In the context of global warming, CO2 capture is one of the explored solutions for greenhouse gas emission mitigation. Its injection in oil fields is one of the EOR schemes adapted to the Middle East carbonate reservoirs. A very high ultimate oil recovery is expected with such a process. A proper design to develop full field EOR CO2 is yet to be found and may be fulfilled through the implementation of one or several pilots. This study of EOR CO2 pilot implementation required a geosciences, reservoir and surface integrated work in order to place it in some robust and promising locations. A static and dynamic synthesis was performed to understand and better capture the structural context of the field and its level of production maturity. The major risks were taken into account for the selection thanks to a complete synthesis of the available data from the core scale to the surface facilities. An adequate methodology was developed to narrow down the possible locations from the field extent (several hundred km2) to only a few squared kilometers of interest. The field was divided in 6 km2 squares (called "locators") for which a two step selection process was applied. In the first step, the geological typology of the reservoirs and their dynamic statuses at the locator level were defined. Then the risks associated to CO2 injection were assessed. At the end of this step, the selected locators were the less risky ones, representating each geological typology. In the second step, the locators were studied more thoroughly with the evaluation of the level of knowledge illustrating the amount and quality of data available; a geological variability study on permeability was also performed on each area. Finally the surface constraints were incorporated to prevent any incompatibilities with the current or future facilities. This second step provided another sub-selection of locators amongst the ones kept at the end of step 1. Overall, the methodology applied allowed to screen the whole field and its reservoirs, and to identify some promising pilot locations representative of the geology, for a given dynamic status, combining high level of knowledge and low risks related to CO2 injection.
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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Coiled Tubing Drilling (CTD) has been growing and developed rapidly through the last two decades. There have been numerous highly successful applications of CTD technology in Alaska, Canada, Oman and the United Arab Emirates (Sharjah Sajaa and Dubai Murgham fields), among other places. Currently, Saudi Arabia has undertaken a campaign for the last seven years that has shown successful results in gas reservoirs. ADNOC initiated a trial Coiled Tubing Underbalanced Drilling (CTUBD) project in the onshore tight gas reservoirs in Abu Dhabi, United Arab Emirates beginning operations 1-December-2019. The initial trial will consist of three (3) wells. The purpose of the trial is to assess the suitability of CTUBD for drilling the reservoir sections of wells in these fields, and further application in others. The reason for choosing coiled tubing for drilling the reservoir sections is based upon the high H2S content of the reservoir fluids and the premise that HSE can be enhanced by using a closed drilling system rather than an open conventional system. The three wells will be newly drilled, cased and cemented down to top reservoir by a conventional rig. The rig will run the completion and Christmas tree before moving off and allowing the coiled tubing rig to move onto the well. The coiled tubing BOPs will be rigged up on top of the Christmas tree and a drilling BHA will be deployed through the completion to drill the reservoir lateral. The wells will be drilled underbalanced to aid reservoir performance and to allow hole cleaning with returns being taken up the coiled tubing / tubing annulus. The returns will be routed to a closed separation system with produced gas and condensate being primarily exported to the field plant via the production line, solids sparge to a closed tank or pit and the drilling fluid re-circulated. The primary drilling fluid will be treated water; however, nitrogen may be required for drilling future wells in the field and will be required regardless for purging gas from the surface equipment during operations. A flare will also be required for emergency use and for start-up of drilling. If the trial proves a success, a continuous drilling plan will be put in place.
Coiled Tubing Drilling (CTD) has been growing and developed rapidly through the last two decades. There have been numerous highly successful applications of CTD technology in Alaska, Canada, Oman and the United Arab Emirates (Sharjah Sajaa and Dubai Murgham fields), among other places. Currently, Saudi Arabia has undertaken a campaign for the last seven years that has shown successful results in gas reservoirs. ADNOC initiated a trial Coiled Tubing Underbalanced Drilling (CTUBD) project in the onshore tight gas reservoirs in Abu Dhabi, United Arab Emirates beginning operations 1-December-2019. The initial trial will consist of three (3) wells. The purpose of the trial is to assess the suitability of CTUBD for drilling the reservoir sections of wells in these fields, and further application in others. The reason for choosing coiled tubing for drilling the reservoir sections is based upon the high H2S content of the reservoir fluids and the premise that HSE can be enhanced by using a closed drilling system rather than an open conventional system. The three wells will be newly drilled, cased and cemented down to top reservoir by a conventional rig. The rig will run the completion and Christmas tree before moving off and allowing the coiled tubing rig to move onto the well. The coiled tubing BOPs will be rigged up on top of the Christmas tree and a drilling BHA will be deployed through the completion to drill the reservoir lateral. The wells will be drilled underbalanced to aid reservoir performance and to allow hole cleaning with returns being taken up the coiled tubing / tubing annulus. The returns will be routed to a closed separation system with produced gas and condensate being primarily exported to the field plant via the production line, solids sparge to a closed tank or pit and the drilling fluid re-circulated. The primary drilling fluid will be treated water; however, nitrogen may be required for drilling future wells in the field and will be required regardless for purging gas from the surface equipment during operations. A flare will also be required for emergency use and for start-up of drilling. If the trial proves a success, a continuous drilling plan will be put in place.
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