Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
South Oman
Abstract The field X is a brown heavy oil field producing under strong bottom water drive since the mid-1980. Production is from a combination of Amin aeolian and Al Khlata glacial reservoir sediments. At present, the development is focused on drilling horizontal infill wells. One of the biggest challenges is the unfavorable mobility contrast between the heavy oil and water causing early water breakthrough. The Amin Formation, the primary reservoir, is characterized by a high net to gross ratio and an average porosity of 30 %. However the initial hydrocarbon saturation at the same porosity often varies by 20 % in different parts of the field. Furthermore, core measurements show an order of magnitude scatter in permeability at the same porosity, indicating the presence of different facies. In early studies these variations were attributed mainly to the grain size variations. A later petrographical study found that the abundance of clays and feldspars could also severely reduce permeability, but may retain high porosity. In the current Study it was found that the rocks have variable radioactivity due to the presence of radioactive Potassium isotope associated with feldspars. A fare correlation was observed between the grain size and the content of feldspars from core. A novel approach to reservoir characterization integrating core and logs was developed leading to a major breakthrough in the reservoir characterization including: Enhanced permeability prediction using normalized Gamma Ray (GR) log as 3rd parameter; Facies identification using normalized Gamma Ray cut-off; Facies based Saturation-Height models. This work is a good example of advances in reservoir characterization achieved by integrating core and log data. It results in better understanding of reservoir properties distribution, optimization of completions of new wells and improvement of further development scenarios. In particular, abnormally high gross production and high water cut in the north of the field is currently in line with new facies scheme.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral > Silicate > Tectosilicate > Feldspar (0.66)
- Asia > Middle East > Oman > South Oman > South Oman Salt Basin > Al Khlata Formation (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Nahr Umr Formation (0.94)
ABSTRACT: This paper shows how better water saturation estimates are obtained for thinly-bedded shaly reservoirs using the Thomas-Stieber approach, 3D resistivity data and a modified Normalised Qv equation. Our contribution is a modification of the Normalised Qv approach of Juhasz, so that additional conductivity is related to the dispersed shale fraction. In the modified approach, the Relative Porosity Difference (RPD) and apparent water conductivity are used to derive the Juhasz parameters BC (for conductivity) and Rw. Using the results of the Thomas-Stieber model, the derivation of RPD is optimised so that it represents the shaliness of the net sand and not of the gross interval. INTRODUCTION Thinly-bedded reservoirs are laminated sand/shale sequences that have bed thicknesses below the log resolution of conventional logs. Consequently, logging tools measure ‘net-sand’ and ‘non-net shale’ simultaneously and the averaged response is not directly representative of the net-sand. In the case of conductive clay minerals and shales, pay could be missed; this is often referred to as Low Resistivity-Low Contrast (LRLC) pay. Thin beds and LRLC pay require a special approach, different from the conventional workflow. The combination of Thomas-Stieber and 3D resistivity logging to calculate the true petrophysical properties of the sand is well known, and published. Previous work, which still forms the basis for this study, is discussed below. The suggested modification to the workflow will then be explained. The problem of defining Net-to-Gross (NTG) and obtaining the true sand properties was considered by Thomas & Stieber (1975). These authors proposed an interpretation method based on endpoints for clean sand and pure shale to obtain the volume of laminated sand, volume of dispersed ‘shale’ and true porosity of the sand fraction. Initially, the shale volume was related linearly to gamma ray.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)