Heterogeneity in the pore network of carbonate rocks can be attributed to variable mineralogy, lithology, sedimentary facies, diagenesis, and fracturing. These factors determine porosities and permeabilities within carbonate platform deposits which control their reservoir properties. This study has investigated all these controlling factors over six different carbonate formations from Northwestern Iraq represented by Butmah Formation (Liassic), Mauddud Formation (Albian), Gir Bir Formation (Cenomanian), Wajnah Formation (Late Santonian), Mushorah Formation (Early Campanian), and Shiranish Formation (Late Campanian-Early Maastrichtian).
These investigations are applied with respect to various depositional positions within the carbonate platform, as well as diagenetic and fracturing history using a range of techniques across various scales from 10^2 to 10^-6 metres including analysis at macroscopic, mesoscopic and microscopic scales. The macroscopic scale analysis involved analysis of well log data and core description investigation, while the mesoscopic scale analysis includes a routine core plugs analysis (RCAL) and some special core plugs analysis (SCAL). The microscopic scale analysis involves thin section photomicrography and scanning electronic microscope techniques (SEM). These quantitative analyses are required to fuse geological information through multiscale integration.
Integrated multiscale analysis has enabled reservoir properties to be identified, together with their depositional factors, diagenetic history, and those characteristic controlling factors which play an effective role in improving or reducing the reservoir properties. According to the difference between lithology, the studied formations were divided into many lithofacies, and later on, the identified lithofacies were subdivided into microfacies according to the difference in their allochems and crystal size. These facies were deposited in various environments to show the differences in the heterogeneity of the carbonate platform.
Dolomitization, dissolution and fracturing were the most effective factors in improving reservoir quality of all of the studied formations, while cementation and compaction represented important negative factors that reduced the reservoir quality again in all of the studied formations. Fracture intensity was variable within the identified lithofacies of the studied formations, and cementation plays an important role, occluding most of them, especially in the Butmah and Mushorah Formations, while less effectively developed cementation was found in the Shiranish Formation.
Nine reservoir classes and nineteen petrophysical rock zones were identified in this study using a novel classification system, depending on the well log data and derived values iii of shale volume, porosity and matrix fraction of the studied formations. In this new classification, Classes 1, 4, and 7 are clean matrix reservoir rocks composed mainly of a matrix porosity system (e.g., intergranular, intercrystalline, moldic and vuggy porosity). The porosity of rocks in this class may be derived solely from the matrix. However, there also is an additional contribution to porosity by open fractures, forming a hybrid or dual porosity system. Classes 2, 5, and 8 are wacke matrix reservoir rocks. The porosity in these classes may be derived in part from the matrix, but it is the fracture porosity which dominates in creating a hybrid or dual porosity system while classes 3, 6, and 9 are shale rocks which exhibit a fracture-controlled porosity system. These reservoir classes were distributed within four defined petrofacies; A, and B as reservoir units, and C and D as non-reservoir units.
Integrated results of the identified petrofacies and reservoir classes help in understanding the fracturing control on the reservoir rocks which is used effectively in characterising the fractured reservoir type of the studied formation using Nelson classification. On the other hand, calibration between the SF indicator (the separation between the bulk porosity (ɸnd) and sonic (ɸs) porosity) and microscopic thin section study was applied to identify whether the SF indicator is due to fracturing or other positive diageneses such as dissolution and dolomitization.
The results of applying this technique show that the Shiranish, Mushorah and Gir Bir Formations host diffuse fractures only within tight or no matrix porosity. The reservoirs are suggested to be Type-I as the oil storage and flow paths are in the fractures without matrix contribution. The limestone lithofacies of the Butmah and Wajnah Formations show diffuse fractures and possible matrix properties. Therefore, the reservoir is characterised as Type-I or Type-II where the oil is mainly stored in the matrix, and its flow occurs through fractures. While the Mauddud Formation and the dolomite lithofacies of the Butmah and Wajnah Formations are suggested to be reservoir Type-II or Type-III, as the oil is in the matrix and its flow occurs both in the matrix and fractures.
A combined analysis of porosity, permeability, pore throat and the pore type data show that the studied carbonate rocks can
be classified into three rock types:
Type 1 consists of limestone with low porosity, a permeability less than 0.001 mD, a pore throat diameter range between 0.005 and 0.1 μm, and qualitative pore styles represented by some biomold and interparticles pores. This type of rock is identified in petrofacies C and D.
Type 2 is composed mainly of dolomite or fractured limestone with low to moderate porosity, a permeability range between 0.001 and 0.1 mD, a pore throat diameter range between 0.1 and 10 μm, and with a pore type which is characterized by a large variety
of pores including isolated and/or connected vugs, intercrystalline and microfractures pores. This type of rock is identified in petrofacies A and B.
Type 3 consists of fractured limestone and/or dolomite with low porosities, a high permeability range between 0.1 and 20 mD, a pore throat diameter range between 10 and 50 μm, and pore types which are mainly fractured networks that could contain some biomold and/or interparticles pores. This type of rock is identified as Petrofacies A.
Integrated study over three different scales provides the best way to interpret the complexity of the studied formations, where new definitions, classifications, and simulation techniques were applied to minimise the uncertainty in the carbonate reservoir characterisation and reservoir quality. This study shows that heterogeneity in carbonate rocks generally increases towards the shallowest environments (inner platform) assuming the fracturing effect and tectonic control are constant. Where deposits in the shallow environment are more susceptible to diagenesis than the deep environment (outer platform) and as a result, the pore system in the studied formations changed from hybrid diagenesis and fracturing in the Butmah Formation to fracturing pore system in the Shiranish Formation.
