The deep exploration oil drilling activity in Oman has greatly increased since 1994, with two continuous strings of deep rig drilling activity in 1995 and 1996. In 1996 the total investment in drilling and completing deep (TVD greater than 3500m) exploration oil wells was approximately US$ 40 million. This paper will discuss this activity, considering the learning value in terms of drilling efficiency from the early wells and how this learning process has led to initiatives to reduce costs in the recent wells. The implementation of these initiatives has been successful and average well costs have been reduced by approximately 20% since 1994.
In addition technology trials to increase the well productivity have been implemented in 1996, the success of these different trials in this deep well environment will also be discussed. A step-wise approach to well cost reduction, uncertainty and risk management and productivity improvement has been undertaken so PDO will have the knowledge and confidence to plan a possible full scale development of these reserves. The high level activity is planned to continue in 1997 with continuing exploration, appraisal and development drilling programs, complete with further technology trials to achieve increased well productivity.
Petroleum Development Oman (PDO) discovered the potential for hydrocarbon reserves in the deep, hard rock, silicilyte reservoir in 1989 in the discovery well Al Noor-1. The well was production tested and on the basis of the results a follow-up well, Al Noor-2 was drilled and completed in 1992. Since this time two further exploration wells have been drilled in the same prospect and seven wells drilled in other exploration prospects in South Oman (two with anticipated surface pressures greater than 10,000 psi).
The prospects are located in the South Oman Salt Basin, they are encased on the top and the sides by a thick sealing salt package and sits on a thick shale package. The reservoir is an infra-Cambrian Athel silicilyte hard rock that mainly consists of micro-crystalline silica with salt cementing the pore spaces. The reservoir, containing light 48 degree API oil (about 5.5 kPa/m gradient), is penetrated at a depth of about 4,000m TD. The reservoir has a very low permeability and due to its stratigraphic encasement in salt and shale is nearly geostatically pressurized; initial reservoir pressure gradients were measured to be about 19.8 kPa/m with concentrations of H2S and CO2 of some 1.5 mol% and 3.0 mol% respectively at a gas/oil ratio of approximately 300. The average thermal temperature gradient is ca. 1.9 deg 1100m, giving a BHST of 100 deg C at 4,000m. In summary the wells can be classed as high pressure with a low thermal gradient but with high partial pressures of H2S and CO2.
The exploration success in the first two wells and the recognition of the large upside potential of the play led PDO to pursue an aggressive campaign. The exploration challenge for the 1995 and 1996 program was defined such that rig resources (10,000 psi and 15,000 psi) were balanced to evaluate the potential of the Athel play, both in and away from the greater Al Noor area, in the most cost-effective manner.
However, the combination of harsh operating conditions (4 to 5 km depth, severe overpressures, sour crude), reservoir and structural uncertainties (multiple pressure regimes, poor seismic response) must be overcome. The initial results were very positive but highlighted the significant technological challenges to be overcome if the full potential is to be realized. A second discovery in 1995 proved that Al Noor was not unique, the flow rates on the production test highlighted well productivity as a critical issue. Additionally, the penetration of alternating carbonate / anhydrite and siltstone / claystone sequences in two outstep wells, drilled on structures with a seismic response analogous to Al Noor, indicated the extent of the geophysical challenge.