A field in South Oman discovered in 1978 is an over-pressured sour oil reservoir. Since first oil began in 1982, the field will has gone through three stages of development during its life. These can be summarized as follows; pressure depletion, pressure maintenance with sour separator gas plus sweet make-up re-injection, pressure maintenance with sour separator gas plus sour makeup gas injection from other fields The field produces from the A4C unit of the Ara Group intra salt carbonates. A carbonate reservoir totally encased in salt. No water has been produced to-date from this reservoir. The reservoir oil column is overlain by a gas cap and the reservoir fluid exhibits a strong compositional gradient which impacts the degree of richness required for a sour miscible gas. Development drilling and the construction of facilities proceeded with all well tubulars and facilities constructed out of carbon steel. Operation of the plant and wells occurs with high regard to the risks of sour, high pressure service, and with no integrity or corrosion has been observed to-date. The field produced under depletion starting in 1982 through oil and gas cap expansion mechanism. The field was shut-in in 1986 awaiting gas injection. In 1993, sour separator gas combined with sweet make-up gas was re-injected as a pressure maintenance project to keep the reservoir pressure from dropping further. Upon expansion of the production station to take production from other nearby sour oil fields, more sour gas was added to the gas injection stream in 2004. Plans are developing to change the composition of the injection gas stream to achieve higher H2S levels so that the injected gas will become miscible with the A4C oil. This is designed to further increase oil recovery. The purpose of this paper is to present the development history of this sour oil reservoir along with presenting the development approach that has been taken for injecting sour gas to increase oil recovery in this remote South Oman reservoir. Introduction The purpose of this paper is to present the development and performance history of a pressure maintenance project of a sour oil (H2S & CO2) reservoir developed in the Ara Salt in South Oman (Figure 1). This reservoir has undergone three stages of development with potential for miscible sour gas injection. These stages are as follows; pressure depletion (1982 - 1986), gas injection (1992 - 2004), sour make-up gas injection (2004 - to date). Estimated ultimate recovery is 30.6%. Modeling work has indicated that miscible gas injection will increase the oil recovery factor to 36% (Figure 9).

No abstract

The use of smart completion with downhole fluid control through Inflow Control Valves (ICVs) has been extensively described in the literature for balancing the water injection profile and improving the sweep efficiency in commingled water injection. This paper describes the limitations of such a system in ensuring zonal distribution of water in stacked, highly heterogeneous reservoir systems. Voidage replacement and pressure maintenance requirements necessitate waterflood under fracturing conditions in the four stacked reservoirs (Zone 1 to Zone 4) in Piltun field, offshore Sakhalin Island, Russia. These reservoirs are heterogeneous with differences in their permeability and fracture gradient. Consequently, smart injectors with four ICVs were planned to maintain the desired injection allocation in these reservoirs. The initial injectivity of these wells was extremely low with all of the injected water going to the deepest zone (Zone 4). An expensive pump upgrade improved the overall injectivity, with drastic changes in the distribution of the injected water amongst the reservoir layers. Contrary to performance prior to pump upgrade, the shallowest zone (Zone 1) emerged as the dominant receiver of injected water. Overall, the zonal distribution of water remained a problem with little success in injecting water in the remaining two zones (Zone 2 and Zone 3). Very limited improvement in the water distribution was obtained by manipulating the ICV valves. Sector modeling was taken up for the injection wells to understand the injection behavior. Modelling results show that after the pump upgrade, fracturing was initially achieved in all zones, although sustained fracture opening and propagation was only possible in Zone 1, the reservoir with better flow properties and reasonably low fracture gradient. The other zones gradually reverted back to injection under matrix conditions with time. The additional pressure drop created by the flow control device is not sufficient to choke back the major zones and achieve sustained fracture growth and water injection in the minor zones in Piltun field. The results demonstrate that the use of intelligent completion for waterflood conformance can be limited by large stress and permeability contrast.

No abstract

No abstract