Scale Problem in Oil Production

Scale problem in oil production is a big issue. We have found an interesting article published at Petrowiki website. We transcribe below some excerpts of such article, related to scale formation and use of inhibitors. 

 

Scale problem in oil production

Wells producing water are likely to develop deposits of inorganic scales. Scales can and do coat perforations, casing, production tubulars, valves, pumps, and downhole completion equipment, such as safety equipment and gas lift mandrels. If allowed to proceed, this scaling will limit production, eventually requiring abandonment of the well.

Technology is available for removing scale from tubing, flowline, valving, and surface equipment, restoring at least some of the lost production level. Technology also exists for preventing the occurrence or reoccurrence of the scale, at least on a temporary basis. “Temporary” is generally 3 to 12 months per treatment with conventional inhibitor “squeeze” technology, increasing to 24 or 48 months with combined fracture/inhibition methods. This page discusses types of inorganic scale, their control, inhibition, and removal.

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Inhibition

Inhibitors are typically used after remediation to prevent further scaling. Obviously, this same technology can be used to do pre-emptive scale control. The effectiveness of inhibition is related to the degree of scale supersaturation—the higher this value, the more difficult it is to inhibit. For example, barite solutions with saturation indices > 350 are particularly difficult to inhibit.

Scale precipitation can be avoided by chelating the scaling cation. This is costly because the reactions are “stoichiometric,” (e.g., one chelant molecule per one scaling cation). More effective are chemicals that poison the growth of scale. These are “threshold” inhibitors, effectively inhibiting mineral scale growth at concentrations of 1,000 times less than a balanced stoichiometric ratio. Most inhibitors for inorganic scales are phosphorous compounds:

  • Inorganic polyphosphates
  • Organic phosphate esters
  • Organic phosphonates
  • Organic aminophosphates
  • Organic polymers

A variety of such chemicals is well-known, and they are available from many companies. Two chemical structures are shown in Fig. 3. These are used for the various carbonate and sulfate scales. Recently, the successful use of a nonphosphorus compound to inhibit halite precipitation has been described and field tested at moderate temperatures; more classical amine-based halite salt inhibitors are also available for halite inhibition.

Delivering the inhibiting solution to the scaling brine in the tubular has been done by a number of means:

  • Continuous injection into the wellbore via a “macaroni string” (a narrow-diameter tubing reaching to the perforations)
  • Injection into a gas lift system 
  • Slow dissolution of an insoluble inhibitor placed in the rat hole

These delivery methods are straightforward to implement but not necessarily without problems. For example, gas injection requires the inhibitor solution to be atomized properly and not to deposit subsequently on the tubular walls immediately adjacent to the injection point;[17] narrow tubing can plug.

The most frequently used method of delivering the inhibiting solution to the scaling brine has been the “inhibitor squeeze.” Here an inhibitor-containing solution is forced into the formation, whereby the inhibitor then resides on the rock surface, slowly leaching back into the produced-water phase at or above the critical concentration needed to prevent scaling [the minimum inhibitor concentration (MIC)]. It is intended that the released inhibitor protect the tubulars, as well as the near wellbore. It is required, obviously, that the inhibitor adsorb on the formation rock with sufficient capacity to provide “long-term” protection. It is also required that the inhibitor be relatively stable to thermal degradation under downhole conditions and be compatible in the particular brine system. And it is also required that the inhibitor treatment not cause a significant permeability reduction and reduced production (see discussion that follows). These requirements are generally achievable, but again, one chemical does not necessarily fit all field situations.[18]

Two types of inhibitor squeeze treatments are routinely carried out where the intention is either to adsorb the inhibitor onto the rock by a physico-chemical process —an “adsorption squeeze”—or to precipitate (or phase separate) the inhibitor within the formation pore space onto the rock surfaces—a “precipitation squeeze.”

Adsorption of inhibitors is thought to occur through electrostatic and van der Waals interactions between the inhibitor and formation minerals. The interaction may be described by an adsorption isotherm, which is a function of pH, temperature, and mineral substrate and involves cations such as Ca+2. The adsorption process for retaining inhibitor in the formation is most effective in sandstone formations. Treatment lifetimes are generally on the order of 3 to 6 months.

The “precipitation squeeze” process is based on the formation of an insoluble inhibitor/calcium salt. This is carried out by adjusting the calcium ion concentration, pH, and temperature of polymeric and phosphonate inhibitor solutions. Also used are calcium salts of phosphino-polycarboxylic acid or a polyacrylic acid scale inhibitor. The intent is to place more of the inhibitor per squeeze, extending the treatment lifetime. Normally, the precipitation squeeze treatment lifetime exceeds one year, even when high water production rates are encountered.

The engineering design of such adsorption and precipitation squeeze treatments into real-world multilayer formations is generally done with an appropriate piece of software. This simulator takes core flood data and computes the proper pre-flushes, inhibitor volumes, post flushes, and potential squeeze lifetime. Computer simulation of such chemistry is described in Shuler and Yuan, et al.

The sequence of pumping steps involved in squeezing inhibitors is listed next.

  • Acid cleans the scale and debris out of the wellbore to “pickle” the tubing (this fluid should not be pushed into the formation).
  • “Spearhead” package (a demulsifier and/or a surfactant) increases the water wetness of the formation and/or improves injectivity.
  • Dilute inhibitor preflush pushes the spearhead into the formation and, in some cases, cools the near-wellbore region.
  • Main scale-inhibitor treatment, which contains the inhibitor chemical, is normally in the concentration range of 2.5 to 20%.
  • Brine overflush pushes the main treatment to the desired depth in the formation away from the wellbore.
  • Shut-in or soak period (usually approximately 6 to 24 hours)—the pumping stops and the inhibitor adsorbs (phosphonate/polymers) or precipitates (polymers) onto the rock substrate.
  • Well is brought back to production.

To continue reading this article please go to the original published page.

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