Karachaganak Field is a gas condensate field in Kazakhstan. It is located about 150 km east from the city of Oral (Uralsk) in the northwest of Kazakhstan. The field was once a massive Permian and Carboniferous reef complex covering an area 30 km by 15 km. At its largest point the reservoir contains a gas column 1450 m deep with a 200 m deep oil rim below it. It is estimated to contain 1.2 trillion cubic meters 42.4 trillion cubic feet (tcf)) of gas and 1 billion tonnes of liquid condensate and oil. Discovered in 1979, it began production under Karachaganckgazprom, a subsidiary of the Russian Gas Company Gazprom. Kazakhgas took over operatorship after the independence of Kazakhstan in 1992. in 1992 AGIP (now Eni) and the then British Gas (now BG Group) were awarded the sole negotiating rights, forming a partnership company. In 1997 Texaco (now Chevron Corporation) and Lukoil signed a production sharing agreement with the original two companies and the Kazakhstan Government. This is a 40-year agreement to develop the field to allow the production to reach world markets. This is done under a partnership company known as Karachaganak Petroleum Operating (KPO) where BG Group and ENI are joint operators with a 32.5% stake each in the company, with Chevron and Lukoil owning 20% and 15% respectively.
This began with three wells penetrating into the Permian formations of the reservoir. Once produced to surface the gas and oil were separated before being piped to Orenburg where further processing was undertaken. This was partially due to the sour nature of the gas, with a hydrogen sulphide content of 3.5-5% and carbon dioxide content of 5%. Karachaganckgazprom also maintained a policy of full gas voidage replacement to maintain pressure of the reservoir above the dew point. By 1990, approximately 200 vertical wells had been drilled in Karachaganak reaching a peak production plateau of 155 bcf/yr (4.4 km³/yr) of gas and 100,000 bbl/d (16,000 m³/d) of oil, before beginning to decline in 1992.
Beginning in 2000 under the operatership of Karachaganak Petroleum Operating (KPO), the field went under a redevelopment program. This involved an investment of over US$1 billion dollars into the construction and enhancement of existing facilities, new gas and liquid processing and gas injection facilities, a workover program consisting of 100 existing wells, a 120 MW power station for the facilities, and connection to the Caspian Pipeline Consortium via a 650 km line to Atyrau. This phase was officially completed in 2004, allowing for the production handling of 700 MMscf/d (20,000,000 m³/d) of gas and 200,000 bbl/d (32,000 m³/d) of oil.
|Reservoir pressure||Reservoir temperature||Reservoir porosity||Net/gross ratio||Water saturation||Density of condensate||Average permeability||Top of structure||Gas-oil contact||Oil-water contact|
|52–59 MPa||70 to 95 °C||9%||40%||10%||47 °API|
|2 mD (2 µm²) with high perm streaks||3500 m||4950 m||5150 m|
Overall, it is planned to recover about 300 million tons of liquid hydrocarbons and 800 billion cub. m of gas during the contract period.
One current production issue facing the field is the increasing amount of gas of which a large amount is sour. As the export facilities of the project are not fully developed most of this gas is being recycled back into the reservoir until it can be exported profitably.
The field consists of a heterogeneous carbonate massif with strata from three geologic periods and numerous stages of deposition during these periods. The following have been identified:
The depositional setting of the field is also varied. On the basis of core sample analysis and seismic studies the following depositional settings have been identified: limestone, talus, normal marine, shallow marine, inner reef lagoon, reef core, relatively deep water, slope and anhydrite.
The variation of deposition is due to the long period over which the Karachaganak structure was formed. From the Late Devonian to the middle Carboniferous the field was an atoll, over which in the early Permian a system of reefs were built. At its greatest the reservoir is 1.5 km thick. This type of reservoir structure has been seen in analogous fileds including Kenkiyak, Zhanazhol, Tengiz, and possibly Astrakhan fields. A west-east cross section through Karachaganak resembles the twin humps of a camel, indicating two separate reef highs.
Likewise the large variation of deposition has led to four different types of carbonate cores in the structure: biothermal, biomorphic detrital, organo-clastic, and biochemogenic. Of these biomorphic detrital are the most common followed by biothermal rock types. However estimates of their volumes range from 30-90% for the former and 10-60% for the latter.
As with other reservoirs in the North Caspian (Pricaspian) Basin, it is thought that the Karachaganak reservoir was filled over multiple stages, the first of which began during late Paleozoic time with he formation of oil pools. As the basin began to subside, gas was generated and migrated to the traps. The gassiness of the reservoirs is determined by their location in the basin. Northern reservoirs tend to be wet; the southwest part of the basin is more gas prone than the east and southeast.