The evolution of a fractured chalk reservoir: Machar Oilfield, UK North Sea

Abstract

Machar is the first of the ‘Diapir’ fields discovered in the eastern trough of the Central North Sea, in BP sole interest Block 23/26a. It comprises a fractured Cretaceous chalk and Paleocene sand reservoir overlying a steeply dipping salt structure. The oil column is greater than 1100 m and reserve estimates are in the region of 100 million barrels of oil equivalent.The history of the Machar reservoir represents a complex interplay of salt movement, oil migration and burial diagenesis. Structural studies have shown that the Permian Zechstein salt has been in a state of buoyant equilibrium for most of its geological history, with only one phase of true diapirism identified in the mid-Miocene. The buoyancy resulted in the deposition of a condensed (<300 m) Triassic–Eocene section over the salt high. In the surrounding area, sediment loading and related salt withdrawal caused ‘downbuilding’ and the deposition of a thick (3000 m) sediment package. A 50–300 m section of chalk was thus deposited over the diapir with a mature Jurassic oil source in the adjacent depocentre. Paleocene sands are thin or absent over the crest of the structure, but thicken to about 100 m downflank.Regional subsidence and oil migration commenced in the early Oligocene, the trap filling from the top down. Here, shallow burial depth (c. 100 m) and early oil emplacement ensured porosity was preserved in the chalk matrix. At the same time, on the flanks of the structure greater depth of burial and diagenesis were destroying chalk porosity from the bottom up. These competing influences resulted in a diagenetic front marking the limit of pay in the chalk. That front lies in the depth range 2000–2500 m.Passive movement of the chalk during periods of buoyancy, plus regional tectonic compression in the mid-Miocene, created a widespread fracture system. Studies have identified a continuous process of fracture, stylolite and cement formation across a variety of brittle and ductile deformation styles. Average spacing of open fractures in 200 m of chalk core from Well 23/26a-13 is 7.5 cm. About a third of these are open.The burial history, oil emplacement and fracturing resulted in a reservoir with a dual porosity system. The fine-grained pelagic chalk matrix has primary porosity in the range 12–35% with permeability generally less than 1 mD. Secondary fracture porosity, although difficult to measure, is probably less than 1%. Production test data over fractured intervals, however, show permeability in excess of 1000 mD. The fracture system is the key to developing the chalk reservoir as it provides effective drainage of the tight matrix. In a wider context the recognition of buoyancy, not piercement, as the dominant structural process provides a model for exploration elsewhere.