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Abstract Over the years environmental legislation has forced changes in the types of scale inhibitor molecule that can be deployed in certain regions of the world. These regulations have resulted in changes from phosphonate scale inhibitor to polymer based chemistry, particularly in the Norwegian and UK continental shelf where phosphonates have either been on the substitution list or phased out for many applications. Over the past 10 years significant improvements in inhibitor properties of the so called "green" scale inhibitors have been made. However for one particular operator the squeeze application of this "green" scale inhibitor resulted in poorer than expected treatment lifetimes and significant operating cost due to the frequency of retreatment. To overcome the increasing operating cost an evaluation was made of the current treatment chemicals vs. the older more established phosphonate scale inhibitors. The results for the laboratory evaluation suggested that the older chemistry would extend treatment life and reduce operating cost. A case was made to the legislative authority who approved the use of the phosphonate scale inhibitor and field applications started. The squeeze lifetimes for the "red" phosphonate chemistry were shown to be significantly better than the existing "yellow/green" inhibitors. During the following months other scale inhibitors with improved environmental characteristics were developed and evaluated. One such molecule was shown to have similar coreflood retention than the applied "red" phosphonate and presented no formation damage. This paper presents the laboratory evaluation of the new scale inhibitor, illustrates the improvement observed with this new inhibitor via field squeeze treatment results from a well treated with both the "red" and new "yellow" environmental profile inhibitor chemicals. This paper outlines the challenges with environmental legislation and how it has been possible to develop technical solutions (both in terms of environmental vs. safety issues and with new inhibitor chemicals) to meet the challenges of offshore scale control.
Abstract Over the past 10 years significant improvements in "green" scale inhibitor chemistries have led to considerably increased use in certain regions, notably the Norwegian sector of the North Sea. However, the use of these more environmentally acceptable products can be at the cost of optimum performance. This was the case for the Varg field: an extensive Best-In-Class re-selection of available yellow / green polymeric inhibitors failed to achieve the required improvement in lifetimes. Modelling work conducted for one of the wells had also shown that one of the primary causes of the poor lifetimes was the lack of effective placement of the treatment chemical in the water-producing zones.1 More recent experimental work to be described in this paper has demonstrated that the scaling challenges on this field could be mitigated in part by adopting the less environmentally friendly, but better retaining, ‘red’ phosphonate chemical. Comparison of the predicted inhibitor return profile using laboratory derived data with the subsequent field return showed very good correlation in a well with no placement challenge. In a manner analogous to the polymer-based chemistries,1 application of the phosphonate inhibitor in a well with known placement issues gave less impressive return lifetimes. However the better retention properties meant that the treatment lifetimes remained acceptable despite the poor placement. When the placement issues were taken into account, the previously derived isotherm proved very effective at simulating the field case in this more challenging well. This paper therefore describes an alternative, more rigorous approach to simulating treatments in challenging wells rather than using history matched averaged field return isotherms. The paper then shows the impact on optimisation of future treatments when the different approaches are examined. This work therefore expands considerably on that previously described in SPE 114077.
Sørhaug, E.. (Talisman Energy Norge A/S) | Jordan, M.M.. M. (NalcoChampion, An Ecolab Co.) | McCartney, R.A.. A. (Oilfield Water Services Ltd.) | Stalker, R.. (Scaled Solutions Ltd.) | Mackay, E.J.. J. (Heriot-Watt University) | Green, J.. (Corex (UK) Ltd.)
Abstract The Blane field is a sub-sea oil and gas production development located in the southern part of the North Sea straddling the UK and Norwegian border. The field is expected to produce inorganic scale (BaSO4) when injection water containing sulphate breaks through in the production wells. This will require scale inhibitor squeezes from an intervention vessel to mitigate scale deposition. The wells were completed with long horizontal sections straddling multiple producing zones. This could potentially result in scale deposition severely reducing productivity if both formation water and injection water were to be produced simultaneously into the wells. Adding to the complexity, the perforation guns were left in the wellbore as part of the completion preventing any access to the perforation area. The distribution of scale inhibitor during a squeeze pumping operation could therefore be uneven leaving parts of the well poorly protected. In addition, the guns prevent physical removal of any type of materials in the well bore like asphaltenes, sand and scale which could plug off the perforations during a pumping operation with a well intervention tool; Wireline, coiled tubing, etc.. Injection water supplied from a host platform is used for pressure support of the reservoir. During the field development, the injection water was expected to contain mostly produced water reducing the scale potential considerably as it would have low sulphate content. When water injection started, very little produced water was being produced resulting in mostly seawater being available available for pressure support. Scale deposition in the well and around the well bore could therefore prove to be impossible to control unless reactions in the reservoir would reduce the scale potential or a reliable scale inhibitor squeeze method to mitigate scaling could be identified. This paper describes the joint effort of 6 different companies to identify the risks associated with the inorganic scaling during production and how a scale squeeze strategy was developed. The work included scale inhibitor selection, a geo-chemical study, and reservoir and near well bore simulations, sub-sea deployment selection, deciding on water chemistry and production monitoring and development of an overall management plan.
Abstract A field in the Central North Sea produces oil from a Forties type reservoir with seawater pressure support. The high salinity formation water contains up to 450mg/l barium, creating a significant scaling risk to the wells, all of which now show seawater breakthrough. The operator was required to replace a scale squeeze inhibitor carrying a substitution warning, and the need for a more cost effective squeeze lifetime was also a driver for change in a field containing complex wells with highly variable permeability, and a challenging placement environment. Evolving environmental legislation in the North Sea has forced changes in the type of scale inhibitor which may be deployed in the UK and Norwegian continental shelf. Phosphonate scale inhibitors have been on the substitution list or phased out for some years, leading to a technology gap for scale squeeze applications, where polymer inhibitors often show relatively poor squeeze lifetimes or can be difficult to detect readily at residual concentrations compared to phosphonates. This paper presents the laboratory evaluation and field application to several wells of the new scale inhibitor, describes the application of the scale inhibitor in complex wells using a combination of placement techniques such as crossflow balancing during shut in and diversion using wax, illustrates that the new inhibitor has demonstrated improved retention and desorption characteristics leading to longer squeeze lifetimes while highlighting the disadvantages of relying on wellhead scale inhibitor analysis alone for scale management of heterogeneous wells. This paper will illustrate the possibility to replace traditional phosphonate scale inhibitors which carry a substitution warning with a chemical which shows much improved squeeze lifetimes over traditional polymer alternatives, leading to a reduction in campaign frequency and resultant cost savings. The lesson learned from these applications can be shared with other subsea producing basins such as those found in offshore Gulf of Mexico, Brazil and West Africa.