The BP operated Miller field arguably produces the most severe barium sulphate scaling waters in the world. There is an operational need to carry out scale squeeze operations almost continually in order to maintain the oil and gas production. In this paper, we will present the challenges overcome proposing and in applying a new downhole product in this challenging environment. The paper will describe the selection process and test protocols needed to identify suitable squeeze inhibitor chemistry and review the laboratory data generated for a specific chemistry. A pre-requisite in assuring the performance of a squeeze chemical on the Miller asset is the ability, for the supplier, to guarantee a 24 hour turn around time for residual inhibitor analysis. The conventional detection method for the type of chemistry selected is the hyamine test, which is time consuming and can be inaccurate. This paper will also include results from the Baker Petrolite High Performance Liquid Chromatography (HPLC) method for residual analysis, developed for detection of polymeric scale inhibitors in produced water. This method has the advantage of producing accurate results in a very short time frame. The paper will also review the actual deployment of this chemical in the field, and demonstrate how the implementation of the selected chemistry resulted in immediate annualized operational savings to BP of an estimated $2.9MM on a single well. The results of Squeeze V modeling are also reported, demonstrating how the squeeze applications are being optimized to bring even larger operational savings to BP by improving the squeeze lives on selected wells. Introduction The Miller field was discovered in 1982 in UKCS blocks 16/7b and 16/8b in the South Viking Graben. It is approximately 270 km Northeast of Aberdeen and the oil bearing structure is some 4000 meters beneath the seabed. The Miller reservoir is Upper Jurassic submarine fan sandstone with medium to fine grained quartz sandstones. The field is a low relief structure with the oil water contact at ~ 13418ft. The platform was installed in May 1992 with production commencing in 1992 at initial reservoir pressures of 6500 psia. Seawater injection is utilised on Miller in order to maintain reservoir pressure with 200,000 – 300,000 bpd seawater utilised through a number of injector wells. Oil production peaked at 150,000 barrels/day which was maintained until 1997. Sandstone is the major component of the Miller reservoir, it accounts for > 80% of the reservoir volume. Smaller elements of carbonate cementation and feldspar are also noted. Trace levels of mica and glauconite are also present and no significant levels of swelling clays are observed. In general, porosity's of 14 15% are found and permeability ranges from 200 millidarcy (mD) to > 1000 mD. Challenges Within the Miller field, seawater breakthrough from the injectors varies significantly. Wells with < 30% and > 60% seawater cut are felt to be comfortably under control for scale deposition. Wells that occur in the 30% 60% region (i.e. the worst case scenarios) are frequently treated with scale inhibitor squeeze treatments. A number of these wells are squeezed approximately every 7 days. This high frequency is due toHigh minimum inhibitory concentration (MIC) requirement for worst case seawater formation water ratioRapid release of adsorbed chemical such that return concentration rapidly falls below the MIC.

Real time reservoir monitoring is critical for the effective management of any reservoir. Permanently installed reservoir monitoring instrumentation is generally installed as standard practice in the majority of offshore wells and whilst the reliability of such systems has improved significantly over the last decade, there are still many examples of wells around the world where these systems have failed prematurely. The Mungo Platform, located in the UK Central North Sea, has several wells in which the permanently installed monitoring systems failed early on in the life of the wells. In the absence of any real time reservoir pressure / temperature data, a compromise solution has been to install long term memory gauges in the wells so that reservoir monitoring, all be it using historic data, has been possible. Being relatively compact in size and a Normally Unmanned Installation (NUI), well intervention operations on Mungo are logistically challenging, with limited deck space for rig up and with personnel having to shuttle from the Marnock platform located around 24km away. A newly emergent wireless reservoir monitoring technology that can be retrofitted into existing wells and can transmit data to surface in real time was viewed as an attractive alternative to performing regular well interventions to gather historic data using memory gauges. Whilst the wireless gauge technology has a growing track record in the subsea and onshore well environments, signal attenuation in the offshore platform environment presents particular challenges that had previously prevented the technology from being retrofitted into such wells. A concept was developed for offshore platform wells having failed permanent cabled gauge systems, whereby the cable and gauge infrastructure of the failed permanent gauge system should, under the right conditions, act a conduit for the wireless gauge signal to be transferred to surface. To test the theory, a proof of concept trial was performed in Mungo well W160. A wireless gauge system was retrofitted into the well using standard slickline equipment and real time reservoir pressure and temperature data was successfully transmitted to surface using the failed permanent gauge system as a signal pick-up. This world first successful retrofit application of a new wireless monitoring technology into an offshore platform well, marks a milestone achievement in enabling the restoration of real time reservoir data without having to perform a well workover. This technology breakthrough is of significance in many situations where cabled in-well monitoring systems have failed. Collecting real time data from well W160 provided several benefits; the well production could be optimised on a daily basis, pressure build-up analysis could be performed, a new well target location was determined and the reservoir panel water injection response was optimised. Introduction The BP operated Mungo Field is located at the edge of the Eastern Central Graben in the UK sector of the North Sea, about 240km east of Aberdeen and sits in around 90m of water. First discovered in May 1989 it was developed as part of the Eastern Trough Area Project (ETAP) and saw first production in 1998. (See Figure 1) Mungo is a large oilfield with a small natural gas cap. The productive Forties, Lista and Maureen formations, which are Palaeocene sandstones, ring a salt diapir. The field has been developed under combined water and gas injection on a NUI located above the field. The Mungo NUI is tied back to the central processing facility (CPF), which is located over the Marnock field. The CPF handles the fluids produced by Mungo and also serves as the accommodation base for personnel shuttling to the Mungo NUI.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe BP operated Miller field arguably produces the most severe barium sulphate scaling waters in the world. There is an operational need to carry out scale squeeze operations almost continually in order to maintain the oil and gas production. In this paper, we will present the challenges overcome proposing and in applying a new downhole product in this challenging environment.The paper will describe the selection process and test protocols needed to identify suitable squeeze inhibitor chemistry and review the laboratory data generated for a specific chemistry. A pre-requisite in assuring the performance of a squeeze chemical on the Miller asset is the ability, for the supplier, to guarantee a 24 hour turn around time for residual inhibitor analysis. The conventional detection method for the type of chemistry selected is the hyamine test, which is time consuming and can be inaccurate. This paper will also include results from the Baker Petrolite High Performance Liquid Chromatography (HPLC) method for residual analysis, developed for detection of polymeric scale inhibitors in produced water. This method has the advantage of producing accurate results in a very short time frame. The paper will also review the actual deployment of this chemical in the field, and demonstrate how the implementation of the selected chemistry resulted in immediate annualized operational savings to BP of an estimated $2.9MM on a single well. The results of Squeeze V modeling are also reported, demonstrating how the squeeze applications are being optimized to bring even larger operational savings to BP by improving the squeeze lives on selected wells.