In oil and gas production operations, precipitation of mineral scales causes many problems, such as formation damage, production losses, increased workovers in both producers and injectors, poor injection-water quality, and equipment failures caused by underdeposit corrosion. The most common mineral scales are sulfate- and carbonate-based minerals. However, scale problems are not limited to these minerals, and there recently have been reports of unusual scale types, such as zinc and lead sulfide. This paper focuses on zinc sulfide scale that has been found in several fields along the Gulf Coast of the U.S.A. and in fields within the North Sea Basin. Scale deposition has caused significant pressure and rate reductions in high-temperature and high-rate gas, condensate, and black oil wells. After acid washes to remove zinc sulfide scale (and other acid-soluble solids), production rates and flowing tubing pressures returned to previous levels, but new scale deposits formed in many wells and retreatments were required. Topside process equipment, most noticeably low-pressure separators and hydrocyclones, were observed to suffer reductions in performance owing to zinc sulfide scale deposition. In addition, there are significant risks associated with acid treatments in high-temperature, high-pressure (HT/HP) gas wells in corrosivity of the acid at high temperatures (general corrosion, sulfide stress cracking, and chloride stress cracking) and in safety (hydrogen sulfide generation by acid dissolution of zinc sulfide plus high-pressure pumping). One possible method for preventing production declines and reducing the need for HT/HP acid jobs is to use scale inhibitors or chelating agents to prevent the formation of zinc sulfide scale. The relative effectiveness of eight scale-inhibitor chemistries and two chelating agents in preventing formation of zinc sulfide scale has been determined. The required scale-inhibitor concentrations are significantly higher than those needed for common sulfate and carbonate scales. For chelating agents, it is possible to prevent the formation of zinc sulfide scale when the required concentrations are proportional to the zinc ion concentration in the scaling brine. This paper outlines the testing methods used for chemical screening and prediction so that assessment of the potential problem within fields can be assessed during appraisal, before production commences, making a method of managing the risk available.
The most common scales encountered in oilfield operations are sulfates, such as calcium sulfate (anhydrite and gypsum), barium sulfate (barite), strontium sulfate (celestite), and carbonates (calcite). Numerous studies on scale inhibition with regard to controlling such scale within the reservoir and in production equipment (downhole and topside) have been published in the past few years.1–8 Other less common scales, such as iron oxides, iron sulfides, and iron carbonate, have also been reported. These scale types are most commonly associated with iron generation from corrosion products, although iron carbonate scale has been reported to form from produced water drawn from formations where iron-containing authigenic minerals are present within the formation. 9–11 Similar to the sulfate and carbonate scale types described previously, even iron carbonate scale can be controlled by inhibitor molecules.12
Lead and zinc sulfide scales have recently become a concern in a number of North Sea oil and gas fields. These deposits have occurred within the production tubing and topside process facilities. Investigation of the literature leads to a number of references in which such scale had been observed,13–17 but very little information was available on their inhibition by chemical means. A recent review paper outlines the formation mechanisms of both lead and zinc sulfides and also reviews the data from the literature before describing how a chemical-inhibition program has been effectively deployed within a North Sea field.18
Several sources of zinc/lead and sulfide ions are possible within produced fluids.
Reaction products of formation minerals (sphalerite zinc sulfide and galena lead sulfide) during connate and aquifer water contact during many millions of years could result in partial mineral dissolution.13–15 Zinc ion concentration within HP/HT fields within the Gulf Coast of Mexico16 were reported to be as high as 70 ppm Pb and 245 ppm Zn.
Reaction of injected water used for pressure support into the aquifer or the oil leg can result in the fresh or seawater reacting with minerals within the formation, which can become enriched in heavy metal ions.
Zinc ions can come from heavy-brine completion fluids lost into the formation during drilling and well workover operations (zinc bromide). Biggs17 reported that a loss of 500 bbl of 17.2 lb/gal zinc bromide completion fluid within a reservoir resulted in significant zinc sulfide scale formation with the presence of 2 ppm of hydrogen sulfide from the reservoir. In an oil field operated in the North Sea, U.K. sector, the presence of zinc sulfide on downhole gauges and logging tools was reported within a well where zinc bromide brines had been lost during completion operations. During initial water breakthrough, zinc levels within the produced fluids were in the range of 10 to 50 ppm for several months.
Hydrogen sulfide (H2S) gas is the most likely source of sulfide ions that allow the formation of lead/zinc sulfide scale. Low concentrations (in the tens of ppm levels) of H2S have been reported in produced gas from wells where lead and zinc sulfide scale problems have been reported.
Decomposition of the corrosion inhibitor and drilling compounds can also produce sulfide ions when tested in autoclave equipment at high temperatures but are very unlikely to be the source of sufficient sulfide ions to give scale deposition during many years of production. The most likely source of sulfide ions is reservoir hydrogen sulfide gas.