Fireflood of the P2-3 Sand Reservoir in The Miga Field of Eastern Venezuela

Abstract

Terwilliger, P.L., SPE-AIME, Gulf Research and Development Co., Clay, R.R., Gulf Research and Development Co., Wilson Jr., L.A., SPE-AIME, Gulf Research and Development Co., Gonzalez-Gerth, Enrique, SPE-AIME, Gulf Research and Development Co. In 1964 Mene Grande Oil Co. began a fireflood in a sand reservoir of the Miga field in Eastern Venezuela. It was expected that only 5 percent of the 13 degrees API gravity oil would be recovered by primary means; the fireflood has recovered more than twice that amount. No serious operating problems have been encountered. problems have been encountered. Introduction In 1964 Mene Grande Oil Co. started a fireflood in the P2-3 sand reservoir in the Miga field of Eastern Venezuela. The project has continued since that time. The original oil in place was estimated at 23.2 million bbl and 1.2 million bbl, or 5 percent, was expected to be produced by primary depletion. To date, an additional 2.6 million bbl, or more than twice the primary production, have been recovered by the use of the fireflood process. The air injection rate has averaged about 10 MMcf/D over the 9-year life. The average air/oil ratio (AOR) has been 11,000 cu ft/bbl. No serious operating problems have been encountered during the fireflood. The loosely consolidated sand is controlled through use of pressure-gravel-packed liners. Corrosion has not been a problem. No water injection has been used for producing well cooling, although a lighter oil is used for down-the-hole blending to increase the producing rates and facilitate the surface handling of the oil. Past performance and sweep pattern studies indicate that fireflooding could result in the production of 50 percent of the original oil in place, whereas the ultimate percent of the original oil in place, whereas the ultimate primary recovery would be only 5 percent. Experience both primary recovery would be only 5 percent. Experience both in this reservoir and other similar ones had shown that gas drive and waterflooding were completely ineffectual. Reservoir Description The project was performed in the P2-3 sand, MG-517 reservoir, of the Miga field located in Eastern Venezuela. A structure-isopach map of the project reservoir appears in Fig. 1. Fig. 2 includes a summary of the reservoir properties. This reservoir is one of several in the P2-3 properties. This reservoir is one of several in the P2-3 channel sand, which is found in scattered locations throughout both Miga and the neighboring Oleos fields. The updip seal is a combination of faulting and sand thinning. Lateral limits are considered to be the 10-ft isopach, as indicated in Fig. 1. The downdip limit is formed by a fault and the original water-oil contact. Reservoir volume is estimated at 18,600 acre-ft. Well MG-525 was high-GOR when completed, suggesting a small initial gas cap. At the time this well was selected for air injection, the south boundary of the reservoir was believed to be a fault located just south of the well. The revised interpretation of the reservoir indicates this is not the case; the reservoir actually extends much further south, as indicated in Fig. 1. Depth of the reservoir ranges from 4,000 to 4,350 ft below ground level, with dip to the north of about 2 degrees. The sand is loosely consolidated, with a porosity of 22.6 percent and an estimated average porosity of 22.6 percent and an estimated average permeability of 5 darcies. Maximum sand thickness is permeability of 5 darcies. Maximum sand thickness is about 25 ft. Connate water saturation is about 22 percent; stock-tank oil originally in place was 23.2 percent; stock-tank oil originally in place was 23.2 million bbl. P. 9

Workflow of the In Situ Combustion EOR Method in Venezuela: Challenges and Opportunities

“…Despite obtaining good results in terms of oil properties’ improvement (viscosity reduction and increase of the API gravity), technical-operational and economic issues (low productivity of the wells, a higher than expected air-injected oil produced ratio, high temperature in the wells, generation of corrosive fluids/acid gases, sand plugging of the wells, failure of compression units, low oil prices, and high costs) led to the suspension of the projects. ,, According to the literature, currently there are no active ISC projects at field scale in Venezuela, and efforts have been made on research projects (at laboratory and simulation scales) with a view of understanding the key variables of the process and implementing a pilot test project in the FPO in the future. This section includes a review of the projects performed in the last 2 decades, as follows.…”

“…1 Thermal 2−6 and thermo-chemical IOR (hybrid) have been the most suitable methods to recover bituminous oils in Venezuela, in zones without significant risk of water production from aquifers. 1,7 Air injection or in situ combustion (ISC) is one of the oldest thermal enhanced oil recovery (tEOR) methods evaluated in highly viscous oil reservoirs worldwide, 8−13 and in Venezuela it has been considered as a highly potential method for increasing oil production for more than 6 decades, [14][15][16][17][18][19][20][21]23 the first experience being at the end of the 50s in a deposit of the Lake Maracaibo Basin. 15,19,22 ISC is an advantageous technique over steam flooding in terms of water consumption (for steam generation) and greenhouse gases emissions.…”

“…Air injection or in situ combustion (ISC) is one of the oldest thermal enhanced oil recovery (tEOR) methods evaluated in highly viscous oil reservoirs worldwide, − and in Venezuela it has been considered as a highly potential method for increasing oil production for more than 6 decades, − , the first experience being at the end of the 50s in a deposit of the Lake Maracaibo Basin. ,, …”