This paper brings the discussion on brine mixing initiated at the 1999 SPE Symposium on Oilfield Scale full circle, and suggests that different scaling regimes may exist in any given reservoir that should impact the scale management strategy. The initial paper by White et al. (1999) identified lower than expected barium levels in many wells in the Alba field, and raised the question of where scale deposition is occurring. A follow-up paper at the same meeting the following year by Mackay and Sorbie (2000) identified from a theoretical standpoint where brine mixing should be expected, and suggested that significant scale deposition may occur deep within the reservoir, particularly where a large proportion of injected water sweeps through the aquifer. The current paper seeks to apply that theoretical analysis to the Alba field, on a well-by-well basis, to establish whether diagnostic tests can identify which wells should be treated conventionally, and which require special attention. Firstly, production data and produced brine compositions are analysed to identify any recurring patterns. Wells are then classified and grouped according to various types based on this analysis. Well properties such as location within the reservoir and orientation to the flood front are then compared to identify whether they can be used to give a similar grouping of wells. Three principal zones are identified, with position relative to the injection wells and the aquifer identified as key parameters. Secondly, the flow patterns around each well are studied using the existing reservoir flow model. Modelling the dynamic mixing patterns throws further light on the differences between the zones, with scale dropout predicted in the aquifer in some areas, and in the oil-leg in others. Recommendations are made regarding the treatment of existing wells and the optimum positioning, from a scale prevention perspective, of any new wells. Introduction Sulphate scale deposition is a common problem in reservoirs where injected seawater mixes with aquifer brines1,2. For reasons that will be explained in the next section, the problem is most severe in and around the production well bores, and can cause considerable disruption to hydrocarbon production after water breakthrough. To deal with the problem two general tasks must be performed. Firstly, the quantity and type of scale must be identified, together with the location and timing of the deposition. Secondly, a suitable removal and/or prevention strategy must be designed and implemented. Both of these tasks require reservoir and laboratory data, and field experience is also a vital component in ensuring successful treatment. Both tasks are routinely assisted by application of appropriate modelling tools3. The use of reservoir simulators to predict the timing and location of water breakthrough, and the application of scale prediction codes to identify the scaling regimes, have both been discussed previously4–9. In addition, models are routinely used in chemical scale inhibitor selection studies and to optimize inhibitor squeeze treatments10. The topic of this paper is not so much the design of scale prevention treatments, although the findings have a bearing on this, but on identifying scale deposition regimes throughout an actual reservoir system. To do this produced brine chemistry data and field fluid flow modelling have been analysed on a well-by-well and field-wide basis for the Alba Field in the North Sea. The evidence of both the produced brine chemistries and the flow calculations is that scale is depositing deep within the reservoir. However, the extent and impact of this deposition varies throughout the reservoir. Three regimes are identified, where the nature of the scaling problem at individual production wells can be related to the flow characteristics in that locality. Important factors are shown to be the proximity of injection wells and the proximity and extent of the aquifer.

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.

Effective monitoring of scale inhibitor residuals following a downhole squeeze can present challenges due a variety of reasons including contamination of the produced fluid with a topside scale inhibitor, and in the case of subsea wells, often the production is commingled as several wells flow through a single riser. The introduction of phosphorus-tagged scale inhibitors has partially solved the detection issue, but more tags are still needed for subsea developments in the North Sea and for use in commingled production. Detection limits and turnaround time of the sample analysis are also concerns. A new tagged scale inhibitor has been developed combining the proven performance of sulphonated co-polymers coupled with fluorescence technology, thus allowing the scale inhibitor to be detected using fluorescence spectroscopy. This paper discusses the development of the technology for use in a North Sea field located 130 miles northeast of Aberdeen that has a downhole barium sulphate scaling risk. It is comprised of platform wells and subsea wells that tie back to the host platform via two shared risers. The operator was experiencing difficulties in detecting the subsea squeeze returns so this new tagged scale inhibitor was introduced in one of the wells to improve the monitoring of the squeeze returns. The scale inhibitor was detected successfully in the produced water samples by spectrofluorimetry and validated with gel permeation chromatography. The ultimate goal is to analyse residual squeeze inhibitors using a portable fluorimeter for onsite detection, enabling real-time monitoring of the squeeze returns. The development of the chemistry and detection monitoring technique and the preliminary results from the field trial, and demonstrates the validity of the analysis method is discussed. This new chemistry, being detectable in mixed fluids, reduces the need for shutting in wells or well tests for sampling, thus minimising process instability due to re-routing wells and shut-in losses.

Rosneft has oil fields in Western Siberia producing fluids from a number of wells via Electric Submersible Pumps (ESP's). While production rates are increased using ESP's, run time can be compromised by the formation of scale within the inner workings of the pump. The deposition of scale can be detected by the pumps requiring increasing amounts of current to maintain the flow rates. Eventually the pumps fail (either mechanically or electrically) and have to be replaced. Typically examination of these pumps indicated the main failure mechanism to be the deposition of Calcium Carbonate scale within the pump. The actual run times achieved tend to be dependant on the severity of the scaling produced water, but were typically in the order of weeks. However in some extreme cases, pump failures had occurred in a matter of days from replacement and start up. It was proposed that one treatment strategy to increase the pump run time by inhibiting scale formation was via a Scale Inhibitor Squeeze application treatment. The Squeeze process and inhibitor application is very well understood, but to get successful squeeze treatment you need to perform adequate laboratory selection tests, including inhibition efficiency testing and core flood evaluations. This data, together with the Heriot Watt University Squeeze VI modeling can get an approximation to the potential squeeze life. This paper presents the testwork performed to identify and develop successful Scale Inhibitor Squeeze Chemistries suitable for application in Western Siberia. It details the laboratory testing, the coreflood evaluation and Squeeze VI modeling. The Squeeze application and performance of the first well squeezed is reviewed together with a summary of the current status of the wells squeezed. An economic evaluation of the squeeze is also performed together with a summary of all the wells treated which demonstrates that the squeeze application provided a very cost effective method of scale control to maximize pump run time and increase the net well value. Introduction Yuganskneftegaz is Rosneft's largest oil-producing enterprise. It holds licenses to develop 26 oilfields located in the Khanty-Mansiysk Autonomous District of Western Siberia. Yuganskneftegaz was established in 1977, and in early 2005, it was fully integrated into Rosneft's core production base. Yuganskneftegaz is responsible for fields that contain approximately 16% of Western Siberia's recoverable oil reserves. Nearly 80% of them are concentrated in the Priobskoye, Mamontovskoye, Malobalykskoye and Prirazlomnoye fields. Production of oil and associated gas at Yuganskneftegaz in 2006 amounted to 56 million tonnes, and 1.5 billion cubic meters, respectively, which is 70.1% and 11% of Rosneft's total production. Yuganskneftygaz Primary fields are: Priobskoye, Prirazlomnoye, Mamontovskoye, Malobalykskoye The number of wells in production in 2006 was 7,707. The average production per well is 21.3 t/day (2006).

This paper describes the development of a PMPA scale inhibitor chemistry, for potential ‘squeeze’ application, to provide scale inhibition under severe Barium Sulphate scaling conditions. Phosphonate type inhibitor chemistries have been applied in ‘squeeze’ treatments as they have the desired adsorption characteristics to protect the near wellbore formation, perforations and production strings for a significant period of time (known as the ‘Squeeze’ Life). These chemistry types, however, are not the most efficient means of preventing scale deposition in some severe, low pH BaSO4 scaling situations. Polymeric inhibitor species, in particular PolyVinylSulphonates (PVS) and sulphonated co-polymers (VS-Co), are sometimes more suited to these types of conditions, but they do not typically posses the necessary retention characteristics to achieve the desired ‘squeeze’ lifetimes. This paper discusses the development of a new experimental PMPA chemistry which has demonstrated improved inhibition performance under harsh BaSO4 conditions, whilst retaining the adsorption and retention characteristics of earlier PMPA chemistries and could potentially result in considerably longer ‘squeeze’ lifetimes than those currently achieved with the polymeric inhibitors. Introduction The formation of oilfield scale, in particular barium sulphate, is recognised as one of the major problems associated with oil and gas production1–4. One of the most commonly used methods to control this is by the treatment of the near wellbore formation with a chemical scale inhibitor, in what is described as a ‘squeeze’ treatment4–8. In this type of treatment the inhibitor chemical is injected or ‘squeezed’ into the rock formation. When the well is put back onto production, this material will usually return in the produced fluids at a level that is greater than that required to prevent scale deposition. This concentration is known as the Minimum Inhibitor Concentration, or MIC and is typically in the order of 1–15ppm of active inhibitor. The length of time that the concentration of inhibitor in the produced fluids exceeds this MIC is known as the ‘squeeze’ lifetime. This is usually defined in terms of cumulative barrels of water produced since the treatment and depending on the production rate of the well can equate to a time period of between 3 and 12 months, or in some cases longer. Chemistries that are suitable for such an application must fulfill two criteria. Firstly, they must inhibit scale deposition at the sub-stoichiometric/threshold levels described above. Secondly, the material must be retained within the rock matrix. Retention, either by adsorption or precipitation, enables an inhibitor to return from the formation at levels above the MIC for a significant period of time. One such inhibitor type, which utilises the PhosphonoMethylated PolyAmine (PMPA) chemistry, has been found to possess extraordinary adsorption properties and, as a result, achieve significantly longer ‘squeeze’ lifetimes than a conventional phosphonate inhibitor chemistry (DETPMP - DiEthyleneTriamine PentaMethylenePhosphonate)9. The main drawback with some phosphonate type inhibitor chemistries, including PMPA, is that they are not always the most suitable types of chemistry to prevent Barium Sulphate deposition in some of the more severe scaling situations. Polymeric species, such as PolyVinylSulphonates (PVS) and sulphonated co-polymers (VS-Co), are more suited to the prevention of scale deposition in these types of conditions, however their retention characteristics are considerably less favourable in achieving suitable ‘squeeze’ lifetimes.