This paper presents the challenges of identifying and deploying a non-damaging non-aqueous scale inhibitor for pre-emptive squeeze into the largest dry producer in the BP-operated Mungo field. In order to pre-empt potential downhole scaling & subsequent impact on production, the Mungo asset requested a non-damaging, pre-emptive squeeze option for application prior to water breakthrough. Scale inhibitor squeezes are usually deployed post water breakthrough and when scale is predicted to form as a result of the co-mingling of incompatible produced brines. On the other hand, pre-emptive squeezes are preferred either when scaling is predicted from the start of water breakthrough or when the time required to mobilise chemicals etc. for an intervention is too long, placing production at risk. For Mungo, both these last scenarios applied: the predicted scaling tendencies were severe and immediate on water breakthrough, and the difficulty in mobilising a support vessel etc. to perform the job required careful planning and time. BP and their Mungo partners initiated a chemical selection test programme through their CMS provider to identify a non-damaging "Best in Class" chemical squeeze option for Mungo. The CMS partner with responsibility for chemical management of the Mungo asset organised an independent laboratory to screen commercially sensitive, "non-aqueous" products (non-aqueous carrier phase) from both their own product range and those of their competitors for potential application. When assessing chemical performance, clear selection criteria were issued to all the participating chemical suppliers prior to commencing any laboratory work. The chemicals were required to:cause minimal formation damage (or <10% damage in core flood tests);provide a maximum squeeze life (ca. 1 year was requested by the Mungo asset);be compatible with the incumbent corrosion inhibitor (>95% corrosion inhibitor performance was required); andbe compatible with Mungo brine. Other selection criteria also included environmental category, cost, impact on facilities, practicality of deployment and proven track record. This paper focuses on the main selection criteria (a) and (b). Comparative core flooding tests presented in this paper demonstrate that only one application fell within the specification of < 10% reduction in permeability. Having selected the least damaging non-aqueous chemical, further core flood tests were designed to simulate:injection into a lower permeability zone of the reservoir (or potential formation damage effects in the near wellbore region); andthe impact of chemical shut-in or adsorption. Two pre-emptive squeeze trials of a novel "non-aqueous" scale inhibitor have now been conducted in wells W168 and W163 on the BP Mungo field. The scale inhibitor was deployed by bullheading, using injection quality base oil as a preflush and overflush. In neither case was formation damage seen as a result of the treatment, with no change in oil or water rates pre and post-squeeze. In summary, the paper discusses how BP, Mungo partners and the CMS providers worked together to find the best technical solution to an important challenge facing many other fields and new developments, i. e. how to effectively select and deploy a non-damaging pre-emptive scale inhibition squeeze treatment. Independent testing has enabled the selection and deployment of a highly commercial "non-aqueous" application from an alternative non-CMS service provider.
In recent years, BP has moved into reservoirs in deep water subsea projects where sea water flooding is required for reserves recovery. The introduction of sulfate rich seawater into a reservoir producing a formation brine rich in barium ions significantly increases the potential for barium sulfate scale deposition. This type of scale is not acid soluble, unlike the carbonate based scales traditionally encountered in many regions. Alkaline based chelants, such as EDTA and DTPA, are only effective at removing small accumulations. Mechanical removal is generally considered to be the only effective removal option for significant sulfate scale deposits in the tubing but is not appropriate for removing scale from within the near well bore area or within a frac-pack or screen. Thus the recommended management strategy is one of prevention rather than remediation.
This paper describes the material selection for tubing in water injection wells for deepwater applications. It details the qualification and deployment of an alternative to duplex corrosion resistant alloy (Duplex-CRA) tubing, including the testing work that was performed. Also described are the operational aspects of running the resulting product in several deepwater wells. With the advance into expensive subsea wells, along with the use of produced water re-injection and the historical performance of de-oxygenation systems, most recent water injector designs for deepwater projects do not utilize carbon steel materials. The common materials are Duplex-CRAs, which are often an order of magnitude higher in price than carbon steel, and carry a significantly longer delivery time. There are few alternatives to Duplex-CRAs. A common choice is glass reinforced epoxy (GRE) lined tubing, whose costs are similar in magnitude to carbon steel tubing and whose delivery time is significantly shorter. GRE-lined tubing requires a set of rings and/or flares to be inserted at the length to length interface. Initially, the connection was modified to allow insertion of the rings/flares in a machined groove in the coupling. This was acceptable for many applications. However, for deeper water, higher pressure wells connection with better performance was required. By employing a modified connection on GRE-lined tubing, BP successfully used it in shallower water injection wells. By 2003, the need was recognized for GRE application in deepwater injection wells. This would require qualification for the following further requirementsDeep water tubing generally requires un-modified proprietary connections due to the loadingsSpar environments introduce fatigue loading and stresses on tubing that requires additional testingGRE tubing had not been run in production prior to injection conditions in deep waterEach GRE connection is commonly drift checked after make-up; this is not suitable for many deepwater operations. The paper will detail the material selection for tubulars, the reasons for the product development and the final qualification testing. Installation experience of the product in several deepwater wells is described. Deepwater water injection wells often cost more than producer wells. Cost is increasing as material prices continue to rise. On a project scope, the cost savings of non Duplex-CRA tubing is significant; thus the GRE manufacturer is now running the qualified product in many other deepwater projects for a variety of operators. As a result of this testing and qualification, GRE-lined tubulars are now being used for the majority of BP deepwater non HP HT water injection projects.
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