Optimal Exploitation Scheme in MFB-5 Reservoir

Abstract

Abstract In order to contribute with the development of Orinoco Belt reservoirs, a simulation model was created to be used on the extra heavy crude oil reservoir MFB-5, located in Bare block, Hamaca area. So far, this reservoir has produced about 1% of oil in place, estimated in 216 MMSTB. Besides, it has an associated aquifer, which generates high water cuts caused by channeling. This situation motivate the study of different exploitation strategies to obtain the most profitable oil recovery. At present reservoir conditions and under primary recovery, there is still a 14% of total recoverable oil (28 MMSTB). The main objective of this work was to obtain the highest oil recovery with the lowest number of new locations, and with the most favorable well production conditions for this reservoir. An economical analysis was performed for each scheme and the result was that the best technical and income-producing exploitation strategy, would recover 15% of OOIP in 20 years, which would exceed recoverable oil in place in 6% if the current 9 active wells are maintained producing under the present strategy. Introduction The reservoir MFB-5 is located in Bare block in the northwest of the Hamaca area within the Orinoco Belt (Figure 1). It covers an area of approximately 52 Km2. This reservoir has a STOOIP of 216 MMB of 10.5 °API oil, of which around 1% has been produced through 12 wells, 4 vertical and 8 horizontal, since 1986. There is an aquifer causing high water cuts in some wells. Due to the low oil recovery factor obtained so far and to the high water production observed in some wells, the main objective of the present study was to build and history match a numerical simulation model, to define an optimum exploitation scheme under cold production, for the reservoir MFB-5. Horizontal wells of 1600 feet were proposed to accelerate oil production, since field experience has established this optimum length. Static Model The reservoir MFB-5 has a simple monoclinal structure, cut by normal faults, dipping 2–3 degrees toward the north-east (Figure 2). The water-oil contact (WOC) is located at the north, at a depth of 2800 feet. The reservoir consists of middle-early Miocene age basal Oficina sands, with its top ranging between 2500 to 3170 ft depth. Based on core and log analysis, sedimentological interpretation has defined a fluvial system with interlaced currents, with two stratigraphic intervals for this reservoir, which are amalgamated in one package in some areas. The total thickness varies from 2 to 68 feet. The reservoir is limited in its top and base by seal shales of regional extension. This shales were easy to identify because they represent two flooding surfaces. Petrophysical properties were obtained from cores and logs interpretation. Porosity varies between 21 and 34.5 %, while permeability ranges from 0.9 to 7.8 Darcys. The irreductible water saturation was estimated around 16%, and according to the grain assemblage present on unconsolidated sands a Kv/Kh ratio of 1.0 was used1. Dynamical Model To analyze fluid properties and foamy oil behavior for this reservoir, conventional and non conventional PVT analysis were performed2. The results show an API of 10.5°, bubble point of 995 psi, pseudo bubble point of 830 psi, initial GOR of 105 SCF/STB and in situ oil viscosity of 810 cp at bubble point pressure. Two pseudo components (dead crude oil and solution gas) were used according to the fluid composition.