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Matrix-acid stimulation is a key production enhancement technique for carbonate reservoirs. The ability to control acid placement by diversion along the reservoir section is often challenging, particularly for heterogeneous formations where low-permeability intervals may remain under-stimulated. In this paper, we demonstrate via subsequent inflow profiling that efficient stimulation of both low- and high-permeability segments can be achieved using a completion method called a Smart Liner and a new methodology of downhole flow monitoring without operational well intervention by utilizing inline tracer system across the lower completion.The Smart Liner is a completion technique, which relies on a number of small and unevenly spaced holes to divert acid along a horizontal drain, while incorporating swellable packers to isolate segments with different reservoir properties. The hole spacing design is unique for each well and requires a software algorithm to balance the outflow. The inflow monitoring is assessed through both inline chemical tracers and conventional PLT. Main components of this algorithm has been presented in an earlier publication.The inline tracer system can provide "wireless" continuous production profiling without the risk & cost associated with conventional PLT methods. The inline tracer samples were collected during both stages of pre-stimulation and post-stimulation activities on oil producer wells, which shows downhole contribution of all segments, acid arrival and enhancement of Mid section of the reservoir drain. Moreover, PLT was conducted to validate inline tracer results.Past deployments of Smart Liners have targeted homogeneous reservoir intervals, but in this paper, we show that also reservoirs with significant permeability variation can be effectively matrix-acid stimulated. It is to our knowledge the first time that inflow profiling of a long horizontal well has been probed with inline tracers as well as PLT. Furthermore, we quantify the incremental impact of a given acid volume on injectivity based on the high-frequency data from the stimulation job.

This study demonstrates first time in Abu Dhabi the capacity of combined 3D tar and petroleum systems modelling, in an operating oil field offshore Abu Dhabi, indicating locally the tar presence in the Arab formation. It is intended to give insights on the most likely process of tar formation and allows to a certain extent a prediction of tar presence away from well control. The tar modelling is calibrated through core observations on vertical wells, which define the thickness of the initially assumed constant and homogeneous tar mat. An extensive data set using adapted geochemistry, petrographic analyses, fluid inclusion analyses and inclusion PVTX-modelling is used to analyse the charge history of the oil field and its tar in detail. The analysed tar occludes the pore space in the reservoirs of the lower Arab Formation in the oilfield offshore Abu Dhabi. The petrographic analyses indicate the presence of tar particles even up to the upper Arab. Geochemistry and petrography show that there are two different tar types. The classical reservoir filling black tar in the upper most part of the Lower Arab is identified as APE (asphaltene precursor entity after Wilhelms & Larter, 1994) tar which is caused by a flocculation process at a certain temperature and pressure regime in the reservoir. This concept has been successful modelled and can even explain the observed fine tar particles up to the upper most Arab. The second type of initially called "tar" is analysed and observed in the top Diyab and lowest part of the Arab, in a micritic limestone facies environment. Previous concepts struggled to justify the black tar deposition in the dense micritic carbonate mudstones. The initial porosity in this micritic mudstones was already very low and therefore a tar flocculation process or gravity segregation in such an environment urges for other explanations. Our analyses indicate that the micritic mudstone acts as a source rock at the top of Diyab and the lower most Arab subunit, where the early heavy oil and asphaltenes (POA=pre-oil asphaltenes) did not leave the rock and stayed in-situ as bitumen/black tar. This has been modelled with a tar specific kinetics, differentiating in an early heavy oil component (POA), that is generated in-situ and an asphaltene component (APE) expelled within the oil and transported into the reservoir. Acceptable tar modelling result have been reached by reconstructing the charge history of the field. It shows that Diyab oil entered the lower Arab reservoir at approx. 105/95 Ma. The tar modelling through time shows that first tar deposited at 78 Ma (+/- 5 Ma) in the southern part of the oil field. The charge modelling indicates the lower Arab seal failure at approx. 58/53 Ma in the past. The shallower reservoir units of the lower and middle Arab up to the upper Arab are subsequently filled with asphaltene rich oil. Then at 48 Ma the asphaltenes reach a flocculation peak. Finally at 47/34 Ma the whole oil field with the already flocculated tar (APE in the reservoir) and the asphaltenes in the source rock (POA) received a paleo heat shock of at least 140°C, which transformed the tar into pyrobitumen and caused the today surprisingly high API (around 40°API) in the oil field by oil-to-gas cracking.

Periodical PBU/PFO surveys have been conducted for monitoring horizontal wells and reservoir pressure maintenance in five-spot water flooding patterns in a giant carbonate reservoir located offshore Abu Dhabi. Although, in the literature, several methods have been proposed to estimate average pressure over a drainage area, none of such methods is applicable to the situation above where a flood pattern is confined with constant pressure boundaries. In this study, we propose a new method of average pressure estimation for a horizontal well in a drainage area associated with constant pressure boundaries. This new method was developed by creating a type curve representing a pressure correction against P* or an extended pressure as if an infinite reservoir existed. Although this method may look similar to the classical MBH theory, we can substantially differentiate the new method from the MBH method since the new method can handle both a horizontal well and a constant pressure boundary while the MBH method assumes a vertical well and a no-flow boundary alone. New pressure correction type curves were generated through intensive numerical simulations modeling a horizontal well in a square and rectangular drainage with a constant pressure boundary condition. The shape factors under a steady state condition were defined and calculated to characterize and differentiate the shape of individual type curves.