SNEIDER, JOHN S., ROBERT M. SNEIDER, Robert M. Sneider Exploration, Inc., Houston; CAROLINA COLL, BICE CORTIULA, GEDI GONZÁLEZ, PDVSA, Caracas; JOHN T. KULHA, John T. Kulha Consulting, J. DENNIS LOREN, Loren and Associates, Inc., DAN SHAUGH-NESSY, Interpretation3 , and MICHAL R.TODD,TCA Reservoir Engineering Services, Inc.
Abstract: Rejuvenating a Mature Supergiant Field VLC-363, Block III Field, Lake Maracaibo, Venezuela - Reservoir Characterization
A multidisciplinary team of geoscientists and engineers studied the Eocene Lower "C" reservoir to provide a detailed reservoir description for reservoir simulation and to develop new well and workover opportunities to increase production.
The geologic framework is based on 3D seismic data, cores from 8 wells, cuttings and detailed well log correlations. A three-way closure on the upthrown side of a major down to the northeast fault traps the hydrocarbons (Figure 1). The area experienced several episodes of extensional and wrench faulting. Six major faults dominate the overall structural pattern and separate the field into four production zones (Figure 2). Twenty-two minor faults with throws from 20 to 150 feet break up the western field area. The producing water level varies by at least 350 feet across the north-south trending fault in the middle of the field. Throw on this fault varies from 150 feet to 20 feet decreasing to the north. A comparison of shale gouge ratios calculated from wells and production data suggest that faults with throws greater than 100 feet are likely to seal; faults with throws less than 100 feet form flow baffles.
Depositional processes and to a lesser extent diagenesis control the reservoirs and flow barriers distribution. The C440-460 reservoirs consist of deltaic and marine deposits formed during an overall transgression and are subdivided into 16 flow units. The deltaic-marine depositional model guided the mapping of geological and petrophysical parameters, sand/shale continuity, and facies distribution.
The field area contains numerous barriers and baffles to horizontal and vertical flow. Both continuous and discontinuous shale laminations form barriers 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 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 and support pressure differences within the field of several thousand psi. The macro barriers are well developed in single wells, but cannot be correlated in nearby wells with certainty. The micro barriers /baffles are too thin to be recognized on logs. The continuity of these individual shales is probably limited, but the high number of these shales makes the effective vertical permeability low.
The small-scale flow barriers/baffles have a large impact on completion practices and simulation results. The entire zone must be perforated to get flow throughout 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 shales ranged from 90 feet to 3,892 feet for gas and 71 feet to 3105 feet for oil. Permeability estimates from capillary pressure indicate permeabilities of <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 transmissibility during any fluid injection project. Kv/Kh from individual sandstone samples are around 0.6, but Kv/Kh for the reservoir flow units including the.thin bedded shales is <0.001. This difference in Kv/Kh has a significant effect in field performance and on the secondary recovery process.
The petrophysical evaluation of 63 wells in the C440-C460 interval is based on normalized and corrected log response interrelationships established by reservoir unit. The evaluation is calibrated to rock information obtained from cores, drill cuttings and thin sections. A lithology fraction variable was calculated from the normalized gamma ray curve; this variable was then utilized in the subsequent calculation of petrophysical characteristics. A reservoir quality index (RQI) derived from the deep resistivity log and the lithology fraction curve was used in the early stages of the project to differentiate between bar and channel facies, and used in the correlation of the flow units. Porosity was based on the density log response; problems associated with log calibration and invalid log responses in rugose boreholes were corrected using a relationship developed between density porosity and lithology fraction. The cementation exponent was defined as a function of the porosity and RQI using the observed dependence of cementation exponent upon porosity established by petrographic analysis.
The Waxman-Smits cation exchange capacity model was selected for the water saturation calculation. Clay 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 correction for water saturation variations within the transition zone. Core measurements and estimates from drill cuttings guided the parameters selected for the permeability equation.
Seven attributes were mapped for each of the 16 flow units of the Eocene "C" reservoirs (112 total maps). These maps were the input data for the reservoir simulation model. Average values of porosity, water saturation, permeability, net feet of pay and hydrocarbon pore volume were summarized for four different pay categories for the sixteen flow units. Facies maps were constructed using information from core, cuttings, calibrated well log shapes, reservoir quality index (RQI) and the distribution of petrophysical attributes. Structure maps were constructed using well data and were guided by the 3D seismic interpretation at the base of the reservoir section, the top of the Guasare Formation a regional unconformity. Seismic data and well cuts positioned fault polygon. Net feet of pay/net sand data was contoured using depositional facies models as a guide.
Porosity values show very little variation across the field. 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. Away from well control, the following relationship between structure and porosity guided the contouring of water saturation:
Sw=0.0386*f -1.526 *d -0.464
Where: F = Porosity, Sw = Water Saturation, d = Depth above free water level (FWL), FWL for the C-453/455/460 is 13,860 feet, FWL for the C-440 to 452 is 13,400 feet.
Hydrocarbon pore volume (HPV) maps were constructed by multiplying the hand edited porosity, water saturation and net feet of pay maps using the equation: (1-Sw) x (Net Feet Pay) x (Porosity). Heterogeneity in flow units was estimated using a Lorenz Function. The Lorenz Coefficient was mapped following well values. No clear relationship between facies and Lorenz Coefficient was observed in the data.
A network of cross sections illustrates the structure, stratigraphy, and continuity of reservoir units and flow barriers.
Development opportunities consist of seven types of workovers, two field extensions and one new drill opportunity (Figure 3). The workover program could add up to 3,600 barrels of oil per day and add reserves of over six million barrels. The two field extensions could add at least 26 million barrels of low to moderate risk reserves. This development program has recently commenced.
The simulation study was conducted in two parts. First the displacement efficiencies of alternative processes such as water injection, gas injection and water alternating with gas injection (WAG) were examined using one-dimensional simulations. Then the recovery efficiencies of alternative processes were examined using multidimensional simulations of representative reservoir elements.
The oil is very volatile in this reservoir, and there is considerable shrinkage below the bubble point. The field has extensive depletion below the bubble point in the target interval that 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 result in 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 reservoir.
Because of 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.
The predicted oil recovery is 0.23 OOIP if infill wells are used to improve
the pattern configuration.
Figure 1. Structure map at the top of C- 455. The map shows the status of producing wells in July 1995 and the producing water level.
Figure 2. Major faults and production zones in the field.
Figure 3. Map showing areas
where new wells may add significant reserves.
AAPG Search and Discovery Article #[email protected] International Conference and Exhibition, Birmingham, England