The depressed oil price has spurred a new wave of innovation in oil and gas industry. When a barrel of oil fetched $100 or more, energy companies were focused on drilling wells and pumping crude oil as fast as they could. However, with oil price has settled around $50 a barrel these days, companies are focused on efficiency; getting the most petroleum for the least amount of money. And many are turning to advanced technology or innovation for help. This session will focus on innovative approaches to reduce cost for mature assets to sustain field life including technology, well types, business model, and resource management. This session also aims to address topics on improving recovery factor through innovative activities in production enhancement and optimization, and tertiary recovery method.
Allard, D.N. (West Australian Petroleum Pty. Ltd.) | Hillyer, M.G. (West Australian Petroleum Pty. Ltd.) | Gerbacia, W.E. (Chevron Overseas Petroleum Technology Company) | Rychener, L.M. (Chevron Overseas Petroleum Technology Company)
This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3-6 October 1999.
Determination of how much production contribution from individual zones in amulti-layer environment is very critical in optimizing initial commingledcompletions and subsequent workovers. The conventional Individual ZoneProduction Testing (IZT) method to determine the maximum well productivity isvery inefficient due to unnecessary repetitions in workovers resulting inhigher operation cost.
The possible maximum production rate of each layer can be estimated bycalculating its productivity index and applying the maximum allowable pressuredrawdown. Data to calculate the productivity index for each layer is not alwaysavailable. Production logging (PLT) or IZT, the source of data is not run inevery well. These common problems could be addressed by instituting aproduction zone allocation system.
This paper reports a practical approach to estimate absolute horizontalpermeability and the specific productivity index (SPI) by correlating todensity porosity ( d) and Volume Shale of Gamma Ray Index (VshGR) for Sihapasformation in Minas Field. The d and VshGR are calculated from open hole logdata, which is usually available. The correlation is principally generated byusing the permeability - density porosity transform, relative permeabilitycurve and Darcy's law for radial flow in porous media. The calculated SPI is afairly good match with actual field data obtained from PLT and IZT. In someconditions the calculated SPI is under estimate compared to actual data. Thisslight disagreement will also be reviewed in this paper. The method to generatethis practical correlation can also be applied to data from other fields.
Estimation of formation fluid or oil production from each layer is afundamental common problem in the multi-layer oil production system, such asMinas Field. Inter layer communication behind cement, and water cross-flowthrough channels in the cement between casing and formation can even make itworst. Production allocation system can be expected to ease the problem in thereservoir management. However, it is very complicated to generate the systemdue to reservoir heterogeneity and complexities with very limited dataavailable.
Minas is a major oil field in Indonesia located about 33 KM northernPekanbaru, the capital city of Riau Province. This field, operated by PT.Caltex Pacific Indonesia with a Production Sharing Contract (PSC) system, is agently dipping anticline which is 28 km in length and 7 to 13 km in width.Original oil-in-place is estimated to be 9.0 billion STB.
Minas field was discovered in 1944, and the first oil well was initiallycompleted and put on production in 1952. The initial field development was 214acres spacing. To enhance the natural aquifer pressure support, peripheralwater injection was started in 1970. A closer well spacing of 71 acres fielddevelopment was begun in 1978. In order to increase oil recovery, 23.7 acrespacing of Phase 1 inverted seven spot waterflood has been implemented in highgraded areas of the field since late 1993. The ultimate oil recovery of thewaterflood project is expected to be 51 % of the original oil-in-place.
The average recent field production is around 250,000 BOPD and 94.9 % watercut from commingling of several layers of Sihapas formation. The Minas fluidproduction is artificially lifted by Electric Submersible Pumps (ESP) from 679active wells, that will increase significantly in the near future when theplanned tertiary oil recovery processes with a closer well spacing isimplemented.
Sihapas formation of early Miocene age is overlain by the Telisa formationof the Middle Miocene age, and underlain by Pematang formation of the Paleoceneage. The Reservoir sands of Sihapas are divided into six major units referredto as A1, A2, B1, B2, D and S sands separated by five major shales.