Karachaganak Field, Northern Pre-Caspian Basin, Northwestern Kazakhstan

Abstract

Karachaganak field was discovered in northwestern Kazakhstan by Uralskneftegasgeologia in 1979 and first produced by KarachaganakGazprom in 1984. The shareholder group of Ente Nazionale Idrocarburi–Agip (ENI-Agip), BG Group, Texaco (now ChevronTexaco), and Lukoil operates the field under a 40-yr production-sharing agreement that was signed with the Republic of Kazakhstan in November 1997 to optimize technical and economic recovery. The Karachaganak reservoir (13 25 km) is a giant retrograde gas-condensate-oil reservoir with a 1650-m hydrocarbon column and in-place hydrocarbons of 17.78 billion BOE. In the field, 252 wells have been drilled, with 163 available for production. An ongoing workover program has restored previously declining production to historic maximum levels. The current optimization plan calls for a partial depletion and enhanced gravity-drainage strategy that involves partial pressure maintenance through gas recycling and development of the oil rim using horizontal wells. Heterogeneous biohermal and platform carbonates ranging in age from Late Devonian (Famennian) to Early Permian (Artinskian) comprise the primary reservoir section. From Late Devonian to early Carboniferous, the Karachaganak massif evolved from a ramplike setting into an isolated, atoll-like carbonate platform along the northern margin of the Pre-Caspian Basin. The Carboniferous platform consists of marginal bioherm and bioherm slope facies, with a relatively small internal lagoon dominated by skeletal grain-dominated facies. Permian pinnaclelike bioherms and bioherm slope facies overlie an erosional unconformity at the top of the Carboniferous. The regional seal for the reservoir is formed by Lower Permian (Kungurian) sulfates and evaporites that immediately overlie the Artinskian carbonates. Limestone and dolomite reservoirs are generally low porosity and low permeability (6% porosity cutoff corresponds to 0.2 md permeability). Whereas dolomitization locally enhances reservoir quality, there is no apparent correlation between dolomite content and effective porosity. Initial reservoir quality is adversely affected by diagenetic processes, including early-marine calcite cementation and later anhydrite precipitation. For the three production objects, average core porosities range from 9.67% to 11.70%, and average core permeabilities range from 9.97 to 14.54 md.