A set of Petrophysical properties including porosities, absolute permeabilities, resistivity indices, elastic properties and Archie's cementation exponent "m" were determined for a number of carbonate core plugs representing four common reservoir rock types (RRTs) of the a Cretaceous Formation Abu Dhabi. The same core plugs were then used to estimate SCAL properties including water-oil relative permeabilities using digital rock physics (DRP). DRP is referred to in this paper as the combination of advanced 3D imaging techniques such as X-ray computed tomography (CT) scanning, and the use of the Lattice Boltzmann Method (LBM) for fluid flow modeling.The plugs were scanned, using X-ray Computed Tomography (CT), at several scales to establish the distribution of macro-and micro-porosity fractions of the carbonate samples, and identify the primary flow units. Comparison of direct measurement results with the LBM-based modeling was used as a validation of its practical ability to predict two-phase flow properties for carbonates for carbonates. Results of this study indicated that the LBM-based method achieved a good to reasonable prediction for several reservoir characterization properties such as residual fluid saturations. Some deviations were present and discussed. Finally, an up-scaling process for determining water-oil relative permeabilities for a carbonate sample exhibiting a bimodal porosity distribution was presented using one of the cores in the study as an example.
Haradh forms the southernmost part of the super giant Ghawar oil field located about 80 km (50 miles) onshore from the Arabian Gulf, in the Eastern Province, Kingdom of Saudi Arabia (Fig. 1). A major feature of the Ghawar field is its tilted Original Oil Water Contact (OOWC), getting shallower from North to South Ghawar at an average gradient of 0.36 m (1.2 ft) per km. In Haradh, the OOWC displays also a large but localized west-to-east component. Understanding the OOWC tilt mechanisms is vital since it will improve the effectiveness of the on-going Oil-Water Contact (OWC) delineation program. This will result in better placement of future producers and injectors, which in turn will reduce the cost of future developments. Statement of Theories and Definitions To date, two major concepts have been proposed to explain the tilted OOWC in Ghawar and more particularly in Haradh:One is that the OOWC tilt is caused by regional changes in reservoir fluid densities1.Another hypothesis is a dynamic flowing aquifer hitting the Ghawar field on Haradh west flank and pushing the OOWC to a shallower level along its south to north journey2. In summary, a static concept of the equilibrium is confronted to a dynamic one. The existence of pre-production pressure gradient in the field has to be verified to support a dynamic cause of the OOWC tilt. Integrating field temperature, salinity and pressure data as arguments, these hypotheses are critically discussed. During this process, a causal link to a major tectonic accident is proposed. Introduction Berg completed the surface mapping of the Haradh structure in 19403. Wildcat HRDH-1 struck oil in the Arab-D reservoir (Jurassic) in 1949. The first OOWC delineation wells were drilled during the seventies. Although 'Ain Dar and Shedgum (North Ghawar) areas are on stream since 1951, very limited production occurred in Haradh until 1996 when Haradh Increment-I (North Haradh) was put on stream to reach the required production plateau (Fig.2). Prior to that date, the OOWC was roughly defined by several delineation wells with a spacing of 16 miles. A fresh look at existing field data, recent advances in regional tectonics and simulation results all support a static origin of the OOWC tilt and confirm the conclusions of a previous work1. Description of the Haradh OOWC Haradh delineation wells showed that:The OOWC gets shallower from north to south to reach -6,420 ft at the Haradh tip;The west flank OOWC gets locally 800 ft shallower than that in the east (Fig. 3). Note that western and eastern aquifer legs are separated by almost 15 miles of a large anticline structure with a maximum 3°-dip angle. Drill Stem Test (DST) samples of Well-A (Well location on Fig.2) showed that the formation did not contain recoverable oil to the top, which established the Highest Known Water (HKW) at -5,863 ft in the west and confirmed the Formation Analysis Log (FAL) (Fig.3). FAL of Well-B (Well location on Fig.2) showed that the formation contained high oil saturation throughout the good quality zones, which established the Lowest Known Oil (LKO) at -6,625 ft in the east (Fig.3). Aquifer water on the Haradh west flank is anomalously fresh (30,000 ppm TDS at Well-A) and recent (6,000 to 20,000 year-old), compared to the more saline water sampled on the east flank (120,000 to 150,000 ppm TDS). Recent isotopic analysis in the Dhahran Research and Development Labs4 showed the meteoric origin of the aquifer water sampled on Haradh west flank. Note: The Jurassic Arab-D reservoir was deposited some 150 million years ago.
Recently observed production behavior in a maturing carbonate oil reservoir indicated that many production strings were getting plugged with solid scales, requiring tubing clean-out jobs. This is the main reservoir of a supergiant onshore carbonate oil field operated by ADCO since 1973. Some cases proved to be no more than calcium carbonate scaling following water breakthrough and the tubing blockage was successfully treated with acid washing. A number of plugged strings revealed that a non-mineral hard scale was the cause of the blockage. Upon analysis, such scales proved to have an organic composition rich in asphaltenes. While solvent washing was successful in removing the blockage, rapid reoccurrence was observed in many cases. The subsurface asset team embarked on a detailed reservoir monitoring and fluid compatibility study to establish causative factors. One of the aims of the study was to check a possible link between the asphaltenes deposition with a naturally occurring tarmat and a rich-gas injection pilot, both located in the severely affected part of the reservoir. This work revealed that although the severity of the problem is higher in the tarmat area, asphaltenes mobilization from the tarmat layer was not considered a realistic mechanism. Although PVT studies revealed that rich gas dissolution in the crude at reservoir conditions triggered asphaltenes instability and precipitation but occurrence of asphaltenes deposition in the field seemed unrelated to the rich-gas injection as the injected gas was moving in a different reservoir subzone. Most of the plugged strings were unlikely to have had gas breakthrough at the time of problem detection and no clear spatial relationship could be evidenced. A preferred explanation may be that asphaltenes precipitation is related to differences in crude oil composition within the studied reservoir. The reservoir might have seen successive oil influxes from two source rocks with wide distribution of mixing ratios. Asphaltenes originating from one of the source rocks might cause greater fluid instability even at the observed low concentrations. Production rate sensitivities indicated that asphaltenes blockage was retarded at higher production rates. Many asphaltenes dispersant/inhibitor chemicals were evaluated for effective tubing clean-out and preventing asphaltenes deposition. Some chemicals proved to be more effective in mitigation and prevention of asphaltenes deposition.
This paper was prepared for presentation at the 1999 SPE Middle East Oil Show held in Bahrain, 20-23 February 1999.
This paper reviewed the water injection strategy of a supergiant carbonate oil field operated by ADCO onshore Abu Dhabi since 1973. This field was subjected to peripheral waterflooding in order to maintain reservoir pressure and provide a mechanism to sweep the oil. In addition to traditional parameters in waterflooding such as for instance, reservoir heterogeneity, mobility ratio and depletion rate that control the waterfont shape, the presence of three oil-bearing reservoirs juxtaposed across strike-slip fault planes added a new variable to the complexity. Fault juxtaposition was interpreted to create limited pressure communication and fluid crossflow between reservoirs. The usual way of computing the voidage replacement ratio based on well production and injection rates was therefore insufficient to gain a complete understanding of the water injection strategy. Two different solutions of the voidage replacement ratio were computed using a full-field reservoir simulation model history-matched for both pressure and saturation changes. After accounting for all surface facilities constraints and under a certain set of assumptions, results of this model indicated that crossflow magnitude was minimized when certain pressure differences were maintained between these three reservoirs. Alternatively, there were some indications that higher crossflow could result in some additional oil recovery. A simple methodology to manage production and water injection targets on a quarterly basis while accounting for the communication between reservoirs was discussed. Finally implications for an on-going development were reviewed. SPE 116989summarized all fractures identified for this field (Figure 1c). At first look, the interpretation pointed to an apparent maximum horizontal compressive palaeo stress direction of N40W, not in line with any of the known maximum horizontal stress directions that affected this region (1) the older Paleozoic and Mesozoic E-W "Oman" stress regime, and (2) the more recent Cenozoic N-S "Zagros" stress regime. A similar conclusion was reached for another oil field in the same concession with a palaeo stress deemed to trend N60W (Gomes et al., 2006). Instead, the authors proposed a new interpretation in which the sinistral N40-50E fracture direction observed offshore Abu Dhabi (Marzouk and Sattar, 1994) and the dextral N110E fracture direction observed onshore Abu Dhabi are conjugate shearing faults with a maximum horizontal palaeo compressive stress oriented N70-80E and consistent in orientation with the E-W "Omani" stress regime (Figure 1d). It was the authors' view that in this field the "Zagros" stress regime re-activated this strike-slip system with a N110E dextral (opposite) slip. A possible explanation for the preferential development of N45E sinistral strike-slip faults in the north of the basin (offshore Abu Dhabi) and N110E dextral in the south of the basin (onshore Abu Dhabi) could reside in the existence of an independent tectonic block bounded to the north by the Trans-Arabian Gulf sinistral...
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