus yacimientos.
8/10/2019 Articulos Yac de Gas
13/27
Memorias / Proceedings
Los estudios integrales de yacimientos requieren de la
sinergia entre ingenieros petroleros, gelogos geofsicos
y petrofsicos, lo que se ha dado de manera natural en la
administracin moderna de yacimientos.
Los estudios integrales son la base de la planeacin del
desarrollo exitoso de un campo.
El campo Arcabuz-Culebra, de la Cuenca de Burgos es
un ejem plo claro de los beneficios de la administracin
moderna de yacimientos y del empleo de nuevas tecno-
logas.
En
los ltimos cuatro aos la produccin d e gas de este
campo se ha visto sextuplicada.
Satter, A. y Thakur, G .: Integrated Petroleum Reservoir
Management: A Team Approach , Tulsa, OK , PennWell
Books, 1994.
Halbouty, M.T.: Synergy is Essential to Maximum Re
covery, JPT, July 1977,750-754.
Craig, Jr.,
F.F.
Willcox, P.J., Ballard, J.R. y Nation,
W.R.: Optimized Recovery Through Continuing Inter-
disciplinary Cooperation, JPT, Julio 1977, 755-760.
Harris, D.G. y Hewitt, C.H.: Synergism in Reservoir
Management- The Geologic Perspective,
JPT, Julio
1977,761-770.
Thakur, G.C.: Reservoir Man agement: A Synergistic
Approach, Artculo SPE No. 20138 presentado en SPE
Permian Basin Oil and Gas Recovery Conferei-
Midland, TX, Marzo 8-9, 1990.
Wiggins, M.L. y Startzman, R.A.: An Approach
to
servoir Management, Artculo SPE No. 20747 pr f-
tado en Reservoir Management Panel Discussion.
65
Conferencia y Exposicin Tcnica de SPE.
.
Orleans, LA, Septiembre 23-26, 1990.
Satter, A, , Varnon, J.E. y Hoang, M.T.: Reservoir
'
nagement: Technical Perspective, Artculo SPE
22350 presentado en el SPE Internacional Meetir.,
Petroleum Engineering, Beijing, China, Marzo
21..
'
1992.
Jourd an, C. A. y Erling, E.T.: Integrating
3D
Seisn: .
Multidisciplinary Reservoir Modeling Projects,
.
Enero 1997,30-32.
Tiab,
D
y Kumar, A. : Applications of the p'D F U E .
to Interference Analysis, JPT
,
Aug. 1980, 1465- - -
Bourdet, D., Whittle, T.M., Douglas, A.A. y Pirar:
M.: A New Set of Type Curves Simplifies Well
Analysis, World Oil, May 1983, 95-104.
Vazquez, R., Mendoza, A, , Lopez, A, , Linares.
Bernal, H.: 3D Seismic role in the Integral Studb
Arcabuz-Culebra Field, Mexico, The Leading Edgs.
1997, Vol. 16, NO. 12, 1763-1766.
Berumen , S., Sanchez, J.M. y Rodriguez, F.: A Str-
for Additional Developm ents in the Burgos Basin -
Arcabuz-Culebra Gas Field , Artculo SPE No.
presentado en International Petroleum Conferencc
Exhibition of M exico, Villahermosa, Tab. Mxico.
\ ' .
3-5, 1997
reas de Drene Elemento de Malla de
Simulacin
Pozo
Fractura
tiempo
entre pozos mts)
igura
1
Metodologta de
o Simulaci np r un
modelo de
se tores
de
yacimiento
04
8/10/2019 Articulos Yac de Gas
14/27
3Wm mn wm V W so m
squemas
de spaclamientw
igura
2
Incrementos econmicos respecto del caso base para diferentes esquemas de
espaciamientos
FERNAN DO RODRIGUEZ D E
LA
GARZA
:sde 1996 es Gerente de Administracin de Yacimientos en la Subdireccin de Tecnologay Desarrollo Profesional
de Pemex Exploracin
y
Produccin.
e incorpora PEP en 1991y fue comisionadoa la UNAM, donde fue profesor y jefe de la Seccin de Ingeniera
trolera en la Divisin de Estudios de Posgrado de la Facultad; actualmentees profesor de asignatura.
ue 1989 a 1991 fue contratado por PETROBRAS y comisionado al Departamento de Ingeniera Petrolera de la
Universidad de Carnpinas en Sao Paulo, Brasil, donde fue profesor e investigador
1982a 1989fue investigadordel InstitutoMexicano del Petrleo,en la Divisin de Ingeniera de Yacimientos.
t u 1 ~ 8 2btuvo el grado de doctor en ingeniera petrolera en la Universidad de Stanford. En 1978 obtuvo el grado
le
maestro en ingeniera petrolera en la DEPFI-UNAM. Se gradu como ingeniero petrolero en el Instituto Politcnico
Nacional en 1973. De 1973 a 1978 trabaj para el
IMP
en la Divisin de Ingeniera de Yacimientos, en el rea de
simulacin numrica.
Su
rea de especialidad es la ingeniera de yacimientos, con nfasis en simulacin numrica de yacimientos
naturalmente fracturados.
a
publicado mas de
5
artculostcnicosenrevistasy memoriasdecongresos,tantointernacionalescomo nacionales.
a sido editor tcnico de SPE, y miembro de diversos comits tcnicos de SPE y de AIPM.
hi distinguido en 1987 con la Medalla Juan Hefferan , otorgada por la AIPM
y
en 1993 con el premio a la
Investigacin en Ingeniera Petrolera, otorgadopor el Instituto Mexicano del Petrleo.
8/10/2019 Articulos Yac de Gas
15/27
Memorias Proceedinas
Integrated Reservoir Study Optimizes Development for a Communicating Gas
Volatile-Oil and Black-Oil Reservoir Complex
Nathan C . Hill Duane A. McVay Pavel A. Zliassov S. .-i
Holditch Associates n .
Brock E. Morris and D. Leigh D ick so~ :
Society of Petroleum Engirzet
An integrated reservoir study was performed to determine
the optimum development plan for two of three adjacent,
communicating reservoirs located in the Americas. The three
reservoirs are within one mile of each other, have three dis-
tinct reservoir fluids, and are in pressure equilibrium. The
lowest reservoir is gas, the next highest reservoir is a volatile
oil, and the highest reservoir is black oil. A compositional
reservoir model that includes al1 three reservoirs was built
using geophysical, petrophysical, and geological and engi-
neering analyses and was calibrated using production and
pressure data. Production data and reservoir modeling indi-
cate that there is movement of hydrocarbons between the
structures. With the calibrated model, we determined that
altemating water and gas injection WAG) in selected wells
offered the optimum future performance for the two oil res-
ervoirs.
The three reservoirs in this study are structural traps sepa-
rated by northw est-trending structural saddles. Th e reser-
voirs are named Reservoir A, B and C, as seen in the sche-
matic cross-section in Fig. 1 Reservoir A is the gas reser-
voir, while Reservoir
B
is the volatile oil and Reservoir
C
is
the black oil. Mosr of the w ells are on the crests of the struc-
tures. At the time of this study, there were 4 wells in Reser-
voir, 11wells in Reservoir B and 10 wells in Reservoir
C
Only
2D
seismic data w ere available over the reservoirs.
The reservoirs are located in an area without a gas market
and regulations do not allow flaring of the gas. Thu s, aIiy
produced gas from Reservoirs
B
and
C
has to be reinjected.
Thre e of the four active wells in the gas reservoir are used a s
observation wells. This study was performed to develop an
understanding of this complex reservoir system and
optimize futu re performance of the oil reservoirs.
Geological and Petrophysical Analyses
Zndicate Depositional Environment
Th e reservoir sandstones are shallow marine, strandpla
barrier, an d fluvial-deltaic deposits. The se sediments u c-
deposited along a retrogradational coastline. Faults bou
some of the basement h ighs and offset the reservoir s ar-
stone. Thu s, the thinness or absence of the sandstone str,
over the structurally high are as is a result of erosional t r L
cation. The se faults also affected depositional patterns
well as fluid migration. Fig.
2
shows the top of structb
ma p of the reservoirs.
We divided the reservoir sandstones into three p ri n ci ~
layers or flow units. Th e two productive intervals are r
UW and the LW layers. The G layer is the lowest layer a-
has no reservoir potential. Mineralogy and di ag en e~
control reservoir character of individual layers, which in t u
reflect the depositional setting of the layers. General
reservoir quality improves upw ard in the reservoir sandsto
as a result of coarser-grained sediments with higher quar
content being deposited in higher energy setting-
Th e G layer was m ost likely deposited below wave base
ir
low-energy marine environment.
Th e LW layer was deposited in a higher energy environm s-
than the G layer. The LW layer is afin e- to med ium -grain~
quartzarenite that is well cemented by quartz overgrou
t
that reduce intergranular porosity and the.size of m any por.
throats. Mu dston e clasts composed of clay minerals wsr.
deformed during compaction and further reduced effecti..
porosity and pore throat size.
8/10/2019 Articulos Yac de Gas
16/27
r r
LW layer was deposited in a high-energy coastal envi-
l:.zlznt. It is a coa rse- to very coa rse-grain ed quar tzare nite
2 Aso is cemented by quartz overgrowths. Only minor
a re p r e sen t i n the UW laye r . Muds tone c l a s t s
~ ~ l r s i t e dn the UW layer were most comm only composed
-~~-bona t eock fragments. During diagenesis, many of the
- - x a t e clasts dissolved, creating secondary porosity that
. __
.-bed
_.
the reservo ir qu ality of this ayer.
cxtrophysical analysis included normalizing the log data
r 5
wells (some of which were from the same formation
r e r nearby fields), performing borehole corrections, and
- .mt ing the log data with the core data. The-calibrated
z s r e then used to determine values of porosity, water
;--=ion and shale content. The average effective porosity
e
LW layer is 13.2 , while the average in the LW layer
L
5 .
The petrophysical analysis of the core data did not
- i z e any flow barriers between the UW and LW layers.
-;
at ' the wells are clustered on top of the structures. To
the maps of net pay and porosity, the sandbody
retry
and reservoir layer trends were extended on the
of seismic amplitude analysis and published des-
- r o n s of the regional depositional setting and paleoslope
~--=on.
production from the field was from Well B10. Well
produced for more than 600 days before the second
r
-rarted production. Initial production from Reservoir
C
=ii
at about 1000 days. At about this time severa1 wells
Y :ompleted and began producing. Fig. shows the oil
a - t i o n rates from Reservoirs B and
C
with time
z n c e d to the start of production f rom Reservoir B .
:
hows that the pressures in al1 the reservoirs began to
c - igif icantly with the increase in production rates.
ZZT
oir
A
was not produced and Wells A7, A14, and A19
ujed as pressure observation wells. Fig. 4 shows that
S Iressures in A7 and A14 dropped as a result of the
- u - t i o n from Reservoirs B and
C,
although at different
- \t about 1400 days, gas injection was started in well
5
eservoir
B.
Fig. 5 shows the gas and water injection
111
Reservoir. B . Within 100 days of the start of gas
cm he measured pressures in Reservoir B start leveling
Fig
4). The production rates in Reservoir B were also
~ u do keep the pressure above the bubble point.
It initially tested o il at original solution GO R and remained
shut-in as a pressure observation well. Severa1 months after
the initial oil test, test data showed very high W OR and low
GO R. A few weeks later, the well was very high GOR while
maintaining high WO R. The test was about 7 0 days after the
start of gas injection and the initial theory was early break-
through. However, early gas breakthrough did not explain
the water production. Well B10 , which was in between the
injector and the test well, produced water free oil at original
gas-oil ratio. Th e conclusion was that gas expan ding in
Reservoir A pushed water from the saddle area up the
northeast flank of the structure toward are a of B 18. T he water
was followed shortly thereafter by gas migrating out of
Reservoir A. Th e reservoir study was
started.soon after this.
About 1700 days after initial production five wells were
drilled and RFT test measurements were taken. The RFT
data show that there is good lateral cornmunication within
the U W layer. The data also show that the LW layer pressure
was 9.5 to 38.7 kglcm2 (135 to 550 psi) higher than the UW
layer, and that this pressure difference is maintained even as
the pressure drops in both layers. The fact that the LW
pressure was declining from the original pressure shows that
there is vertical communication between the layers with
fluids migrating from the LW to the UW since there was
very little production from the LW itself. The pressure
difference between the two layers shows that the vertical
communication is limited. Considering the areal extent of
the reservoirs, the vertical transmissibility must be very small
to maintain this pressure difference. This lirnited vertical
communication between layers has a direct impact on
secondary recovery in the LW layer.
1
r ss su r uildi a t Data Supports
Estimates
and
Layer
Pressure buildup tests were analyzed on eight wells in
Reservoir
C
and seven wells in Reservoir B . The pressure
buildup tests that were m n early show that the UW layer has
a permeability of about 800 to 1000 md on the top of the
structures while the LW layer has permeability of 15 to 30
md: Pressure buildup tests in the U W layer that were run
after a significant pressure drop in reservoir pressure al1 show
indications of layer cross flow between the UW and LW
layers. As an example, the type curve plot in Fig. 6 shows a
bdziction Data Show Communication
buildup pressure test from Well C11. Reservoir simulation
.
history matching with a single well model was required to
z r rst
direct evidence of fluid migration within the
W
analyze the test. The analysis showed that crossflow was
as production test data on well B 18. Well B 18 is on
occurring and that only a minimum permeability could be
;
..rtheast corner of the top of the Reservoir B structure. obtained. These results confirmed the RFT results
8/10/2019 Articulos Yac de Gas
17/27
Memorias Proceedinas
. .
Reservoirs
Fluid samples were analyzed from four wells in the three
reservoirs. The results, summarized in Table 1, show that
Reservoir A has a gas with a dew point, Reservoir
B
has a
volatile oil with a bubble point and that Reservoir C has a
black oil with a bubblepoint. Since it appeared there was
migration of fluid between reservoirs, one set of equation-
of-state EOS)parameters was developedto describeal1three
reservoirs. Since the objective of the study was the optimi-
zationof Reservoirs
B
andC, the three sampleanalysesfrom
these two reservoirs were used for calibration of the EOS
model.
A compositional reservoir model was built and then calibrated
using the pressure and production data. The objectives in
calibrating the model were to match the pressure responses
in the oil reservoirs Reservoirs
B
and C), match the gas and
water production in well
B18
and fit the general pressure
trend of the gas wells in Reservoir A. The approach was to
specify the oil rates and calculate the gas and water rates and
the pressures. The results of the pressure match from the
reservoir model calibration are shown in Fig. 7.
Al1 three reservoirs were initially at equilibrium at a
pressure of 327 kg/cm2
4656
psi) at a subsea datum of
2930.7m -9615 ft), which is below the water contact in al1
three reservoirs. As Reservoir B is produced and the
pressure is reduced, water migrates and the pressure drops in
Reservoir A, allowing the gas to expand. The gas expands
below the spill point and starts migrating into Reservoir B.
The gas-oil ratio match of Well
B
18 in Fig.
8
shows the early
gas-oil ratio increase caused by gas migration. The lines on
the graph are the model results, while the symbols are the
observed data. Although not shown, water migration
between the reservoirs causes a water-oil ratio in Well
B
18.
The pressure data and reservoir modeling also showed that
t h e ~re partial transmissibility barriers that limit communi-
cation within Reservoir A, the gas reservoir. This limited
comm unication between wells in the gas reservoir has a
significant impact on long term production performance in
Reservoir B.
At the time gas injection was started in Reservoir
B
it was
not determined if Reservoir C
was in cornrnunication. As
the pressure in Reservoir
B
leveled off, the data show that
the pressure decline changed in Reservoir
C,
indicating
communication.
ptimal R e .
~ s
. .
Alternatina Gas Znjection
To optimize performance of this reservoir complex, we con-
bined the reservoir model, an economic model and a wellborr
model. The economics were calculated an wellbore modc
The economics were calculed on an incremental basis ar .
were used to judge the various operational scenarios. Soni:
major factors affecting the economics were the costs of ns
wells and the operating costs for the gas and water injectii
facilities. The produced gas is reinjected because there is
r
market for the gas and it cannot be flared due to regulatior.
During the optirnization phase, cases were developed
investigate the sensitivity of different model paramete:
These included parameters affecting surface facilitis
comrnunication between the reservoirs, reservoir layer a:
fluid properties, and individual well production.
The results of our optimization showed that gas inject~~
should remained capped at the current capacity and tk-
water and gas should be injected in Reservoir C. T-
pressure in the UW layer in Reservoir B should
maintained above the original bubble point pressure
maintain gas miscibility until the oil production can:
economically support gas injection. This happens abou-
years after the end of the current history match. T-
pressure should then be allowed to drop but still maintair-
above the Reservoir C bubble point pressure. This d r o ~
ReservoirB pressure allows additional migration of gas fr
Reservoir A and increases cross flow from the LW to
r
UW layer, thus reducing injection requirements.
We determined that water-altemating-gas WAG) inject:
should be used to maintain reservoir pressure and optim
sweep in the UW layer. The alternating over-ride of :
miscible gas and underride of the water provides excel1:-
sweep efficiency. The permeability of the LW layer is
:
low to use WAG. We also determined that WAG injectior
the UW layer does not have a negative effect on recovep
the LW because of the pressure differential toward the
L-.
Secondary recovery in the LW found to be was
1 :
accomplished by injection of gas. The gas is miscible a
the oil, thereby reducing viscosity and improving cross fi
to the UW layer.
We also recommended adding severa1 wells to improvex
sweep, and we determined that horizontal wells in the L
layer provide an economically viable option if the drilli-
risks can be overcome.
8/10/2019 Articulos Yac de Gas
18/27
The optimum recovery method in the
UW
formation
of Reservoirs B and is WAG injection.
The optimum recovery method is the LW in Reser
i~oirs and
C
is gas injection only.
Horizontal wells in
the
LW formation appear to be
sconomic; however, t he nsks associated with
hrizon-tal drilling in this area should
be
quantified
k t .
Reservoirs A, B and C are al1 in communication
through a common aquifer.
Gas is migratingfrom ~eservoir to the oil reservoir
in Reservoir
B
because of the decline in pressur in
Reservoir
B
There is limited vertical communication between
the
UW
and LW layers in Resenoir B and
C
Reservoir C
Bubblepoint 158 kg cm2
OM
2766 m
SS
Table 1- Summary of Reservoir Fluid Properties
Reservoir B
Bubblepoint224 kg cm2
OMI
2864
ReservoirA
Dewpoint308 kg cm2
MI 2931 m ss
Reservoir
A
B
C
- < S - s e c t i o n of Reservoirs A B nd C.
Saturation
Pressure
T Y P ~
Dewpoint
Bubblepoint
Bubblepoint
Saturation
Pressure
kg/cms2
308 4390)
224 3186)
158 2244)
Mole of
C7+
2.58
27.62
39.93
8/10/2019 Articulos Yac de Gas
19/27
Memorius
/
Proceedings
rg. - l op oj imucnrrejor
ReservoirsA
B
nd C
lo
lo
P
-i
E
d flerewair c
-
o
1
O
1o
O 500 1 15 2 2 ?
Time, days
Fig. 3 Oilproduction rates from Reservoirs
B and C.
Fig. 4
Reservoirpressure history in
all
threr
reservoirs
34
~ ~ ~ l l
320
O
J ~ ~ ~
9
\
B
*
v v v
300
- 280
P
260
2
n
24
2
220
200
18
*N
- ResewoirB
O
All Wells
*+
X
-
-
@i
-
-
-
All Wdls
\&
ResewoirC d
B
-
-
-
l i ' i i i i i i i l i i i i l i i i i ~ i i i t
-500
O 500 lo 1500 2000
2500
%
8/10/2019 Articulos Yac de Gas
20/27
d ater injection rates
B
1 E m E
Fig
6 Log plot of plo o presura buildup test
otofivm
We CII
1OOOOO
.
m
2 ~ a n n ~
Fig
7
- abmcion
of motiel
t
reservoupressures
-
-
-
-
-
Water Injection
I I J I I l l l l I I l I I l
r
lo
12 14 16 1800 2000 2200
.
-
-
-
-
-
1
'
8/10/2019 Articulos Yac de Gas
21/27
Memorias Proceedings
Fig.
8
Calibrntion of model to gas oil ratio hislory
Manager of Reservoir Engineering Venezuela Division
S.A Holditch Associates, Inc.
B.S., Petroleum Engineering, Texas A M University
M.S., Petroleum Engineering, Texas A M University
Mr. Hill received a B.S. degree in 1983 and an M.S. degree
in
1984 in Petroleum Engineering from Texas AS
University. He joined S.A. Holditch Associates, Inc. part time in May 1984 and full time in January 1985.
principal area of responsibilityis the design and enhancementof computer models to assist in engineering evaluat
of projects. Recent software projects include well test analysis and production analysis programs. Mr. Hill
participated in engineering projects for litigation and presentation to state regulatory agencies. He has also
bc
involved in reservoir simulation, pressure transient analysis, well logging analysis, and well performance projectit
In 1998 Mr. Hill moved to the Venezuela Division to manage the reservoir-engineeringgroup.
i
8/10/2019 Articulos Yac de Gas
22/27
Memorias / Proceedings
The Use of a Multi-Disciplinary Team Approach for the Reservoir
Characterization of a Mature Field, Alto de Ceuta, Block
VII
Lake Maracaibo, Venezuela
Gomez Ernest; Elphick R.
Y;;
Forrest G .
F;
Gustason E. R
McChesney D. E. Vivas M. A.; Doe M .
GeoQuest Reservoir Technologies Denver i
Gonzalez
J.
A. Rampazzo
M.
Chan B. Mora
J. L.
and Rivas O
PDVSA Caracas Venezuela ar
Ripple R. .4
ARCONICO Jakarta Zndone
The Alto de Ceuta (ADC) Field is located in the southeastern
part of Lake Maracaibo. The field was discovered in 1957
and has produced over 480 M MB O through 1997 from the
Miocen e Lagunillas and Eocene Misoa formations. The
field s structure is characterized by inversion of Eocene
through M iocene sediments along a convergent, left-lateral,
right-stepping zone of re-activated, rift-related, Jurassic
faults. Progressive deformation comb ined with changes in
the dynamics of the eastern Maracaibo microplate have
resulted in relaxation and tensional tectonics ac ross the AD C
high in the post-Miocen e. Th e later tectonic history affected
deposition of the Miocene and
served to compartm entalized
both the M iocene and E ocen e reservoirs.
A multidisciplinary team cons isting of engin eers, geologists,
geophys ic is ts and pe t rophys ic is ts was assembled to
characterize and simulate the field. Th e available data
included 3-D seismic, open hole logs from over
200
wells, 9
cores with routine core analysis, and production and pressure
measurem ents. Because of the complex stratigraphic and
structural nature of the AD C Field, it was especially imp ortant
to integrate data from al1 the disciplines to accurate ly
characterize the field. Pressure measbremen ts and production
history were combined with the seismic interpretation, log
analysis , core description, log correla tions , Statis t ical
Curvature Analysis Technique (SCAT) and mapping to define
During the past several years the
importante
of
u.
i n t e g ra te d mu l t i -d i s c ip l in a ry t e a m s in r e s e r \
charac te r iza t ion and s imula t ion has been recogniz .
In tegra t ion of the va r ious d isc ip l ines a l lo ws fo r
construction of geologic and reservoir models that
n-
accurately represent what is happening in the field. Alth o-
an integrated, multi-disciplinary approach is useful in fic
of any siz e, it is especially vital in m ature reser voirs that
-
comp lex structurally and stratigraphy. The subject of
paper, Alto de Ceuta Field (ADC), falls into this cates
and is located in the southeast com er of Lak e Maraca
Venezuela Figure 1).
A joint team of PDVSA and GeoQuest professionals
formed in late 1996 to study the Alto d e Ceuta Field.
first objective of the study was to construct a geologi,
static model of Alto de Ceuta using the available geologi..
geophysical, petrophysical and engineering data. Once :
reservoir characterization has been completed the g e o l ~
model will be validated through reservoir simulation
p
selected basis. The resulting dynamic reservoir model
then be used to optimize production. A t present tbe geoli.
model of the Alto de Ceuta Field is nearing completion
this paper will focus the methodologies used durins
construction and to a lesser extent on the results.
fault compartments . Engineering data also proved very
f i r s t s t e p i n an o v e r a l l in t e g ra te d r e s e r \
helpful in the stratigraphic correlations. characterization and simulation study is the constructior
the geologic model. The geologic model is static. That
:
reflects the state of the field based on the data available F .
it is built. No as sumption is made of what will happen
\
time and additional operating activities within the field.
8/10/2019 Articulos Yac de Gas
23/27
:.urate geologic model incorporates data from geology,
T- ics, petrophysics and reservoir engineering (Figure
-- 1
onsists of the structure, isopach and property maps
:sjervoir.
. 9 geologic model is built it can be validated using a
-7ic model through numerical simultaion (Figure
3 .
The
-
.i.;tructure. isopach and property maps are input into
.
.:mulator. If the geologic model is indeed-an accurate
--z~ntationf the field, the production and pressure history
zs duplicated or matched he reservoir simulator. In
. this z i f ver happens on the initial attempt. A
Aely scenario is that the model will be reviewed and
e by the integrated technical team that built it (Figures
The Alto de Ceuta structure was a positive feature throughout
Miocene time. The Lower Lagunillas, Laguna and
Bachaquero members of the Lagunillas Formation are thinned
or absent over the feature, the result of non-deposition and/
or erosion. West of the Pueblo Viejo Fault, the Bachaquero
thickens abruptly. While faulting is much less pronounced
in the Miocene than the Eocene, changes in sand unit
thicknesses and facies due to minor fault relief exert a major .
influence on reservoir heterogeneity and quality. The
complex nature of the structure and stratigraphy at Alto de
Ceuta meant that the construction of an accurate geologic
model would require close intergration of the various
technical disciplines.
. :
J Several iterations may be necessary until an
.::~blc history match can be achieved. The resulting
--sd reservoir model is dynamic. That is the model
- sx with time and in response to different operating
The data available at Alto de Ceuta included various vintages
-70s. This dynamic feature allows the model to be used
and types. Cores of the Miocene and Eocene reservoirs were
E
prediction of field behavior using different operating
among the first pieces of data to be reviewed. otal of 9
---os From these various realizations the field operator cores were described for this study. Five of the c o r z e r e of
ct the optimal scenario that is the best solution given
wells within the field and the remaining 4 came from wells
. .
nomic and operating constraints.
immediately adjacent to the Alto de Ceuta Field. The cores
provided valuableinformationon depositionalenvironments
and reservoirproperties includingporosity and permeability.
In addition,special core analysis had been preformed on two
ro de Ceuta Field was discovered in 1957 and has
--
8/10/2019 Articulos Yac de Gas
24/27
this task was to see what data was available, identify missing
logs, looking for inconsistencies and correcting the dig::
data sets and to build the data base that would be used for the
data to the original paper prints. After the digital logs as
remainderof the study. Thedata and specifictasksperformed corrected, environmental corrections were applied and r
duringthis stagewill be reviewed by disciplinein this section logs were normalized. This normalized data set was rk.:
(Figure 3).
used for the stratigraphiccorrelations and log analysis.
Y
sand, net pay,.average porosity and average water saturar:
were among the petrophysical properties calculated r
mapped for the Alto de Ceuta Field (Figure 3).
The geologists were responsible for developing the
stratigraphic framework that will be used through out the
field (Figure 3 . The first step of this process is to examine
the available core within the Alto de Ceuta Field and adjacent
areas. The cores provided information on depositional
environments, rock type and porosity and permeability.
PDVSA was able to provide valuable information on the
field and regional stratigraphy in the form of unpublished
interna1 reports. The core descriptions and previous PDVSA
geologic studies were then incorporated into the final
stratigraphic framework used for the study. The geologist
then took this framework, and aided by seismic, petrophysical
information and the pressure and production data, extended
the correlations to the remainder of the field (Figure 3).
Although the geophysicist had the primary responsibility in
developing the structure model for the field, the geologist
alsoplayed an importantrole The geophysicist and geologist
incorporatedthe regional structureas interpretedby PDVSA
and other workers into the Alto de Ceuta structural
interpretation, modifying it as dictated by the well and
seismic data. Statistical Curvature Analysis Technique
(SCAT) was used with the dipmeters to aid in the structural
interpretation. The Alto de Ceuta Field has had a complex
structural history resulting in multiple fault blocks with
different pressure and hydrodynamic regimes. Fine tuning
of the final smctural frameworkrequired inputof thepressure
and petrophysical (i. e.
oillwater contacts) data.
The seismic data quality at Alto de Ceuta rendered it suitable
only for gross structural interpretation. For this reason only
six horizons were interpreted; Laguna, Eocene Unconformity
(EUNC), Miosa B1, Misoa B6 Misoa C1 and Cretaceous
Colon. These seisrnic horizons were tied to the stratigraphic
framework developed by the geologist from the well control.
Structure maps of the seismic horizons and severa1 other
geologic markers were constructed and used to build the
structural framework of the field (Figure 3).
The petrophysicist s first responsibilty was to build a digital
log data base for the Alto de Ceuta Field that would be used
for log analysis and stratigraphic and seismic correlations
(Figure 3). This started with editing of the existing digital
The project engineers had two tasks during constructior
the geologic model. The first was to build the data base :
would be used in the geologic model. The second objecr:
was to prepare the data for an eventual reservoir simular.
study.
The largest component of of the engineering data base :;
.
the well histories (perforations, sleeve histories
L
completion data). Almost al1 of this data was in hard
c i
T
form and had to first be placed into a digital format. T
pressure and production data was allocated based on
i
stratigraphic correlations developed by the geologist
i
geophysicist. This pressure and production data playei
important role in fine tuning of the stratigraphicand strucrL--
frameworks (Figure 3). Along with static press- -
measurements, pressure transient tests (mostly press-
buildups), were evaluated to assist in identifying flow ba r :
(i. e. sealing faults).
The engineering data gathered and evaluated during built.
of the geologic model will be instrumental n the construcr~
of the reservoir simulation models. Data such as rela:
permeability, fluid properties, rock properties and
L:
histories will be used in the final reservoir simulationm@::
The geologic model as reflected in the individual reser.
models will serve as a basis for further understanding
history match proceeds.
Data integration occurred continuously during the reser.
characterization and building of the geologic model. Ha\ .
the project team work in close proximity to each other res~:- .
in discussion and enhanced the integration process. 1
structure, isopach and property maps that make up the
i
geologic model incorporated al1 the data sets availr-
(Figure 3). In this way it is anticipated that an accur.
geologic model of the Alto de Ceuta Field will be construi::
As stated previously a finalized geologic model is nor
available. However, based on some prelirninary results
;
conclusions can be drawn.
8/10/2019 Articulos Yac de Gas
25/27
r
new geologic model for Alto de Ceuta Field repre-
ents
the complex stmcture and stratigraphy better than
~sv iousttempts.
litial volumetrics of the main Eocene B6 reservoir
zpea r
to match closely with figures from previous
=DVSA tudies. This allows for increased confidence in
::eologic model constructed during the study.
--:zgration of the various technical disciplines helped to
iplain and correct apparent discrepancies in the data.
of Economic Paleontologist and Mineralogist Special
Publication no. 37 p.375-386.
Ghosh S. Pestman P. Melendez L. and Zambrano E.
1996 El Eoceneo en la Cuenca de Maracaibo; facies
sedimentarias y paleogeografia: Vo Congreso Venezolano de
Geofisica 8 p.
Roure
F.
Colletta B. De Toni B. Loureiro
D.
Passalacqua
H.
and Gou Yves 1997 Within-plate deformations in the
Maracaibo and East Zulia Basins westem Venezuela: Marine
and Petroleum Geology vol. 14 no.
2
pp. 139-163.
2 2 K. T. and Christie-Blick N. 1985 Glossary trike-
- ~=formation asin formation and sedimentation in
. : : s . K. T. and Christie-Blick N. eds. Strike-slip
qa tio n Basin Formation and Sedimentation: Society
The authors wish to thank PDVSA and GeoQuest for the
opportunity to present this paper. Doug Crane assisted in
preparation of the illustrations.
lto
e
Ceuta
Field
Fault
Location map Alto de Ceuta
Field
Venezuela.
8/10/2019 Articulos Yac de Gas
26/27
Memorias
Proceedings
Fig. 2 l x s e r v o i r linracterizntioriand simulatiorz workflow.
Previous
ork
Interna1PDVS
Sudies
Methodology and Work Flow
Alto de Ceuta Geologic Model Construction
Fig. Diagram of the methodology and workflow used in the construction of the Alto de Ceuta geologic model.
Geological geophysical petrophysical and reservair engineering data was integrated to produce the final geologic model.
8/10/2019 Articulos Yac de Gas
27/27
C
Q)
Q)
O
O
Fig. 4 Genemzed Miocene nd Eocene strrtlgraphic column Alto de C e m Fieki
m
a
u
Z=
13
a
La
Rosa
Bachaquero
Laguna
Lower
Lagunillas
Marine Shale
Santa Barbara
Q)
Q)
O
O
W
Pauji
d
O
cn
S
Upper B
Lower
B