Structural and stratigraphic configuration of the late Miocene Stage IVC reservoirs in the St. Joseph field, offshore Sabah, NW Borneo

702001-101379-1189-B
Author : Johnson, H.D., Chapman, J.W. & Ranggon, J.
Publication : Bulletin of the Geological Society of Malaysia
Page : 79 – 118
Volume Number : 25
DOI : https://doi.org/10.7186/bgsm25198906

Bulletin of the Geological Society of Malaysia, Volume 25, Dec.1989, pp. 79 – 118

 

Structural and stratigraphic conflguration of the late Miocene Stage IVC reservoirs in the St. Joseph field, offshore Sabah, NW Borneo

H.D. JOHNSON, J.W. CHAPMAN & J. RANGGON

Sabah Shell Petroleum Company, Lutong, 98009 Miri; Sarawak, Malaysia

 

Abstract: The St. Joseph field is a large, structurally and stratigraphically complex oil field situated offshore West Sabah. The paper describes the main geological characteristics of the field, highlighting the benefit of 3D seismic and core/well log data in developing a comprehensive three-dimensional geological model, which is being used to guide field development.

Structurally the field is situated along a major Lower Pliocene wrench fault zone (Bunbury-St. Joseph ridge) and comprises three distinctive areas:

(1) NW Flank is a structurally simple area, dipping uniformly (at ca. 20°) to the NW, which contains the majority of recoverable oil reserves (ca. 95%).

(2) Crestal Area is a structurally complex zone characterised by intense faulting, steeply dipping beds and incomplete stratigraphic sequences. Minor oil reserves are present which were discovered by the first exploration well (SJ-1) in 1975.

(3) SE Flank is an area of moderate structural complexity with negligible oil reserves.

3D seismic data has significantly increased the quality of the structural definition of the field as a result of: (1) ability to map individual intra-Stage IVC reservoir intervals,

(2) better fault definition, particularly in the structuraly complex areas, and (3) identification of stratigraphic features, such as slump scars. Practical benefits include improved  definition of the boundary between the NW Flank and Crestal Area, better delineation of the NE extent of the field (by faulting/slump scars) and improved location of development wells and drilling jackets.

Stratigraphically the main NW Flank reservoir (Upper Sand Unit) comprises a complex sequence of shallow marine sandstones and shales (late Miocene, Stage IVC), which display marked lateral variations in sand development, reservoir quality and shale layer thickness/continuity. Sedimentological studies of ca. 1600 ft of core (including 800 ft of continuous core from well SJ-7) and palaeontological data indicate deposition in a storm/wave-influenced shallow marine (neritic) environment. The main reservoir units comprise several stacked coarsening/fining upward sequences reflecting repeated progradation and transgression of coastal/delta front sand bodies. This subdivides the Upper Sand Unit into thirteen distinctive sub-units, which can be correlated field-wide.

Log calibration of the four main facies types and correlation of the genetic sequences have enabled construction of a three-dimensional reservoir geological model of the Upper Sand Unit. This thick (700 - 900 ftI27 - 43 m), heterogeneous sequence is effectively a single, connected reservoir but with predictable lateral variations in sand and shale distribution:

(1) reservoir sands are best developed in updip areas and in the southern part of the NW Flank.

(2) reservoir quality deteriorates downdip (to NW) and alongstrike (to NE) in response to an increasingly moredistal depositional setting.

(3) shale layer frequency and continuity is also higher in these distal areas compared to the more proximal areas (to SE and SW).

(4) shale layers are mainly discontinuous (except the field-wide 1.1 shale); RFT pressures indicate that in the NE they form pressure baffles whereas in the SW the reservoirs are fully connected.

The structural and stratigraphic interpretations presented herein provide a comprehensive three dimensional model of the St. Joseph field. The results have been incorporated into a full-field simulation model to optimize the fields ongoing development planning and reservoir management.

 https://doi.org/10.7186/bgsm25198906