Carbonate or sulphate scaling is usually mitigated by using chemical inhibitors that alter the growth mode of the scale mineral, but with halite scaling the apparent absence of a suitable inhibitor has meant that periodic removal with low-salinity water has been favoured. We report laboratory testing and the first field application of a chemical inhibitor for halite scaling. The inhibitor was field-tested in the Leman gas field (North Sea), where halite scaling occurs in gas-compression equipment due to evaporation of water from brine droplets carried over from the gas-water separator. The scale reduces the efficiency of both compressor and cooler, necessitating regular costly cleaning of the internals. After a recent system clean out, the cheap, non-toxic halite inhibitor was dosed continuously for 3 months into the production stream downstream of the gas-water separator. Whilst halite deposition was not completely suppressed, an increase in compressor efficiency was observed for all compression stages compared with recent non-inhibited data. A significant improvement in gas-cooler efficiency and a reduced tendency to block gas-flow meters, were also observed. This indicates that the inhibitor has considerable potential for cost-effective control of halite scaling, possibly as an alternative to periodic removal or in combination with it. Introduction Scale deposition is a widespread problem that causes production deferment, necessitates costly intervention, and can also compromise safety systems. It can be particularly severe when highly saline (typically>200,000 mg/litre) or even salt-saturated formation water is involved, because of the potential to generate large quantities of halite scale (rock salt, NaCl), normally by evaporation of water into the gas phase. Although halite deposits tend to be easier to remove than most other scales - most commonly by periodic washing with low-salinity water -, the rate of build-up can be orders of magnitude greater,1 and thus very frequent intervention may be required to limit hydrocarbon deferment and prevent equipment malfunction.2 Unlike carbonate and sulphate scales, which can be controlled by the use of threshold inhibitors that influence crystal nucleation and/or growth, preventing the build-up of halite scale has only been achieved by continuous dilution of the fluid stream with water upstream of where deposition occurs. Whilst successful, this can require significant amounts of low-salinity water to be available, which preferably is chemically compatible with the produced water and has been deoxygenated to limit corrosion. Sea water is often unsuitable without addition of large amounts of inhibitor chemicals against sulphate scale, because high-salinity formation waters frequently contain extreme levels of barium, strontium and calcium ions, and are hence highly incompatible with the high concentration of sulphate in sea water.3 Moreover, the introduction of even small amounts of additional liquid can be highly detrimental to the performance of some equipment, such as gas compressors.

The formation damage that results from the incomplete back-production of viscous, fluid-loss control pills can be minimised if a slow acting internal breaker is employed. In particular, core-flow tests have indicated that combining a succinoglycan-based pill with a hydrochloric acid internal breaker enables a fluid-loss system with sustained control followed by delayed breakback and creates only low levels of impairment. To describe the delayed breaking of the succinoglycan/hydrochloric acid system, a model, based on bond breaking rate, has been used. With this model, it is possible to predict the change of the rheological properties of the polymer as a function of time for various formation temperatures, transition temperatures of the succinoglycan and acid concentrations. Hence, the model can be used to identify optimum formulations of succinoglycan and acid breaker on the basis of field requirements, such as the time interval over which fluid-loss control is needed, the overbalance a pill should be able to withstand and the brine density required.

As assets in the Southern North Sea continue to mature the tie in of new (high pressure) wells becomes more challenging. Additionally, the operators may consider centralizing their processing, increasing the complexity of the system. The wet gas then has to be transported over longer distances. Moreover, a greater emphasiss than before on the environment has created a drive to reduce production chemical usage. These factors combined have set new and challenging requirements for the chemicals that are to be applied to protect the existing facilities against hydrate formation and corrosion. Conventional offthe-shelf technologies were not able to meet the tough challenges, and required the development of a novel, and fit for purpose kinetic hydrate inhibitor (KHI) and corrosion inhibitor (CI). The minimum performance requirements for the KHI included protection against hydrate formation at conditions of 8 degrees Celcius subcooling and 200 hours of hold time. Besides the high level of subcooling and extended hold time, several secondary chemical properties were essential for successful application of the developed product. These included: solubility of the KHI and CI at elevated temperature and high salt concentrations (independent of each other and together), the chemicals are to be formulation in methanol and functionally compatible, have a minimum impact on oil in water and water in condensate separation, have low reservoir impact with produced water reinjection (PWRI), be HSSE acceptable (CEFAS sub-warning free) and comply with certified chemical cleanliness standards (SAE Class 6) to enable trouble-free umbilical application. All of these requirements were able to be met for the developed product packages. This paper describes the qualification process, lessons learned and the first successful field application of the newly developed chemistries into a recently developed reservoir block in the southern North Sea.

The fine materials present in the gravels used in gravel packing represent a largely unrecognised source of impairment. They form filter cakes on/in the perforation wall resulting in direct impairment and cause declining injectivity while placing gravel in perforations. This may cause poor perforation filling with gravel, which in turn leads to pack invasion on production and further impairment. This study has revealed substantial levels of permeability impairment caused by injection of suspensions containing fine debris from originating gravels (clay, silt and satellite particles). This occurs for natural gravels that are well within the API specification limit of 1%w for silt and clay. This work indicates that the API specification should be reduced to 0.005%w. In this case less than 10% of the fines, causing possible impairment in the completion phase, are originating from the gravel. Washing of the gravels (if the gravel does not meet the proposed new specification) will reduce the fines content and is suggested for synthetic gravels; natural gravels require a more thorough washing step. Introduction Placement of gravel inside perforations relies on leak off of gravel carrier fluid into the formation. This process may however cause i) accumulation of fine solids present in the slurry at the perforation wall or within the formation, resulting in internal or external filter cake formation, and ii) reduced injectivity. The latter may cause incomplete filling of perforations with subsequent invasion of formation grains into the gravel or 'trapping' of fine solids by the gravel pack. In-house studies have proven that these two mechanisms and intermixed gravel with perforation debris are the major causes for internal gravel pack productivity impairment. All gravels from natural sources and some synthetic materials are contaminated with fine materials viz. silt, clay and grain satellite particles. Even if good oil field practice is maintained (brine filtration, wellbore cleaning prior to gravel packing, minimal use of pipe dope etc.),the fines present in gravel slurries originating from the gravel itself,fines released by the crushing action of the pumps andfines released by the abrasive action of the flowing slurry remain sources of impairment. Core flushing experiments have been carried out to evaluate the permeability impairment due to the fines present in several gravels. The results obtained are presented in this article. EXPERIMENTAL PROCEDURES Fluid preparation and analysis Gravel slurries (479 g/l) were prepared using 0.45 m filtered 2% KCl brine for two minutes using a high speed (2000 rpm) propeller mixer. The gravel was removed by 80 mesh sieving, resulting in gravel carrier fluids contaminated with suspended fines from the gravel. These gravel carrier fluids were flushed at rates and volumes equivalent to oil field gravel packing practice in the core flushing tests. P. 699