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Difference between revisions of "Scale problems in production"
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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.
As brine, oil, and/or gas proceed from the formation to the surface, pressure and temperature change and certain dissolved salts can precipitate. This is called “self-scaling.” If a brine is injected into the formation to maintain pressure and sweep the oil to the producing wells, there will eventually be a commingling with the formation water. Additional salts may precipitate in the formation or in the wellbore (scale from “incompatible waters”). Many of these scaling processes can and do occur simultaneously. Scales tend to be mixtures. For example, strontium sulfate is frequently found precipitated together with barium sulfate. The chemical formulae and mineral names for most oilfield scales are shown in Table 1.
The most common oilfield scales are:
“Exotic” scales such as calcium fluorite, zinc sulfide, and lead sulfide are sometimes found with high temperature/high pressure (HT/HP) wells.
Calcite deposition is generally a self-scaling process. The main driver for its formation is the loss of CO2 from the water to the hydrocarbon phase(s) as pressure falls. This removes carbonic acid from the water phase, which had kept the basic calcite dissolved. Calcite solubility also decreases with decreasing temperature (at constant CO2 partial pressure).
Halite scaling is also a self-scaling process. The drivers are falling temperature and evaporation. Halite solubility in water decreases with decreasing temperature, favoring halite dropout during the production of high total dissolved solids (TDS) brines to the surface. (Falling pressure has a much smaller effect on decreasing halite solubility.) Evaporative loss of liquid water is generally the result of gas breakout from undersaturated condensate and oil wells, as well as the expansion of gas in gas wells. This increase in water vapor can leave behind insufficient liquid water to maintain halite solubility in the coproduced brine phase. Halite self-scaling is found with both high-temperature and low-temperature wells [e.g., with 125 and 350°F bottomhole temperature (BHT) gas/gas condensate wells].
Barite scales are generally the result of mixing incompatible waters. For example, seawater is often injected into offshore reservoirs for pressure maintenance. Seawater has a high-sulfate content; formation waters often have high-barium contents. Mixing these waters results in barite deposition. If this mixing/precipitation occurs within the reservoir far removed from a vertical wellbore, there will generally be little impact on the production of hydrocarbons. Mixing/precipitation near or within the wellbore will have a significant impact on production. Mixing of incompatible waters within the sandpack of a hydraulically fractured well can also be detrimental to production. Furthermore, after the initial, large deposition of scale, this water continues to be saturated in barite and additional barite scale will continue to form in the wellbore as pressure and temperature fall.
Waterfloods combining ground waters with high calcium and high sulfate contents can deposit anhydrite or gypsum by much the same “incompatible waters” mechanism discussed for barite. However, calcium sulfate scale solubility, unlike that of barite scale, actually increases with decreasing temperature (until about 40°C). This can decrease the likelihood of scale after the initial mixing deposition. The reversal in solubility falloff below 40°C accounts for the gypsum scaling observed in surface equipment. This inverse temperature effect can result in the generation of anhydrite scale when injecting seawater. Anhydrite solubility falls as pressure falls; data could not be found for gypsum solubility vs. pressure.
Iron sulfide scales are almost ubiquitous when hydrogen sulfide is produced—frequently the result of tubular corrosion in the presence of H2S. A review of the iron sulfide chemistry and phases occurring in production equipment is contained in Nasr-El-Din and Al-Humaidan and Cowan and Weintritt. The chemistry is complicated; more than one iron sulfide phase can be present. The physical properties of the phases vary (sometimes dense, sometimes not), and the phase composition can change with time.
These multistep scale/water chemistries can be simulated with present day computer software. Some of the programs are commercial, and some operators have their own in-house programs. In effect, the code sets up a series of equilibrium equations for each possible scale and solution ion/ion reaction, as well as solution-gas reaction, then solves them simultaneously as a function of:
- Input pressure
- Gas composition
- Water-phase composition
These are referred to as “thermodynamic models.” Software has not yet reached a level of sophistication sufficient to say, reliably, how fast these solids can form during production. This has resulted in a series of “rules-of-thumb,” correlating an operator’s field experience with the thermodynamic simulator’s output. Such rules of thumb are much less necessary for formation scaling, particularly if the mineral is naturally present in the formation (e.g., calcite). Computer simulation of scaling tendencies for produced oilfield brines has found considerable acceptance and application. Examples of this technology, applied to halite and calcite scaling in HT/HP wells, are in Jasinski, et al. and Jasinski.
Scale remediation and prevention comes at a cost. It is more appropriate to think of scale control not as a cost, but in terms of “value added”—obviating the consequences of not remediating or preventing scale formation, and so increasing the total revenue from a well, as well as possibly extending its lifetime. The effects of scale can be quite expensive and rapid. In one North Sea well (Miller field), production fell from 30,000 B/D to zero in just 24 hours because of scaling. The cost for cleaning out the single well and putting it back on production was approximately the same as the chemical costs to treat the entire field. While not all wells are susceptible to such momentous penalties for allowing scaling to initiate, there is no question that scale formation, remediation, and prevention have associated costs. The cost savings because of less deferred/lost oil can result in substantially increased revenue over the life of the well, as well as more oil.
It is anticipated that oilfield scaling problems will continue to worsen and become more expensive. The new drivers are:
- Tendency to longer tiebacks
- Use of smart wells (integrity more critical)
- More gas production (gas well formations tend to be more delicate)
- Nneed to use greener chemicals
- Increasing amounts of produced water
Identifying scale occurrence
Scale control has tended to be reactive rather than proactive. There are a variety of methods of removing the effects of scale on production. The first step is to determine which scales are forming and where they are forming. Some of this information can be reliably inferred from the computer simulation procedures discussed above, particularly for self-scaling processes. The simplest method of physically detecting scale in the wellbore is to run calipers down the wellbore and measure decreases in the tubing inner diameter. Gamma ray log interpretation has been used to indicate barium sulfate scale because naturally radioactive radium (Ra226) precipitates as an insoluble sulfate with this scale. An example of this technology is shown in Fig. 1. Visual observation with the appropriate wireline tools has also been used to show the presence of calcite and halite solids within the wellbore.
The onset of water production coinciding with simultaneous reduction in oil production is a sign of potential scale problems. It is quite possible, particularly with gas wells, to produce water below the limit of detection of surface analysis (nominally 1 or 2%). This water will evaporate and leave its dissolved solids behind, as scale. Because the amounts of water are small, the amounts of solids per unit volume of water will be small, but the solids will accumulate with time. The same idea applies to the appearance at the surface of liquid “fresh” water when the reservoir brine is known to be brackish. This can be condensed water because of falling temperature. When a few percent of liquid water is produced, it is prudent to track the dissolved ion content with time. Injection-water breakthrough is generally signaled by dramatic changes in the concentrations of scaling ions, such as barium or sulfate, which coincide with reduced oil production.
Early warning of scaling conditions downhole would be valuable. Wells with intelligent completions and permanent monitoring systems are being designed to contain scale sensors. The function of the scale sensor is double duty—not only to provide early warning about the initiation of production impairment by scale generation but also to provide information about possible impairment of the smart-well sensors and valves by films of scale.
Scale remediation techniques must be quick and nondamaging to the wellbore, tubing, and the reservoir. If the scale is in the wellbore, it can be removed mechanically or dissolved chemically. Selecting the best scale-removal technique for a particular well depends on knowing the type and quantity of scale, its physical composition, and its texture. Mechanical methods are among the most successful methods of scale removal in tubulars. When pulling costs are low (e.g., readily accessible and shallow land locations), the least expensive approach to scaling is often to pull the tubing and drill out the scale deposit.
Scales are generally brittle. One of the earliest methods used to break off the thin brittle scale from pipes was explosives: a strand or two of detonation cord (“string shot”) placed with an electronic detonation cap at the appropriate location in the wellbore, most effectively at the perforations. Thicker scales require more stringent means. Impact bits and milling technologies have been developed to run on coiled tubing inside tubulars using a variety of chipping bits and milling configurations. Such scale removal rates are generally in the range of 5 to 30 linear ft/hr of milling.
An alternative to milling and drilling is jetting. Fluid jetting systems have been available for many years to remove scales in production tubing and perforations. These tools can be used with chemical washes to attack soluble deposits where placement is critical. Water jetting can be effective on soft scale, such as halite, but is less effective on some forms of medium to hard scales such as calcite and barite. The use of abrasive slurries greatly improves the ability of jets to cut through scale but can damage the steel tubulars and valves.
“Sterling beads” is an alternative abrasive material for scale removal by jetting. This material matches the erosive performance of sand on hard, brittle scales, while being 20 times less erosive of steel. Sterling beads do not damage the well if prolonged jetting occurs in one spot. The beads are soluble in acid and have no known toxicity, simplifying use and cleanup. Hard scales, such as barite, are removed at rates > 100 ft/hr. This tool is capable of descaling configurations other than wellbore tubing (e.g., removing hard barite scale deposits on two gas lift valves in a multiple-mandrel gas lift completion).
Chemical dissolution of certain wellbore scales is generally relatively inexpensive and is used when mechanical removal methods are ineffective or costly. Carbonate minerals are highly soluble in hydrochloric acid; therefore, they can easily be dissolved. Bullheaded “acid washes” are commonly used to remove calcite accumulations within the wellbore.
Sulfate scale is more difficult to remove from the wellbore because the scale has a low solubility in acid. Chelants (scale dissolvers) have a high thermodynamic driving force for dissolving sulfate scales such as barite, isolating and locking up the scale metallic ions within their closed cage-like structures (Fig. 2). These chemicals are successful at removing films of sulfate scale from the wellbore. However, they are slow in dissolving the larger particle-sized wellbore scales and plugs—the reaction rates are surface-area limited; treatments are time-consuming, thus expensive.
Fig. 2—A representation of a chelant/scale dissolver molecule, ethylenediaminetetraacetic acid (after Crabtree et al.).
Iron sulfides are soluble in hydrochloric (HCl) acid. Many HCl corrosion inhibitors are also effective in inhibiting the iron sulfide from dissolution, as well as the tubular steel. There are now exceptions: inhibitors that protect the steel and not the scale, as well as being compatible with scavengers for the toxic hydrogen sulfide that is generated.
For halite, dilution with low-salinity water is sufficient to prevent its accumulation in the wellbore and to dissolve halite that may have accumulated in the wellbore. This requires a source of fresh or brine-treated water to help prevent other scaling problems, which can be expensive. A case in point is the use of a desulfation plant to remove sulfate ion from the halite wash water for the Heron field production.
Some scales and scaling situations are “chemically difficult.” Fluorite scale, found with some HT/HP brines, has no known solvent. Access of the scale-dissolver chemical to the inorganic scale can be blocked by organic deposits (e.g., asphaltenes).
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; 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.
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.
Fig. 4 illustrates a typical inhibitor return curve that shows the concentration of an inhibitor dissolved in the water phase as the well is brought back on production.
A large amount of inhibitor returns immediately after turning on the well. This is nonadsorbed inhibitor or weakly adsorbed inhibitor. It is “wasted” in the sense that it is not available for use late in the life of the squeeze. This wasted inhibitor does not otherwise impose a serious financial burden on the treatment—the inhibitors can be the cheapest part of the inhibition treatment. The plateau (or slowly declining) portion of the return curve is the critical data that describe the effectiveness of the treatment. As long as the curve is above the MIC, scale deposition is not taking place in the formation or wellbore. Immediately below the MIC, scale formation may start to occur.
The x-axis in Fig. 4 is given in terms of time (months). The lifetime parameter is more correctly volumes of water produced. Obviously, a high rate of water passing over a given amount of inhibitor will maintain the MIC for a shorter period of time than a low rate of water passing over the same amount of inhibitor.
Cautions with inhibitor treatments
Scale-inhibitor squeeze treatments can sometimes bring undesirable side effects. These side effects include: process upsets, poor process and discharged water quality on initial flowback, extended cleanup period, deferred oil, and the potential for a permanent decrease in oil production combined with an increase in water production. The first three side effects listed are functions primarily of the oil, brine, and squeeze chemicals. Most of these problems can be avoided, or at least minimized, by prior laboratory testing. Deferred oil is an intrinsic problem in well intervention. The improved production must pay for the deferred oil.
Permanent decreases in production after inhibitor squeeze treatments are usually associated with pumping large amounts of water-based chemicals into water-sensitive zones, assuming an otherwise proper treatment design and the use of clean fluids. Clay swelling and in-situ emulsions are damage mechanisms; low pH-inhibitor solutions are often detrimental to clays, in particular to chlorites. Handling the scale inhibition of water-sensitive reservoirs is not a solved problem. Several routes are being investigated. One solution is the use of oil-soluble inhibitors. Another is the use of water-in-oil emulsion (“invert emulsions”), similar to the invert emulsions used for time-delayed acidization. A third solution is the use of a mutual solvent preflush. Here, the mutual solvent is the first chemical seen by the sensitive formation, and it is the last seen as the well is put back on production. Also used are “clay stabilizers” in the preflush. As of this writing, no single approach solves all problems.
New inhibitor chemistry is also being developed to handle the harsher scaling environments such as particularly high supersaturated barium sulfate solutions (saturation indices > 350). A case in point is the barite scaling problem in the North Sea Miller field. “Harsh” conditions also include HT/HP reservoirs with severe thermal stability requirements.
Well intervention to place the scale inhibitor is particularly costly with high-volume wells because of large amounts of deferred oil; intervention at remote locations (e.g., offshore platforms and subsea completions) adds to the cost. It is often possible to place a scale inhibitor as part of the scale-removal step, providing both treatments with one setup and intervention. One of these techniques is the inclusion of a scale inhibitor with the acid stimulation process for dissolving calcite scale. The advantages are in cost and in putting the inhibitor into exactly the same zone opened up by the acid treatment.
A second dual-treatment technique consists of placing a scale inhibitor along with a hydraulic fracture stimulation. Inhibitors can be injected into the pumped gel/sand mixture with calcium ion to form a sufficiently insoluble and immobile scale-inhibitor material within the proppant pack. DTPMP acid (Fig. 11) has been used, as well as polyphosphates. Other inhibitor formulations can generate a “glaze” on the proppant pack. The concept has been effective with calcite and barite scales. This technology has been practiced since the early 1990s on the Alaskan North Slope and, more recently, in west Texas; lifetimes of nominally two years are now claimed. Shown in Fig. 5 are return curves for such a treatment together with a return curve for a conventional squeeze. Here, lifetime is expressed in terms of quantity of water protected from scaling. There are also a few important ancillary advantages to the method greater than extended lifetime—the well returns to production faster because adsorption time shut-in is not required, and there is little opportunity for changes in the formation wettability and its attendant problems. The concept is illustrated schematically in Fig. 6.
Fig. 5—Inhibitor return curves for two Permian Basin wells treated with inhibition/fracturing technology and a companion well treated by a conventional squeeze (after Wigg and Fletcher).
A newer, dual-treatment technique consists of deploying an inhibitor impregnated into porous ceramic proppant along with conventional proppant in hydraulic fracture stimulation. Upon production, any water flowing over the surface of the impregnated proppant will cause dissolution of the scale inhibitor. Dry oil will not release the inhibitor from the beads or the insoluble inhibitor. Field examples of this technology are given in Webb, et al. and Norris, et al. The advantages are similar to those of the nonencapsulated inhibitor/frac concept already discussed but with a potentially longer lifetime (e.g., 4 years). This comes at an additional cost that must be offset by savings in deferred oil and setup/intervention costs. The targets are high-volume wells in remote locations, such as the North Sea and deep Gulf of Mexico. Both inhibitor/proppant techniques also protect the fracture itself from plugging with scale. This scaling occurs primarily when incompatible waters mix near the wellbore.
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- Collins, I.R. 1997. Scale Inhibitor Impregnated Particles—Field Applications? Paper presented at the 1997 IBC Solving Oilfield Scaling Conference, Aberdeen, 22–23 January.
- Webb, P.J.C., Nistad, T.A., Knapstad, B. et al. 1999. Advantages of a New Chemical Delivery System for Fractured and Gravel-Packed Wells. SPE Prod & Oper 14 (3): 210-218. SPE-57421-PA. http://dx.doi.org/10.2118/57421-PA.
- Norris, M., Perez, D., Bourne, H.M. et al. 2001. Maintaining Fracture Performance through Active Scale Control. Presented at the International Symposium on Oilfield Scale, Aberdeen, 30–31 January. SPE-68300-MS. http://dx.doi.org/10.2118/68300-MS.
Noteworthy papers in OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
Jamaluddin, Abul. 2013. Flow Assurance – Managing Flow Dynamics and Production Chemistry. https://webevents.spe.org/products/flow-assurance-managing-flow-dynamics-and-production-chemistry-2
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro