Leon, Alfredo (Maraven S.A.) | Casas, Jhonny (Maraven S.A.) | Agostini, Nelida (Maraven S.A.) | Bengochea, Xiomara (Maraven S.A.) | Salamanca, Lourdes (Maraven S.A.) | Munoz, Pedro (Maraven S.A.) | Parra, Nestor (Maraven S.A.)
The La Rosa Basal Sand (Miocene), known in some areas as Santa Barbara Member, was discovered in 1954 as a pool for Block I area in Lake Maracaibo basin, with a relatively poor success during the next 40 years of production.
Since 1993 however, an aggressive policy of wokovers and drilling was undertaken increasing by over 300% the total production of medium and light oil. These activities were based upon the recommendations of several multidisciplinary team projects.
The La Rosa Basal Sand is a 5-60 ft thick sandstone deposited in a fluvio deltaic environment overlaying an unconformity which truncated Eocene successions (Pauji and/or Misoa formations). Lateral continuity varies from south to north and it is feasible not only to observe new sand bodies but also coalescent effect with the underlying Eocene productive sands. The La Rosa Basal Sand is overlain by a 100'-200' thick marine shale, known as La Rosa Shale.
Change of paradigm in the reservoir management was mainly a consequence of the result of well VLa-1185, upon the west flank of the Block which also demanded a revision of the petrophysical parameters. Its initial production of 1,300 BPD and 0.3% water, was difficult to explain considering resistivity values of only 8-10 Ohm-m, a parameter which had been long considered to indicate high water saturation. Such parameter subestimated remnant reserves and in some cases supported rejection of some well locations. Additionally new core data has helped to better understand reservoir behavior and predict future activities. During the last four years seismic interpretation, stratigraphic well by well correlation, structural and isopach maps and production history matching have been updated by information from new wells which have acted as a support for a slimhole campaign. Consequently, geologically targeted infill wells and no conventional workovers, increased production from 4000 BPD to 18400 BPD (Mid, 1996).
Block I area, located in the middle of Lake Maracaibo basin, is considered one of the more prolific fields in Venezuela (Fig. 1). By January 1996 oil production of this block has reached 2,158 MMSTB of medium and light oil from reservoirs of different ages: Miocene, Eocene, Paleocene and Cretaceous.
The La Rosa Basal Sand reservoir, of Miocene age, is characterized by a succession of sandstones and shales with an average thickness of 25 feet (Fig. 2) and commenced production on April 1954, with well VLA-13. The initial production was 1,874 STB/D, GOR of 700 SCF/STB and 1.2% of water cut. Gravity of the crude: 28.9° API.
In December 1996, 650 wells had been drilled in the area, most of them aimed at Eocene targets. Nowadays the reservoir is producing from 75 wells; other 24 wells had been closed due to operational problems and two were abandoned because of high water cut.
Physico-chemical analysis proved that water production was coming from underlying Eocene reservoirs which had communicated with La Rosa Basal Sand through either the casing or coalescent Eocene sands.
Calculated Original Oil in Place (OOIP) was 434.0 MMSTB. By December 1996 the reservoir had a cumulative production of 59 MMSTB.
Block I is divided by Icotea fault trend into two flanks: east and west. Initial pressure for wells of the west flank was 2900 psi and 3100 psi for wells of the east flank. (Fig. 3).
Update of the reservoir properties was obtained by interpretation of new 3D seismic (1991, 1993), sedimentological analysis of three new cores and an aggressive campaign for pressure data acquisition.
Experience of Drilling the Horizontal Well VLD-1152 in Lagunillas Formation, Block IV, Lake Maracaibo Basin, Venezuela.
The main objective of the horizontal well VLD-1152, located in Block IV, was to improve recoverable reserves which was impaired by pressure depletion and reservoir heterogeneities. The well represents an important challenge because it is the first horizontal well drilled in a depleted pressure area and it was drilled within a small productive interval of 25 feet thick only.
A pilot area was selected after a detailed multi-disciplinary study by geologists. petrophysicists and reservoir engineers. New 3D seismic interpretation revealed a structural model that conformed well with pressure behavior of the area. New information from well VLD-1112 were utilized to update the petrophysical properties and the volumetrics These data were input to develop improved reservoir description and build a reservoir model for flow simulation.
The results indicated that Layer VII is the most important drainage target. The principal reasons for selecting this unit were, good mechanical stability of the rock, absence of a water front and a secondary gas cap and the presence of a regional shale ar the top that might be used to navigate drilling.
Despite some operational problems encountered in drilling, the results were mostly satisfactory. The entire pay was penetrated and the geology and petrophysics of the drilled area came in line with our model predictions.
A pilot area, containing approximately 30 wells located in Block IV in Lake Maracaibo Basin,was selected as the site for a horizontal well (Fig.1). The target reservoir, VLC-52/VLD-192 Lower Lagunillas, commenced production in 1957 with well VLD-192.
The reservoir, which is stratigraphically divided into L, M and N sands, has not been uniformly drained. Since 1960, most of the wells have been completed in the L and N sands; therefore, the M sand has been less depleted. (Fig. 2) Production declination was very intense and was partially controlled by a gas injection program in 1967. Dropping pressure however continued until getting 1000 psi (Fig. 3)
The drilling of VLD-1112 well at south of the selected area, contributed with valuable information to validate the petrophysical parameters and calculate a new OOIP number which was found to be 20 % greater than the initial estimate of 264 MMSTB.
Once the new geological model and petrophysical parameters were defined, the more prospective area with less operational risk was selected. The output was used as information to develop a dynamic model for the simulator. The results provided well defined boundaries conditions and indicated the absence of an independent aquifer.
The selection of the zone was based on a combined evaluation of different criteria of orientations, lengths and restrictions for the horizontal well. This zone showed low values of porosity and permeability and a depleted reservoir character, justifying drilling of horizontal wells in order to improve oil recovery and maximize the production rate. The recommended location was GOF-3.
The main target is Unit VII of M Sand Lower Lagunillas Member. This sand has an potential of 1200 STBOD, and is expected to have a water cut of 5% and a GOR of less than 1000 SCF/STB.