Interpretation for Quality Prospects"
REJUVENATING A MATURE SUPERGIANT
FIELD, VLC-363, BLOCK III FIELD, LAKE MARACAIBO, VENEZUELA
by MARAVEN PETROLEOS DE VENEZUELA, S.A.
Emir Arzola, Bice Cortiula, Gedi González and Luis Rondón
TCA RESERVOIR ENGINEERING SERVICES, INC.
LOREN AND ASSOCIATES, INC.
John T. Kulha and J. Dennis Loren
SNEIDER EXPLORATION, INC.
John S. Sneider and Robert M. Sneider
EXPLOITECH SERVICES, INC.
John R. Farina
This poster session consists of
seven related poster contributions:
INTRODUCTION (BACKGROUND AND SCOPE)
J. Dennis Loren, Robert M. Sneider,
John S. Sneider, Dan Shaughnessy, Robert M. Sneider*, Gedi González and Bice
J. Dennis Loren*, John T. Kulha and Carolina Coll
John Sneider*, Gedi González and Bice Cortiula
RESERVOIR PERFORMANCE AND OBSERVATIONS
John R. Farina*, John T. Kulha and Emir Arzola
John S. Sneider, Gedi González*, John T. Kulha and Dan Shaughnessy
Michael R. Todd* and Emir Arzola
BACKGROUND AND SCOPE
The Eocene Lower "C" Reservoir is a supergiant field in Lake Maracaibo,
Venezuela. The field is developed by 63 wells.
A multidisciplinary team of geoscientists and engineers undertook an integrated
multidisciplinary study of the Lower "C" Reservoir to provide a detailed reservoir description for reservoir
simulation and to develop
additional new well and workover opportunities to increase production. A reservoir
simulation study was performed to determine processes and methods to improve future production. The team making
consisted of thirteen staff from TCA Engineering, Loren and Associates, Robert M. Sneider
Exploitech and Maraven (Petroleos de Venezuela, S.A.).
This paper consists of six parts:
1.Geologic Framework is based on 3D seismic and detailed well log correlation. The
are composed of deltaic and marine deposits, which are subdivided into 16 flow units.
Complete to partial
barriers to vertical and horizontal fluid flow result from stratigraphic facies changes
and/or faults. The
deltaic-marine depositional model was used to guide the mapping of geological and
parameters, sand/shale continuity, and facies distribution.
Page 2, Background and Scope
2.Petrophysical Evaluation includes documentation of the methodology used to calculate
variables in each of the 63 wells over the C440 - C460 intervals. Average values of
saturation, permeability, net feet pay and hydrocarbon pore volume were summarized for
each of four pay
categories for the sixteen flow units. The Lorenz coefficient, which expressed
calculated for each flow unit.
3.Reservoir Characterization includes maps of porosity, permeability, water saturation,
hydrocarbon pore volume, Lorenz coefficient, structure and depositional facies. These
parameters are the
major input data for the reservoir simulation model. A network of cross sections
illustrate the structure,
stratigraphy, and continuity of reservoir units and flow barriers.
4.Reservoir Performance and Observations includes an analysis of some of the production
behavior of the C440, C455 and C460 reservoir units.
5.Development Opportunities consist of seven types of workovers, two field extension areas
and one new
drill opportunity to increase production in a newly defined fault block.
6.Reservoir simulation study covers the reservoir engineering processes and methods,
including a water
alternating with gas (WAG) scheme to improve future production.
The Eocene "C" reservoirs and flow barriers are controlled primarily by
depositional processes and to a lesser
extent by diagenesis. The major depositional system for the C-440 to the Guasare is an
overall transgression. The lower C-4 interval, including the C-455 and C-460 is low energy deltaic, and the upper
interval including the
C-440 to C-452 reservoirs are shallow marine.
Detailed structure maps were constructed using seismic and well log control for the Top
Guasare (unconformity), and four stratigraphic horizons.
The hydrocarbons are trapped by a three-way closure on the upthrown side of a major down
to the northeast
fault. Six major faults dominate the overall structure pattern. These six faults separate
the field into four
production zones. A north to south fault with 100 to 150 feet of throw separates the field
into an eastern and western half that produce differently. Twenty-two small faults break up the western half
of the structure. The
eastern half of the field contains one minor fault. Except for the major east-west
bounding fault on the north side
of the field, no appreciable growth occurs across any of the faults in the C-4 section.
Cross sections indicate a
general thickening of the upper C-4 interval to the northwest.
Page 2, Geologic Framework
The C4 to C460 reservoirs are subdivided into sixteen-reservoir flow units that are mapped
across the field. A
reservoir flow unit is a reservoir zone that is continuous laterally and vertically, has
similar ranges of porosity,
permeability, and capillary pressure properties, and has similar position in a sedimentary
The field area contains numerous barriers and baffles to horizontal and vertical flow.
Both horizontal and vertical
flow barriers and flow baffles were recognized throughout the field. Both continuous and
laminations form barrier and baffles to vertical flow. Barriers to vertical flow are
easily recognized on RFT data. Barriers and baffles to horizontal flow are more difficult to recognize due to limited
pressure information. Facies
changes and faults form the barriers and baffles to horizontal flow.
Three scales of vertical flow barriers (Mega, Macro and Micro) are recognized in the
field. The mega barriers
separate shales/siltstones that cover wide areas. RFT data suggest that mega flow barriers
differences across the field. The macro barriers are recognized on logs because they are
thick enough to be
recognized. These barriers or baffles can not be correlated in nearby wells with
certainty. The micro barriers or
baffles are too thin to be recognized on logs. The continuity of these individual shales
is probably local, but the
high number of these barriers makes the effective vertical permeability low.
RFT data indicate that mega boundaries are field wide fluid barriers. Recognition of this
fine scale of flow
barriers/baffles has a large impact on completion practices and simulation results. The
entire zone must be
perforated to get effective flow through a flow unit. Pressure differences within flow
units indicate that the entire section is not being drained.
Capillary pressure measurements for six shale/siltstone core samples show that the sealing
capacity of the flow
barrier shales ranged from 90 feet to 3,892 feet for gas and 71 feet to 3105 feet for oil.
estimates from capillary pressure indicate permeabilities <0.001 md for all samples
except for one that has a
permeability of 0.044 md to gas. The shale layers will be effective barriers to fluid
migration during any fluid
Petrophysical evaluation of the C440 through C460 interval is based on log response
established by reservoir unit and calibrated to rock information obtained from
petrographic analysis of cores,
drill cuttings and thin sections. A lithology fraction variable was first calculated from
the normalized gamma ray
curve, and this variable was then utilized in the subsequent calculation of petrophysical
reservoir quality index (RQI) derived from the deep resistivity log and the lithology
fraction curve was useful in the
early stages of the project as an aid in differentiating bar and channel facies and in
correlation of the flow units. Porosity was based on the density log response, and was augmented by a relationship
porosity and lithology fraction in order to solve problems associated with log calibration
and invalid log
response in rugose boreholes. The cementation exponent was defined as a function of the
porosity and RQI using the observed dependence of cementation exponent upon porosity established by
The Waxman-Smits cation exchange capacity model was selected for the water saturation
volume was determined from the lithology fraction curve, and Qv (cation exchange capacity
per unit pore
volume) was determined from clay volume and porosity using a clay activity level
representative of kaolinite.
Permeability was calculated as a power function of porosity and water saturation, with a
applied in order to account for the variation in water saturation within the transition
zone. Selection of
appropriate parameters for the permeability equation was guided by measurements on cores
and by estimates
on drill cuttings.
The pay counts and petrophysical properties of each of the sixteen reservoir units are
summarized for each well.
Within each of the zones the net feet of pay and average porosity, water saturation and
permeability were calculated in each of four pay categories. In addition, the Lorenz coefficient to describe
was calculated for the combined pay categories selected for reservoir mapping and the
simulation model. The
software utilized for the petrophysical work was used to generate files of the pay summary
results in the format
required by the mapping software system. The mapping process sometimes highlighted values
properties for specific wells, but not that unusual when considered as a single well.
Investigation of the potential
problems sometimes led to discoveries of errors associated with the upstream processing
calculations or with
the original digital log data. All significant problems associated with the data anomalies
have been addressed
prior to generating the final maps.
Seven attributes were mapped for each of the 16 flow units of the Eocene "C"
reservoirs (112 total maps) .
The maps for each reservoir flow unit were mapped as follows: Facies maps were constructed
information from core, cuttings, calibrated well log shape, reservoir quality index, RQI
and mapped distribution of petrophysical attributes. Structure maps had structural contours that follow well
values. Where well control was
sparse, contouring follows the depth converted seismic Guasare interpretation. Seismic
data and well cuts
positioned fault polygon. For the simulation maps, contours were only offset along faults
with large throw. Net
Feet of Pay/Net Sand used depositional facies models as a guide for contouring.
Porosity data came from core-calibrated log determinations. Porosity values show very
little variation across the
field. To ensure a uniform distribution of contours across the maps, porosity was
contoured at 0.5% or less.
Permeability came from cross plot data from cores calibrated with well logs. The
distribution of permeability for each flow unit was hand edited based on porosity, facies and net pay thickness trends.
Water saturation was determined from well logs and saturation contours follow well values.
However, away from
well control, the relationship between structure and porosity guided contouring of water
saturation. Structure and
porosity control water saturation by the equation:
Where Ř = Porosity
Sw = Water Saturation
d = Depth above free water level (FWL)
FWL = (C453/455/460) = 13,860 feet
FWL = (C440 to 452) = 13,400 feet.
Hydrocarbon Pore Volume: The water saturation, net feet
of pay and porosity maps controlled the hydrocarbon
pore volume (HPV)mapping. Contours were based on the calculated HPV found by multiplying
the hand edited
porosity, water saturation and net feet of pay maps using equation:
(I-Sw) x (Net Feet Pay) x (Porosity)
Lorenz Coefficient is a measure of reservoir
heterogeneity. Lorenz Coefficient contours follow well values. No
clear relationship between facies and Lorenz Coefficient was observed in the data.
PERFORMANCE AND OBSERVATIONS
Reservoir performance of the Eocene "C" was monitored using wireline formation
tests, pressure buildup analysis and production logging with flowmeter surveys. Data from these tools provided an
understanding of the
horizontal barriers. reservoir lateral continuity, formation damage, correlation with
log-observed pay categories
and water production and its effect on well performance.
The wireline formation pressures are the most accurate in determining the amount of
depletion in specific
producing intervals. Buildup pressures measured after the well completion are difficult to
use for this purpose
because the completion intervals usually commingle several different reservoirs. The
extrapolated pressure is a
weighted average of the reservoir pressures and is therefore not definitive for
determining the pressure and
depletion in the individual layers. It is difficult to establish layer continuity from RFT
data, but these
measurements clearly identify depletion occurring in the various layers. However, where
depletion exists, lateral
continuity must exist with offset wells responsible for the depletion at the infill well
Page 2, Reservoir Performance and Observations
Production logging is an invaluable tool for quantifying the contribution to production of
the individual layers in a
multi-zone field, such as the Eocene "C". The profile is necessary to monitor
reservoir performance, to insure all
perforated intervals are producing and to design and evaluate stimulation treatments.
Based on a review of the
flowmeter logs in this field, many of the perforated intervals in the wells are not
contributing to production. Many
of these non-flowing, perforated intervals are zones that have reasonably high reservoir
pressure and have good
rock quality based upon petrophysical analysis. The explanation for this problem is
perforations and/or formation damage from completion/stimulation fluids or scale.
Water production in this field is a serious concern because of the impact on well
performance and the possible
reduction in oil reserves within the affected reservoirs. All wells in the study area
completed in the C-455/C-460
reservoirs are producing water at rates ranging from 1 to 300 BWPD. Many of the wells in
this area have been
abandoned within the C-455/C-460 due to water production (sometimes at relatively low
water production rates)
and have been recompleted in shallower horizons. Water production appears to be due to
breakthrough in an
interval or communication behind casing. Two mechanisms that may account for the water
production with poor
pressure support are water cusping from the aquifer and expansion of the connate water as
Production rates could most likely be increased by workovers and selective stimulation in
the C-460 and the
intervals between the C-455 and the C-440. Seven wells have been selected for a proposed
Development opportunities consist of new wells in new reservoir compartments and workovers
of existing wells.
Three new drill well opportunities are recognized: northeast of the field in a separate
fault block, down structural
dip to the southwest and to the southeast. Northeast Fault Block: This well has a
potential for 6.0 million barrels
of moderate risk recoverable reserves in an undrilled structure in a separate fault block.
The opportunity is
located several hundred feet structurally higher than a poor producer in an adjacent
separate fault sliver.
Southwest Extension: this opportunity is located in production Area IV that is separated
from the rest of the field
by an east-west fault. The opportunity is along the structural strike of four wells that
have produced at least 17.8
million barrels with a low water cut. This extension area could have over 100 million
barrels of oil-in-place and
potential recoverable reserves of over 20 million barrels from the C-440 through the C-460
Southeastern Flank: this opportunity is within production Area I and most likely contains
significant volumes of
undrained oil. The most downdip well in the fault block was never completed, but
indicates considerably more pay than well VLC-363, which produced more than 6 million
Page 2, Development Opportunities
Seven representative workover candidates in the C450/C-460 reservoirs are identified.
These seven wells
(VLC-586, VLC-642, VLC-916, VLC-952, VLC-955, VLC-964, VLC-1029) will provide critical
and help refine the reservoir simulation model. A successful workover program could add up
to 3,600 barrels of
oil per day and add reserves of over six million barrels.
There are numerous other downdip opportunities in the C-440 to C-488 intervals.
shows no large increase of water saturation with depth. This suggests that the field water
level is considerably
down structure than previously mapped.
From production performance and water occurrence, four separate production regions are
north-south fault in the center of the field is probably sealing; production performance
is different on either side
of the fault. East of the north-south fault, the producing water level is more than 250
feet higher than west of this
fault. Structurally higher wells just to the north of the east-west fault are abandoned,
yet the wells south of this fault
are still productive. This suggests that the east-west fault has a major effect on
The objective of the simulation effort was to examine the potential for enhance oil
recovery in the C455/C460
pay intervals of the Eocene C-Lower, VLC-363 reservoir, Block III, Lake Maracaibo. The
study was conducted in
two parts. First the displacement efficiencies of alternative processes were examined
simulations. Then the recovery efficiencies of alternative processes were examined using
simulations of representative reservoir elements.
The oil is very volatile in this reservoir and there is considerable shrinkage below the
bubble point. The pressure
in the target intervals of the reservoir were well below the bubble point when this study
was initiated. The
extensive depletion below the bubble point has resulted in 1) significant oil shrinkage;
2) the formation of
secondary gas caps underlying barriers separating flow units; and 3) insufficient free gas
being available to
significantly swell the oil upon repressuring by means of water injection. The consequences of these
circumstances are 1) there is very little waterflood moveable oil saturation; 2)
repressuring by means of water
injection will not significantly increase the waterflood target; 3) without repressuring,
gas injection will resulting
very little oil recovery by means of mass transfer, although with repressuring the system
could become miscible;
and 4) without repressuring, injected gas will stream through existing high gas saturation
regions of the
A representative cross-section of the reservoir, some 28% COIP, was used to study
processes. An eleven grid-layer model was used to represent seven geological flow units
comprising the pay
interval of interest. The two dominant, highly stratified flow units were described by
three grid-layers each by a
technique that utilizes Lorenz functions.
Thus, the reservoir mapping provided by the geoscience study provided not only the normal
parameters for input to the simulation model, but also a mapping of the Lorenz function
which represents the
areal variation of the reservoir heterogeneity which controls vertical sweep efficiency.
Without an initial reservoir fill-up, the predicated poor displacement efficiency for
water and gas injection
resulting from the extensive depletion below the bubble-point is predicated to be
exacerbated by poor sweep
efficiency resulting from reservoir heterogeneity and the high free-gas saturations
existing at the start of
injection. Because so much prior shrinkage and limited free gas remaining in place at the
start of injection, a waterflood is predicted to recover less than 0.05% OOIP additional oil over continued
primary. Similar results
are found for gas injection. However, if target flow-units are filled up via water
injection, resulting in substantially
increased displacement pressure for subsequently injected gas, the oil recovery is
predicted to improve
markedly. Straight gas injection after fill-up is predicted to recovery 0.11 OOIP
additional oil over primary. For a
2:1 WAG process, the predicted additional recovery is 0.16 OOIP. And for an infill program
which would result in
much better pattern configurations, the predicted additional oil recovery is 0.23 OOIP.