Untangle Shale and Gas Effects to Estimate Porosity and Net/Gross Ratio Using a Boomerang Workflow-A Case Study in Shoreface Reservoirs in Brunei

摘要

Tertiary shoreface-deltaic sediments in Brunei fields show different boomerang motifs on neutron-density and gamma ray-resistivity crossplots. A boomerang workflow, named after the motifs, is tested by calibrating to core data to quantify net/gross ratio and porosities under variable shale and hydrocarbon effects. The inflection between the two boomerang limbs marks the boundary between shoreface sandstones and offshore shale-type lithologies. Compared with subjective V_(sh) cutoffs, boomerang inflections are more objectively defendable signatures defining net and non-net rocks. Thin beds and heterolithic sandstones in lower shoreface and tidal environments are mixed in the sandstone limb near boomerang inflection. By including the thin beds and heterolithic reservoirs that are cut off by the V_(sh) approach, the static hydrocarbon in place in the studied fields increases by 10 to 40% based on the well data.The shale matrix effect on porosity estimation in shaly heterolithic sandstones is resolved by interactively derived shale-line slopes without involving the uncertain clay volumes or clay parameters. Particularly, effective porosity, Φ_(EF) is estimated by inputting a wet-shale-line slope, k_(sh) based on the shale limb on the neutron-density crossplot in each boomerang interval; it changes with depthas result of different compactions. Total porosity, Φ_(TOT) is estimated by a dry-shale-line slope; it is constant for most of the reservoirs based on core calibrations in the studied fields due to identical sediment provenance.Hydrocarbon effect is independent of shale matrix effect, although they are mixed in the log responses. Hydrocarbon effect is qualitatively analyzed based on the angular rotation of the hydrocarbon-bearing sandstone limbs towards different fluid points. It is also quantitatively evaluated by the apparent fluid neutron-density parameters (Φ_(ft) ρ_(ft)) interactively determined by coherent Φ_(EF) and Φ_(TOT) estimations in a dual-porosity and dual-fluid model. For example, the calculated Φ_(TOT) is significantly less than Φ_(EF) if water parameters are used for gas-charged sandstones. By decreasing the (Φ_(ft) ρ_(ft)) from water (1,1) until (Φ_(TOT)- Φ_(EF)) ≥> 0, we find the resultant Φ_(TOT) matches with core porosity (except in unresolved thin beds); this is tested in more than 1,000 meters of cores in several fields covering a large range of lithology and hydrocarbon types. If invasion is insignificant, the resultant fluid density, ρ_(ft) also matches with produced hydrocarbons. Therefore, the workflow not only provides coherent Φ_(EF) and Φ_(TOT) estimation in the rocks with variable shale and hydrocarbon effects but also the apparent fluid density profiles for hydrocarbon typing.