A concise review of the standard treatment technologies used to achieve compliance with the Stage 2 Disinfectants/Disinfection Byproducts Rule (D/DBPR), along with their respective advantages and disadvantages, is presented in this article. Capital and operating cost estimates for D/DBPR compliance, first released in 2005 by the U.S. Environmental Protection Agency, are updated. As many utilities have found, switching to a disinfectant other than chlorine may be effective in limiting regulated disinfection byproducts, but it can also create new DBPs whose effects are not well known or understood. Treatment technologies that remove the source of the byproducts, although more expensive, may prove to be the better alternative ‐ especially when the additional contaminant removal often required in addition to the reduction of DBPs is factored into the equation. By implementing organic matter removal technologies, a water utility can best achieve Stage 2 D/DBPR compliance without creating additional problems in the treated water and will likely achieve additional benefits in terms of improved water quality. This article can help utilities prepare for technology selection as well as future treatment needs and budgeting of expenses.

A large majority of the wells in deep-water/subsea environments are being drilled as horizontal wells to gain cost-effective accessibility to multiple sand bodies and larger reserves. Most of these wells are being completed as open holes because of the higher productivities as well as lower costs associated with such completions. Furthermore, a substantial fraction of the fields in deep-water environments requires some sort of sand control. Although standalone screen completions have been used successfully in some of these deep-water fields (relatively large sand grains and uniform particle size distributions, with little to no fines), premature sanding problems have been reported, jeopardising project economics as a result of prohibitively high cost of remediation. In this paper, we present a significant case history on the application of the simultaneous gravel-packing and cake-cleanup technique in the Foinaven field, West of Shetland, UKCS. The well is the first gravel-pack completion in this deep-water, harsh environment, where various types of standalone screen completions have been utilised since the initial development of the field in 1994. The subject well is of 3,075-ft open hole, penetrating through two sand bodies separated by a 530-ft shale section. It is the first openhole gravel-pack completion in such an environment in the North Sea to result in 100% packing efficiency based on gauge hole calculations and a zero mechanical skin based on pressure build-up testing. In addition to being the first horizontal well West of Shetland to be drilled with water-based mud (WBM), this was the first production well to be drilled in a new reservoir horizon of the field, discovered and brought on line in less than 10 months. Initial production from the well far exceeded expectations and the completion was delivered safely and 3 days ahead of the target time. Introduction It is widely recognized in the industry that properly selected reservoir drilling fluids along with properly designed filter-cake removal treatments are essential to achieve high-productivity wells with low skin, particularly in gravel-packed completions where the filtercake is trapped between the gravel-pack and formation. Engineering the filtercake cleanup to be incorporated into the gravel-pack carrier fluid provides a cost-effective and uniform filtercake removal along long horizontal openholes, eliminating remedial treatments. However, this approach requires significant integration of different disciplines of well construction and completion. Previous publications have elaborated on reservoir drilling fluid selection for optimisation of the cleanup process, and the integration of custom engineered solutions.1,2 Based on friction pressures derived during yard testing, shunt tube technology for openhole gravel packs can successfully pack long openhole sections in excess of 5,000 ft pumping at low rates (e.g., 2.5 bbl/min). At these rates there is a requirement for the carrier fluid to exhibit superior rheological properties to avoid the gravel from settling out when pumping down a large-diameter workstring. In the severe conditions West of Shetland, this was a significant extension to the technology's proven limits in a harsh deep-water subsea environment. Critical to the success of any shunt-tube gravel-packing operation is the rheology of the carrier fluid; it must meet the minimum requirement for slurry transportation in the shunt tubes.

Water Injection completion selection in a deepwater subsea environment requiring sand control is currently an inexact science with lack of a proven track record for life of field solutions. The West of Shetlands (WoS) fields Foinaven, Schiehallion and Loyal have been on injection since 1997 and are starting to develop a substantial track record of injection performance. This case study will provide a performance comparison of the 2 main completion types installed to date, namely Cased and Perforated (C&P) and standalone Wire Wrap Screens (WWS), along with a subset of a three zone Smart well completed with premium sand screens. The comparison focuses on 4 main areas;Well LongevityCompletion Efficiency (skin)Injection Conformance (Near Wellbore)Performance of single and multi-zone injectors The WWS screen performance is further subdivided by clean-up technique of which there are currently five;Backflow Oil Based Mud (OBM)Bullhead Oil Based MudBullhead Water Based Mud after spotting BreakerToe Fracture using External Casing PackerDisplace OBM to Solids Free OBM and bullhead A variety of data will be presented as part of the comparison including, PLT Data, MDT Data, PFO Results, Hall Plots, UCS Data. A simple set of criteria is presented to select when C&P or sand screens are viable completion solutions. Introduction Water Injection (WI) completions in a sand control environment have recently gained a higher profile within the West of Shetlands, in particular, and the industry in general. No clear concensus would appear to have been reached as to what the optimum completion design should be and a variety of completions have been installed throughout the industry. Areas causing particular concern are well longevity and near wellbore injection conformance, both of which are directly linked to producer performance and maximizing reserves recovery. This study presents the range of injection completions that have been installed in the 29 injection wells drilled to date in the WoS fields. Areas that will be examined are completion design parameters and how they are derived, completion selection, impact of drilling fluid conditioning, formation damage, well clean-up and completion performance in terms of completion efficiency, injection conformance and life of well. Background to WoS Fields and Area The Foinaven, Schiehallion and Loyal fields are located in blocks 204/19 and 204/24a (Foinaven) and 204/20, 204/25a, 204/25b, 205/16 and 205/21b (Schiehallion and Loyal) which lie approximately 190kms West of Shetlands, in water depths ranging from 350 – 510m.

The BP Operated Rhum Field is a North Sea High Pressure High Temperature lean gas field. A key design requirement for successful development well planning and execution was to evaluate Overbalance and Dynamic Underbalance perforating techniques for their potential to optimise productivity while reducing the risk of producing hydrocarbons to surface during downhole operations.In this paper we present a case history focussing on the evaluation of the available perforation techniques with the aim of matching or exceeding the flow performance achieved on the Appraisal Well DST. The selection of drill pipe conveyed dynamic underbalance perforation, using the Schlumberger PURE technique provided the best compromise in terms of minimising HSE exposure and maximising productivity, with the main potential downside being the potential for large cost over-runs from utilising Caesium Formate brine. The re-completion of a Rhum appraisal well provided a rare opportunity to obtain a direct comparison of well productivity from standard Underbalanced and Dynamic Underbalanced perforating operations in the same reservoir interval.Operational issues forced the Rhum team to utilise a third perforation technique, on-balance perforation via electric line, and the paper will present the productivity achieved using this technique also. The paper progresses sequentially through the following items; -An overview of the Rhum Field and Reservoir; -Design and Planning of the perforation techniques utilised on Rhum Development wells to overcome challenges such as Hard Rock Perforating and Sand Control requirements; -The detailed design and core flood testing of two different types of Caesium Formate Kill Pills, aimed at identifying the least-damaging formulation.Operational data is presented to demonstrate the success of dynamic underbalance in maintaining a full fluid column, effective gas suppression in clear brine and tight fluid loss control. Field production and pressure data showing the filter cake clean-up over time is examined to evaluate the actual performance of the chosen kill pill after extended exposure at downhole temperature.The paper concludes with a comparison of the flow performance achieved on a single well in an identical reservoir interval when shot with ; a) standard underbalance during the original appraisal DST operation and b) dynamic underbalance for the development completion operation (original perforations cemented off). These results are compared with the flow performance of a second well shot on-balance using electric line.

Sand control, particularly gravel packing, is a common practice in the Mediterranean Sea due to the presence of poorly consolidated sandstone reservoirs. Open Hole Gravel Packs (OHGP) in highly deviated wells present an additional challenge due to the risk of sand bridging during the alpha wave propagation. The risk of bridging is escalated further in low fracture gradient environments where the pumping rate is reduced to avoid inducing losses. A major operator in Egypt has performed the first highly deviated OHGP jobs in the Mediterranean using Alternate Path screens. A series of qualification work was performed by the service provider during the planning phase for the 2 wells. Planning work included fluid rheology tests, flow loop testing, modeling full scale tests to achieve desired accuracy with gravel transport equations, pretreatment numerical simulations and post-treatment comparison of simulated data to actual data. Moreover, a lightweight proppant (LWP) product was qualified and successfully pumped on the second well where the fracture gradient was particularly low due to reservoir depletion. This paper discusses the planning, execution and post-job review work that was performed for these wells to produce two successful sand control jobs. Recommendations and lessons learnt for the future wells are also included. With the Industry and specifically the Mediterranean Basin moving towards more challenging wells requiring sand control in ever higher deviations and significantly depleted sands these highly deviated gravel packs with high overbalances are becoming increasingly important to unlock resources and maintain field plateau. The paper will detail the simulated results based on flow loop testing and how they compare with the actual job data. Successful sand control integrity was achieved with amount of gravel pumped exceeding 100% of the theoretical volume and sand free production achieved on both wells. Individual well performance with estimated skin values will also be shared.