Numerical Modeling of Sedimentological Facies as Flow Units in the Laguna Water Injection Project, Lake Maracaibo-Venezuela

Sanchez, Nestor Luis (Maraven) | Martinez, Claudio (Maraven) | Rattia, Aquiles (Maraven)



The Laguna water injection project was initiated by Maraven, S.A. in Jan. 1967 and consist of 145 wells of which seven are injectors located in the low part of the reservoir. Since 1973 two attempts to reproduce the project performance using three dimensional reservoir simulation performance using three dimensional reservoir simulation models have failed due to difficulties in matching the reservoir performance and the advance of the water injection front. Both studies were temporarily suspended for acquisition and analysis of additional field data to resolve ambiguities which affect the simulation results. In 1986 a sedimentological study of the reservoir and flow units allowed the identification of the main flow channels within each sedimentary unit observed in the main reservoir. Based on the results of this study a new three dimensional reservoir simulation model was built, integrating the geological and sedimentological models, allowing proper characterization of reservoir heterogeneities and reproduction of the project performance on a well by well basis through the end of 1987. The use of sedimentological facies and the flow units concept for the reservoir description of the Laguna project was the key for the numerical modeling of the water injection front advance in each flow unit within the accumulation, allowing to establish the actual distribution of the remaining oil saturation and the pressure profile. Finally, the future performance of the reservoir was predicted under different injection schemes, and an infill predicted under different injection schemes, and an infill drilling plan, employing ten new production wells in regions being poorly drained will permit to increase the recovery for the field by 40 MMSTBO (3% STOIIP).


The Laguna reservoir is located in Lake Maracaibo, Venezuela (Fig 1.). The initial oil in place was estimated in 1458 MMSTB, and cummulative production for January 1987 was 387 million barrels of 28 API gravity oil (26.5% of the STOIIP) leaving a remaining oil volume of 1072 MMSTB. Since 1951 to 1967 the reservoir produced by natural depletion with little support from an aquifer. The pressure had declined from the original of 4050 psia to 2060 psia at the depth of 9500 feet subsea. During August, 1967 secondary recovery was initiated injecting gas at the reservoir crest which was reforced in 1968 with water injection at the aquifer. Furthermore in 1974, the water injection was extended to the north-central part of the field. During 1975, the gas injection was part of the field. During 1975, the gas injection was discontinued since the expected reverts pressure support in the north area was not observed. The actual reservoir production rate is 16.5 MSTB/D and water is being production rate is 16.5 MSTB/D and water is being injected at a rate of 50 MSTB/D through five injectors in the south area and two in the north area. In the first part of the study a 3-D model was developed to reproduce the historical reservoir performance. The results of the reservoir match allowed to identify regions poorly drained under the actual production-injection front; observing that the injected water at the south of the reservoir has been channeling up dip along the main axis of the litoral bars identified in the sedimentological reservoir study (Ref.1) invading the zones with the best sand development in the reservoir. In the second part of the study the model developed was used to carry out sensitivities aimed to evaluated the strategy that allow to obtain the optimum scheme for the exploitation of the reservoir remaining reserves, and examine the effect on recovery of in fill drilling in regions indicated by the simulator as poor drained by the actual well configuration.