No abstract

No abstract

No abstract

The gas-condensates-oil reservoir of the Karachaganak Field, Pri-Caspian Basin, Kazakhstan, consists of carbonates forming a low angle ramp in the Tournaisian-Early Visean, an isolated carbonate bank in the Late Visean-Bashkirian and a high-rising isolated build-up in the Early Permian (Asselian-Artinskian). The reservoir, sealed by Kungurian-Ufimian-Kazanian evaporites, is overlain by three salt diapirs that make the reservoir seismic imaging challenging and the use of pre stack depth migration seismic mandatory for interpretation. Following the depth reprocessing of the seismic acquired in 1999, and as a consequence of the remarkably imaging improvements achieved, a revision of the Early Carboniferous reservoir stratigraphic architecture has been recently carried out. Its ultimate goal is to provide elements (internal stratigraphy, depositional facies and dolomite distributions) for the reservoir model updates, for the day by day drilling follow-up and for the future wells planning. The work integrated the definition of a 3D full field seismosequence stratigraphy framework with the analysis of the available wellbore data. The Carboniferous interval, bounded by the Devonian-Carboniferous PV2 unconformity at the bottom and by the Carboniferous-Permian C1a unconformity at the top, was identified as a high rank sequence and internally subdivided in six mid rank sequences (Early Tournaisian, Early Visean, Late Visean, Serpukhovian I, Serpukhovian II and Bashkirian) bounded by mid rank sequence boundaries (PV1b -Top Early Tournaisian, Top Bobrikovsky, C7 -Top Late Visean, ILS -Intra Late Serpukhovian and C1b -Top Serpukhovian), either recognized from well data only or identified on seismic and correlated to unconformities recognised on wells. Within this interval, the high rank transgressive section includes Tournaisian and Early Visean ramp carbonates delimited at the top by a regional marker of shale and cherty limestone that records the maximum sea level (C9 -Tula, high rank maximum flooding surface). The Late Visean and Serpukhovian high rank highstand section records the onset of biohermal deposits, and a phase of remarkable vertical growth, characterized by aggrading, prograding and downstepping internal geometries, well imaged by the reprocessed seismic depth cube. The Serpukhovian evolution has been mapped over the entire Field and the relevant seismic horizons (Top SERP AGG1, Top SERP AGG2, Top SERP PROG1, Top SERP PROG2, Top SERP PROG3 and Top SERP PROG4) have been interpreted, in terms of sequence stratigraphy, as the seismic response of low rank sequence boundaries marking the top of shallowing upwards cycles (recognized from logs and core facies interpretation). This was confirmed by the high resolution cross-well seismic profiles acquired along the northern margin of the carbonate bank. The stratigraphic architecture presented in this study provides elements to explain the reservoir behaviour, and particularly the effects of dolomitisation.

Karachaganak, an isolated carbonate platform, is a gas-condensate-oil field located in the Pri-Caspian Basin. Production, started in 1985, is now focused on liquid recovery. In 2003 gas injection was implemented. Despite the huge amount of geological data of different vintages, there is not yet a general consensus about the conceptual geological model. This fact is due to poor quality data and lack of reliable analogues. In particular the integration of geological data with 3D Seismic data, affected by the presence of salt-domes, is ambiguous. The main critical issue is represented by the presence of an enhanced permeability affecting about 15% of the reservoir. An adequate description of this event, at present randomly distributed in the reservoir models, would represent an effective tool to optimize both new wells location and further developments. The issue has been tackled in a pragmatic way cross-checking dynamic and geological data vs. several geological scenarios and thus testing their reliability. Using effective data-base tools, production and Well-Test data of 169 wells have been cross-checked with geological and petrophysical data at different scale of observations ranging between micro-permeameter measurements to Seismic Stratigraphic Units. Well-Test permeability, based on PLT’s contributions, was a key factor. This analysis has allowed the endorsement of a model resulting very effective in differentiating the reservoir into petrophysically homogeneous Depositional Regions. The distribution of enhanced permeability resulted linked to the geological evolution, and particularly to the bank internal geometry, consisting of an aggradational phase bioherm-dominated, and a progradation phase characterised by clinoform depositional bodies.