fax 01-972-952-9435. AbstractHorizontal wells have become very common in the Middle East because of their capability to increase reservoir contact, particularly in carbonate reservoirs. These types of formations often are naturally fractured, and because of channeling from underlying aquifers, allow the ingress of water into the production process systems. When water breaks through to the well completion, it tends to increase and becomes preferentially produced, thereby reducing the volume of produced hydrocarbons. This phenomenon adds cost to the well operation because of the requirement to lift, separate, treat and dispose of the water. Preventing and managing water-cut through cementing, chemical application or the use of mechanical openhole barriers such as inflatable packers is costly, and often, the method chosen is not effective. This paper will discuss the use of swellable packers to provide a long-term, completely effective, water shutoff tool. These packers use expanding rubber around the packer that expands to seal the annulus. When expanded, a permanent seal is created, regardless of whether the packer has been run as a straddle or as a plug. The packers can be used in open and cased-hole applications in all the most common oil-and gas-well environments.This paper discusses the development and design of the packer and presents case histories from the Middle East and other parts of the world that illustrate the advantages that swellable packer technology can provide to operators in reservoirs in which water break-through has been predicted or experienced.In these case histories, it will be shown that the packers significantly reduced water cut, which in turn, reduced water disposal costs and intervention needs while increasing production rates and extending field life.

Inflow Control Devices (ICD) optimize production, delay water influx, eliminate / minimize annular flow, and ensure a uniform inflow along the horizontal wellbore at the cost of a small pressure drop. ICDs have brought promises to the industry’s efforts in horizontal wells inflow profile optimization which contributes to the economic success of horizontal wells. Although the structure of different types of ICD varies from one design to another, the principle is the same - restrict flow, and therefore balance or equalize wellbore pressure drop to achieve an evenly distributed flow profile. In general ICD’s are not adjustable once installed in the well. The location of the device and the relationship between rate and pressure drop are fixed. This makes the design of a well completion and inflow control devices critical for production. Having knowledge of the pressure profile of a horizontal well, the ICD completion can be designed to achieve the required uniform influx. Therefore, the need for pressure profile prediction along horizontal wells’ inflow area is obvious. Reservoir conditions are dynamic during the wells’ life cycle; hence the impact of ICD varies over time. Results to date within one of the onshore fields located in Abu Dhabi showed remarkable improvement in well performance, where gains in oil production with controlled water production have been achieved. Long-term reservoir simulation results also showed considerable recovery increase with ICD’s compared to the open-hole case. The paper provides an integrated analysis method of dynamic inflow and outflow to generate the flow profile of a horizontal well. The additional frictional pressure drop created by inflow control devices is considered. Two conditions that result in production challenges, wellbore pressure drop and breakthrough of undesirable fluids are addressed. The focus will be on when and how water encroachment will hit the horizontal well bore and how inflow control devices will act to optimize production. A simulated example at field conditions will be used to illustrate that it is critical to understand the reservoir conditions and wellbore dynamics together when designing a completion with inflow control devices. Uncertainties in reservoir conditions are considered, and a business case for a passive shut-off ICD is discussed through cumulative oil gain predicted by simulation of different development options and completion design strategy. This paper presents the evaluation and results of ICD technology, and how it is expected to become a game changer in this field development.

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Carbonate coiled tubing (CT) reservoir stimulation approaches vary, using acid systems and different diverters in order to try to achieve the best results. However, because it was not previously possible to know where the injected fluids actually go in the formation during a stimulation job, even with the enhancement of the coiled tubing placement and software model prediction, the results were often not effective as they could be. The inclusion of a fiber optic distributed temperature monitoring system (DTS) in the coiled tubing enables visualization of different zones injectivity by monitoring the exothermal effect of the acid reaction with the carbonate in highest permeability zones and hence acid and diverter placement can be optimized for improved stimulation efficiency. In one of Abu Dhabi Onshore fields a production log (PLT) was run in a water injector well that was completed in two different reservoirs, to provide a baseline injection profile. The acid stimulation job was then performed using fiber optic temperature monitoring through the coiled tubing, to optimize fluid placement. One feature of the data acquired by the fiber optic distributed temperature system was that the initial baseline temperature log was able to identify the high permeability injection interval from its "warm-back" response and this was correlated with the PLT interpretation. Consequently the treatment volume was optimized using the DTS results. Another DTS run was recorded after the acid stimulation with diverter using the injection velocity approach. This consists of bull-heading water down the coil tubing annulus and tracking the hot water generated at the heel of the well from the previous shut-in as it moves across the reservoir. The velocity interpretation of the injection profile confirmed that there was minimal injection into the high permeability interval at that point of time. The stimulation resulted in a well injectivity increase of 20% indicating successful placement and diversion of acid compared to conventional stimulation practices. The use of DTS will enable stimulating wells without the need for pre-job production log (PLT) and especially wells where a PLT is not possible either due to low flow-rates (below critical flow) or operational constrains (completion restriction). This paper details this "first-time" experience of a coiled tubing stimulation combined with DTS measurement and injection velocity profile in the UAE. It also concludes with a list of lessons learnt and recommendations for similar future approaches.