TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWater production in the North-east of Syria has increased significantly in recent years. As a result costs per barrel of oil have increased and the field's production is currently constrained by the facilities capacity.PLT surveys combined with a reservoir study showed that good-quality sands were not properly swept by the water, probably due to poor connectivity in the reservoir. It was anticipated that these un-swept sands could contribute to production if the watered out sands were shut-off.A newly developed gel-cement has been used to shut-off the watered out sands in a cost-effective manner. The gelcement system combines the properties of two shut-off techniques:Cement for mechanically strong perforation shut off. Gel for excellent matrix shut off. The gel, used as 'mix water' of the cement, will be squeezed into the matrix creating a shallow matrix shut off. The cement will remain in the perforation tunnel as a rigid seal. This system showed superior shut off performance in the laboratory compared to normal cement squeeze techniques. Selective perforation of the hydrocarbon zones will reestablish the oil production. The shut off zones can be reopened later in the well's life when artificial lift has been installed.In the first field trial 84 meters of perforations (gross) were squeezed of with the gel-cement in a single attempt. After reperforation of the top and the middle zone the well produced at a strongly reduced water cut, i.e. 25-33% compared to 60-62% before the treatment, and an increased oil production, i.e. 3000 bopd compared to 1000 bopd before the treatment. The oil production declined to 2000 bopd over a year. The water cut gradually increased over that period to 56%.

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Summary Water production in northeast Syria has increased significantly in recent years. As a result, costs per barrel of oil have increased and the field's production is currently constrained by the facilities capacity. Production logging tool (PLT) surveys, combined with a reservoir study, showed that good-quality sands were not properly swept by the water, probably because of poor connectivity in the reservoir. It was anticipated that these unswept sands could contribute to production if the watered-out sands were shut off. A newly developed gel/cement has been used to shut off the watered-out sands in a cost-effective manner. The gel/cement system combines the properties of two shutoff techniques:Cement for mechanically strong perforation shutoff.Gel for excellent matrix shutoff. The gel, used as "mix water" of the cement, will be squeezed into the matrix, creating a shallow matrix shutoff. The cement will remain in the perforation tunnel as a rigid seal. This system showed superior shutoff performance in the laboratory compared to normal cement squeeze techniques. Selective perforation of the hydrocarbon zones will re-establish the oil production. The shutoff zones can be reopened later in the well's life when artificial lift has been installed. The system was tested in the field in two wells. In the first field trial, 84 m of perforations (gross) was squeezed off with the gel/cement in a single attempt. After reperforation of the top and the middle zone, the well produced at a strongly reduced water cut (i.e., 25 to 33% compared with 60 to 62% before the treatment) and an increased oil production (i.e., 3,000 BOPD compared with 1,000 BOPD before the treatment). The oil production declined to 2,000 BOPD over a year; the water cut gradually increased over that period to 56%. In the second well, full shutoff was achieved but oil production could not be resumed for reasons that are not fully understood. Introduction Waterdrive, either natural or through water injection, is probably the most important recovery mechanism for oil production from oil-bearing rocks. In a layered reservoir, this will cause water breakthrough in the high-permeability layers, leaving oil behind in the unswept layers. Generally, oil production decreases with the maturity of an asset while the water production increases. For 1999, the worldwide daily water production associated with oil production has been reported as 33 million m3 or, roughly, 3 bbl of water for every barrel of oil (Bailey et al. 2000). The U.S. petroleum industry generates 2.4 billion m3 of water annually (Sustainable Development 2004). This amounts to an average 7 to 8 bbl of water per 1 bbl of oil. Water production within the one group has roughly increased from 350,000 m3/d in 1990 to more than 1,000,000 m3/d today (Khatib and Verbeek 2002). The costs associated with handling produced water are typically proportional to the amount of water produced. Consequently, costs per barrel of oil produced continue to increase with increasing water production. Ultimately, individual wells or complete fields are abandoned when cash flows turn negative because of excessive water production. The heterogeneous geologic nature of most oil reservoirs, however, provides opportunities to prevent or reduce excessive water production. In layered reservoirs with good vertical isolation between the layers, water production can be managed either by controlling the injection profile in the injectors (if water is injected) and/or by selectively producing different layers in the producers. It is essential that the well integrity and cement bond are good to prevent communication behind pipe and casing.

To store CO2 in depleted oil and gas fields or saline aquifers, a detailed site assessment is typically done manually, which is time-consuming and costly, as there are large number of older wells with poor quality records. The study presented here will leverage cloud computing and artificial intelligence (AI) tools like Optical Character Recognition (OCR) and Natural Language Processing (NLP) to automate the legacy well assessment for efficient decision-making in storage site selection, thus reducing human effort. Results from our preliminary tests show that with this approach one can extract 80% of the desired information from various data sources including hand-written well reports and analyze information to accelerate CO2 storage risk level estimation.

Development of remote offshore fields has unique technical challenges because quite often, such fields have only a few subsea wells tied to adjacent fields. This scenario is especially the case in small and/or marginal offshore fields where the profitability is very dependent on capital and operational expenditures. Therefore, quite often a group of marginal offshore fields located nearby are developed together with several gathering points and pipeline systems joining different subsea wells. Flow metering is usually performed at gathering points on the seabed using multiphase flowmeters rather than at individual wellheads. While this method can be very efficient from an economical point of view, it may, on the other hand, compromise the data acquisition process, resulting in an insufficient understanding of individual well performance. The situation may get even more complicated when wells from different fields are tied together. Because well interventions for individual well performance evaluations are generally expensive and not always possible, it is necessary to have a reliable and cost-effective permanent downhole monitoring system that provides continuous real-time data necessary for updating and improving the field development strategy. This paper presents a case study of a subsea oil producing well in the North Sea where one such system—a venturi downhole flowmeter—was installed to obtain continuous pressure and temperature measurements for downhole fluid density and flow rate calculations. This type of flowmeter is useful only in liquid environments because the underlying Bernoulli principle is applicable only for single-phase flow and tenable in low-slip liquid/liquid flow regimes, such as in the concurrent flow of oil and water at high velocities. Surface flow rate validation is always a good complement but not compulsory. The goal of this cost-effective monitoring method was to facilitate production (oil and water) allocation so as to simultaneously improve well performance and reservoir modeling. The continuous pressure and temperature data obtained from this downhole flowmeter were translated into valuable information during well flowing and shut-in periods. The application of specific workflows transformed the downhole data into fluid flow rates, which allowed to accurately evaluate performance of the well. Successful calculation validations were performed using a multiphase meter data due to the inability to test the well. The results allowed the operator to properly allocate flow, assess reservoir performance, and identify improvement opportunities in the field-development plan. This case study demonstrates that with the installation of reliable, cost-effective downhole flowmeters and the appropriate interpretation of downhole real-time data, well performance evaluation and reservoir management strategy can be improved simultaneously in subsea environments where the risks are high and expenditures are tight.