Selection and Application of a Non-Damaging Scale Inhibitor Package for Pre-Emptive Squeeze in Mungo Production Wells

Abstract

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.

Acid/Scale Inhibitor Stimulation Treatment for High-Temperature CHFP Subsea Wells: Fluid Qualification and Formation Damage Assessment

“…Strategies include the use of oil soluble scale inhibitors, aqueous inhibitors in conjunction with relative permeability modifying chemicals, and micro-encapsulated scale inhibitors. Non-aqueous scale inhibitors, on the other hand, are not as readily available as aqueous scale inhibitors, and while some field trials have taken place, their risks and effectiveness have not been fully assessed (Graham et al 2002a and2002b). An alternative treatment is here proposed, it consists on the addition of a mutual solvent pre-flush stage prior to the injection of the main acid / scale inhibitor treatment, followed by the overflush brine.…”

Technical and Economic Analysis of the Downhole Scale Risks and Uncertainties for Subsea and Deepwater Field Developments

“…In a similar manner, the Mungo field which forms part of the ETAP development anticipated rapid increases in seawater following initial water production and therefore non-damaging preemptive squeeze treatments were required for dry oil producers. 19 Although these operations represented a risk to production owing to the introduction of foreign fluids into the wellbore prior to water production, the risked-cost of not treating the wells was more significant since the options would be to either shut in the wells while awaiting mobilization of scale squeeze treatment products or to risk scale build up in the wells. Owing to the relatively high barium composition of the formation water (FW) (FW Ba ~ 120mg/l) this was not considered a low risk option.…”

“…These are expected to be successful based upon reports from other BP-operated subsea fields such as Mungo. 19 It is believed that the risks associated with formation damage from such operations are reduced in the GoM because of the rock characteristics; however, many of the fields are equipped with coil tubing access points and other systems in the event that damage remediation is required.…”

Coreflood Studies to Examine Potential Application of Novel Scale Inhibitor Products to Minimise Intervention During Field Life Cycle

“…The very high level of damage to oil permeability meant that the emulsion was not suitable for this low water cut application. 27 Both floods (EF 9 and EF 10) were repeated but this time the cores were treated as if the reservoir was at high water cut Sor conditions (type A but this time with chemical injection into and then out of the core like a type C flood cycle, coded type D). The data from this coreflood cycle is presented in Figures 15 and 16 where a 5-fold increase in differential pressure was recorded ( Table 8).…”