Acid Placement and Diversion
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The flow of fluids through these pores is often restricted because of permeability damage in the near-wellbore (NWB) formation. During matrix acidizing, the acid treatment is injected at matrix pressure and staying below formation fracture pressure. Matrix acidizing of carbonates and silicates are worlds apart.
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Acid Placement and Diversion
- 1. Acid Placement and Diversion Behzad Hosseinzadeh 1Spring 2015 Number of slides : 33Supervisor: Dr. Aghighi
- 4. Introduction Two Reason Why Acid Treatments Fail Acid-removable damage is not present If it is present it is not fully contacted o Acid does not go where it needs to go 4Before acid treatment After acid treatment (without diverter)
- 6. Acid Placement Objectives of Acid Placement and Diversion 1. Coverage of the production or injection interval(s) targeted for acid treatment 2. Distribution (spread) of the acid treatment in the formation. 6
- 7. Acid Placement, In The WellBore Methods 1. Bullhead injection (MAPDIR Method) 2. Mechanical placement 3. Chemical diversion 4. Protective Injection Maximize Coverage … Minimize Volumes 7
- 8. Methods The MAPDIR Technique • maximum pressure differential and injection rate • This was first introduced by Paccaloni and Tambi • Referred to as Paccaloni’s method • limited zone height, length and permeability variation • Openhole, or liner completions in single or multiple zones, as well as in thin zones 8
- 9. Mechanical Methods Packer / Bridge Plug. • The surest way to place fluid • Earliest mechanical method • Retrievable and Permanent • Types • Cup type packers • Mechanical packers • Inflatable packers • Expensive • Need kind of intervention, such as a workover 9
- 10. Mechanical Methods Ball Sealers • Most widely used • More economic • Overcome drag forces • Suitable for high permeability contrast • Efficiently in vertical wells. • larger than perforation • Rubber or Biopolymer 10
- 11. Mechanical Methods Ball Sealers • Type • Sinkers (non-buoyant balls) • Floaters (buoyant balls) • Neutral buoyant 11 Floaters Neutral Sinkers
- 12. Mechanical Methods Jetting • The acid can be placed directly at the point where it is needed. • Ease with which an acid injection can be terminated • Most completions • With foam provides excellent zone coverage • Rotary action required • For perforation coverage • For screen or open hole coverage 12
- 14. Chemical Methods Chemical Diversion • The more commonly used chemical diverters today include: 1. Salt granules • Low solubility in strong acid but soluble in formation water • Not be used in a formation that does not produce water • Combined particulates, such as graded rock salt and benzoic acid • Work best in perforated casing and with medium permeability contrast. 14
- 15. Chemical Methods Chemical Diversion 2. Benzoic acid • The most broadly applicable diverter type • Has limited solubility in both oil and water • It has the ability to sublime directly into its gaseous state, above about +/- 230 °F. • Benzoic acid particulates are typically added to water or acid- based carrier fluids (a surfactant may be required for dispersal) • Removal is either by slow dissolution in produced oil (preferred) or water, or through sublimation at higher temperatures. 15
- 16. Chemical Methods Chemical Diversion 3. Waxes • These materials are usually removed from the well by either the action of temperature, dissolution in liquid hydrocarbons or both. 4. Oil-soluble resins (OSR) • Are not as popular today as they used to be 5. Gilsonite • Naturally-occurring asphalt material 6. Fiber • Effective diverting agents for both matrix and fracture treatments 16
- 17. Chemical Methods Chemical Diversion 6. Foam • It is useful in gravel pack completions 7. Viscous pills • Polymer gels, such as hydroxyethylcellulose (HEC) • Which can provide sufficient diversion • Remaining gel residue in perforations can block flow. • A separate treatment may have to be conducted to remove the gel. 17 The major benefit of foams and gels relative to particulates is their reversibility.
- 20. Diversion Methods Acid Fracturing Treatments • Many of the techniques described in the preceding sections also can be applied to acid-fracturing operations. • Mechanical isolation methods work particularly well, although this often involves extra expense, such as for a workover or for specialized completions. 20 • This often is accomplished with the use of diversion stages programmed into the treatment schedule, effectively breaking up a large treatment into several smaller ones.
- 21. Acid Diversion in the Formation In-situ diversion • In-situ diversion is also necessary and quite important in both matrix and fracture acid treatments. 21
- 22. Acid Diversion in the Formation Foam • Foam is a two-phase, gas-in-liquid emulsion consisting of a liquid external phase and a gaseous internal phase. • They observed that successful diversion can be expected for permeability ratios less than 10:1. • A surfactant is required to keep the foam stable until it enters the formation. • Work better in higher-permeability formations. • Oil tends to destroy foams 22
- 23. Acid Diversion in the Formation Foam 23
- 24. Acid Diversion in the Formation Foam 24
- 25. Acid Diversion in the Formation Self-Viscosifying Acids (SVA) • Has three specific components: 1. Gelling agent 2. Crosslinking agent (Fe, Al, Zr) 3. Breaker • no H2S and permeability greater than 50 md. 25
- 26. Acid Diversion in the Formation Self-Viscosifying Acids (SVA) 26 Live partially neutralized, spent acid
- 27. Acid Diversion in the Formation Self-Viscosifying Acids (SVA) 27
- 28. Acid Diversion in the Formation Viscoelastic surfactant systems (VES) • VES systems designed for matrix or acid fracturing operations exhibit viscosity as a function of acid strength 28
- 29. Acid Diversion in the Formation Viscoelastic surfactant systems (VES) 29
- 30. Acid Diversion in the Formation Comparing VES - SVA • Why do we use VES instead of SVA? 1. No residue 2. Completion brines 3. No damage 30
- 31. Acid Diversion in the Formation Viscous Fingering Relies on viscosity contrast between acid and non-acid fluids 31
- 33. References 1. L.J. Kalfayan, The Art and Practice of Acid Placement and Diversion: History, Present State and Future, 2009 2. Ragi Poyyara, Optimization of Acid Treatments by Assessing Diversion Strategies in Carbonate and Sandstone Formations , 2014 3. Leonard J. Kalfayan, The Art and Practice of Acid Placement and Diversion, 2005 4. Leonard Kalfayan, Production enhancement with acid stimulation, 2nd ed, 2007 5. Javier Ballinas, Weatherfird, Viscous Fingering Stimulation Option Applied on Heavy-Oil Carbonate Reservoirs, 2014 6. M.G. Bernadlner, Effect of Foams Used During Carbonate Acidizing, 1992 7. Liang Jin, Optimising Diversion and Pumping Rate To Effectively Stimulate Long Horizontal Carbonate Gas Wells, 2007 8. G. Glasbergen, Design and Field Testing of a Truly Novel Diverting Agent , 2006 33
Editor's Notes
- The flow of fluids through these pores is often restricted because of permeability damage in the near-wellbore (NWB) formation. During matrix acidizing, the acid treatment is injected at matrix pressure and staying below formation fracture pressure.
- Matrix acidizing of carbonates and silicates are worlds apart. sandstone acidizing, the reaction between HF and sandstone is much slower. In sandstone formations, matrix acidizing treatments should be designed primarily to remove or dissolve acid-removable damage or plugging in the perforations and in the formation pore network near the wellbore. Matrix treatment of an undamaged formation cannot be expected to significantly increase production. In carbonate formations, matrix acidizing works by forming conductive channels, called wormholes, through the formation rock. These penetrate beyond the near-wellbore region, or extending from perforations. If a carbonate formation is undamaged, a matrix acidizing treatment probably cannot be expected to do more than double the production rate.
- Determination of the proper fluid placement is perhaps the most crucial factor in acid treatment design in both carbonates and sandstones. Treatment success can hinge on it. A well-conceived, properly designed treatment in all other respects (formation damage assessment, selection of acid types, concentrations, volumes, additives) can go for naught if the treatment is not properly placed. The zone of interest must be sufficiently contacted by stimulation fluids.
- Without any modification of the flow path, where will most of the acid go? => Along the path of least resistance How do you treat the other zones? => Make the high permeability zones harder to enter or the low perm zones easier to enter. Remember! The blockage must be temporary unless the high perm zones have watered out. chemicals are used to create temporary plugging against high-permeability fractures, channels, vugs and fissures while the acid is diverted to low-permeability zones In first picture (left) which tools can help us to move acid in proper zone? Heterogeneities: • Varying permeabilities in different interval sections or zones • Varying degrees of formation damage • Varying reactivities to acid • Varying formation pressures • Varying fluid viscosities • Presence of natural fractures • Combinations of the above Most are a result of the height or length of the zone(s) to be treated, which can be hundreds or even thousands of feet, as is often the case in horizontal well completions.
- The first has to do with placement in the wellbore, whilst the second has to do with diversion in the formation.
- Unless steps are taken to promote efficient acid placement, the stimulation fluids will tend to follow the path of least resistance, meaning the acid will preferentially pass into the interval with the highest conductivity. Often, this section of the well requires the least stimulation. flow of acid to a path of least resistance is exacerbated by reactivity of acid with the formation.
- (injection rate) – increase while maintaining maximum matrix injection pressure differential (p iw – p e ). (acid viscosity) – increase chemically with polymer gelling agent, surfactant viscosifying agent, foam. h (portion of interval treated at any given time) – mechanically isolate sections of zone with packers, selective acidizing tools (coiled tubing with jetting nozzle injection provides the smallest h). s (temporary skin) – create temporary local skin in portions of interval already acidized – with ball sealers or stages of solid chemical diverters. MAPDIR calls for pumping acid treatment stages at as high a rate as possible, but below fracturing pressure. It is postulated that by maintaining maximum allowable matrix injection pressure, the need for diversion is greatly reduced. It has come under some criticism in recent years because of its inherent limitation in maximizing treatment interval coverage through acid injection rate only. Main problem: This is also the case where permeability varies substantially across the treatment zone, and maximum matrix injection rate is not high enough to prevent complete fluid entry into the high permeability paths of least resistance.
- Bridge Plug: A downhole tool that is located and set to isolate the lower part of the wellbore. If the fluid is mechanically blocked from the path of least resistance, then it will have no alternative but to follow the only path presented to it. The two main types are retrievable, which are designed to come back out of the wellbore after the treatment has finished, and permanent, which can only be removed by drilling or milling. Packers. Like bridge plugs, packers come in several different varieties, but they all have similar features and methods of operation. function as a direct opposite of a bridge plug, i.e. to prevent fluid flow above the tool, allowing injection of stimulation fluid function as a direct opposite of a bridge plug, i.e. to prevent fluid flow above the tool, allowing injection of stimulation fluid. they can be expensive. Some kind of intervention, such as a workover, is usually required.
- Perforation ball sealers are likely the most widely used mechanical diversion method in perforated wells much more economic than conventional packers To divert the ball sealer to the perforation, the inertial force of the ball must overcome the drag forces created by the fluid velocity through the perforation. the pressure in the wellbore is greater than the pressure in the perforation. Once the treatment is completed, pressure is bled off rapidly at the surface in order to “surge” the balls from the perforations Balls either flow back during production Modern ball sealers are rubber (typically RCN – rubber-coated neoprene) or biopolymer. the ball is sized to be larger than the perforation Effective ball sealing action is a function of injection rate. Ultimately, ball sealers are most effective in newer wells with a limited number of perforations. Furthermore, the nature of the perforations has an effect on ball sealing efficiency. The efficiency of a ball sealer depends on its seating efficiency, which in turn depends on the following Density contrast between the ball and the fluid Flow rate through the perforation Flow rate past the perforation Fluid viscosity Differential pressure to hold a ball once seated
- Ball sealers generally work efficiently in vertical wells.
- Overall, CT is very effective in placing acid, especially during smaller treatments and treatments for damage within inches of the wellbore. Coiled tubing (CT) is a very useful tool for improving acid placement. Ease with which an acid injection can be terminated, if it appears that continuing injection is not doing any further good. The total volume in the CT string is small and can be quickly displaced. Ability to attach injection nozzles for full interval treatment, or selective (hydrocarbon-producing) zone treatment, such as in wells with high water cut. Pump rate limitations. Smaller diameters cause higher friction pressures, which may limit treatment injection rates to lower-than-desirable levels. Corrosion in a CT string is especially disastrous Overall, CT is very effective in placing acid, especially during smaller treatments and treatments for damage within inches of the wellbore.
- The first attempts at acid treatment placement used chemical “diverting” additives
- Salt (NaCl) has relatively low solubility in strong acid systems but is readily soluble in formation water. Salt should not be used in a formation that does not produce water, as water production is the mechanism for removal. Degradable particulates, as the name suggests, are chemical particulates that, when sent downhole along with the stimulation fluid, will enter higher permeability regions and create a very low permeability cake on the formation face or a low permeability plug just inside the perforations in the pipe, in the NWB region. The added pressure drop caused by this cake increases flow resistance in the areas where diverting agents have been deposited, causing diversion of flow to other parts of the interval where little or no diverting agent has been placed. Particulates might not work effectively in zones of high permeability and high pore throat because the particle size might not be large enough to block the pore throat. Until now, the most basic desire was that the diverting agents be relatively insoluble in the treatment fluids and dissolve readily in the produced or injected fluids. The problem with this approach is that it is often difficult to contact all of the material that has been placed and achieve uniform cleanup.
- Rock salt is water soluble and keeps its mechanical integrity in the oil phase, while benzoic acid is oil soluble.
- OSR use is limited because the melting point is more than 300 °F. Therefore, removal must typically be entirely from dissolution in produced oil. If that is not accomplished, a separate solvent treatment must be pumped to remove the diverter. Other degradable diverters, such as forms of benzoic acid and wax beads, are therefore preferable because of their lower melting points. Gilsonite begins to soften around 195 °F and has a melting point of 300 °F, so it is recommended for use between these temperatures. It is recommended for formations that produce liquid hydrocarbons; in other wells, a post-treatment hydrocarbon solvent wash (such as with xylene) should be performed.
- Foam: It is useful in gravel pack completions, for example, where particulates do not pass well (or not at all) through the pack or through screen slots to the formation face. Generally, foam is more effective in high-permeability formations with deeper damage. Generally, foam is more effective in high-permeability formations with deeper damage. Viscous pills. Polymer gels, such as hydroxyethylcellulose (HEC), as a “pill” or “slug” injected downhole, will exhibit viscosity-controlled leak-off, which can provide sufficient diversion. However, if gel diverter does not break and clean up completely, remaining gel residue in perforations can block flow. Diversion with particulates is not necessarily easily reversible.
- This process involves the injection of an inert fluid into the most conductive interval, whilst at the same time injecting the acid system into a less conductive zone the interval to be treated with acid is located toward the heel end of an openhole horizontal wellbore, with the most conductive interval located further toward the toe of the well. The protective fluid is injected down the tubing and into the wellbore, flowing into the formation and into the most conductive interval, at a rate determined to produce no significant injection into the upper interval. Acid is then pumped down the tubing/casing annulus. The protective injection forces the acid into the less conductive, upper interval. The tubing is positioned so as to be just below the zone requiring the acid. If the zone requiring stimulation is toward the bottom of the well, then the fluid flow is reversed, with the protective fluid coming down the annulus and the acid being placed through the tubing (as illustrated in the lower part of Fig. 1). Sometimes, a large-diameter nipple profile is included on the outside of the tubing, positioned at the desired boundary between the two fluids, to further promote isolation of the two wellbore areas. A more sophisticated version of this technique employs foam as the protective fluid
- These diverters are particularly effective because of the often high viscosity of the fracturing fluid (which helps to carry the diversion system) and the high rates experienced when fracturing (which enables the diversion technique to block perforation tunnels or plate off openhole sections more easily).
- The previous two sections of this paper dealt with the diversion of stimulation fluids within the wellbore – for the purposes of efficiently distributing stimulation fluids over long perforated intervals, multiple perforated intervals or along openhole wellbores. This section addresses diversion once the stimulation fluids have exited the wellbore and have begun to stimulate the formation. Important because: Divert acid beyond the near-wellbore formation region, thereby increasing live acid penetration. Divert acid away from high-conductivity areas (which may require the least stimulation) toward low-conductivity areas (which may require the most stimulation). (فرض کنیم اگه مخزن دارای شکستگی باشه یا واگی شکل نیاز به این روش احساس میشه) Diversion in the formation is especially important in carbonate acidizing and it is addressed with a variety of methods, most of which utilize fluid viscosity Mild HF systems or moderated reaction rates can increase distribution of acid within the formation.
- Foams can be used for diversion in both sandstone and carbonate matrix stimulation, and in acid fracturing Although foam is a wellbore diversion method, it is also an in-situ diversion method. The effects produced by foam are a result of its relative inability to pass through porous media, this producing a pressure rise as it enters the formation. Bernard and Holm (1965) were the first to indicate that foam could selectively block high-permeability zones (or less damaged zones) Thompson and Gdanski (1993) concluded that foamed acid diversion is limited by the permeability contrasts in the formation. They observed that successful diversion can be expected for permeability ratios less than 10:1. In addition, because the individual gas bubbles are generally larger than the pore throats, energy is required to force them from being spherical to being elongated. This requirement for extra energy increases the injection pressure. If this increase in pressure is large enough, fluid behind the foam is diverted elsewhere. a foaming agent is required if the foam is to acquire sufficient stability. Foam diversion tends to work better in higher-permeability formations. This is because the foam bubbles have greater ease of entry to the formation when the pore throats are larger. Decreasing average bubble diameter will increase effectiveness in lower-permeability formations. Oil tends to destroy foams by disrupting the surface tension effects required to maintain stable foam. This effect can be used to target acid preferentially at oil-bearing formations (Jensen and Friedman 1986). Mutual solvent pumped ahead of the foam diversion stage can help prolong foam life in such formations. Foams mixed with a viscous water phase tend to have greater stability and diversion capability than those mixed with non-viscosified water. Foam is generally produced by injecting nitrogen into fluid containing a surfactant. Foamed fluids break down and become ineffective quite quickly (usually in less than an hour), so they are often mixed with polymer gelling agents to increase stability and improve rheology.
- This study investigated a method of in-situ foam generation that allows deeper wormhole penetration yet uses less acid than conventional methods.
- This study investigated a method of in-situ foam generation that allows deeper wormhole penetration yet uses less acid than conventional methods. The foam structure by itself, however, should improve the stimulation performance by preventing loss of aqueous acid to the side walls.
- These systems may be used in carbonate formations during matrix or fracture stimulations. The first component is a gelling agent designed to give the acid system 20 to 30 cp at bottomhole conditions. Gelling agents are typically from the polyacrylamide family The second component is a crosslinking agent, typically a zirconate, selected so that the crosslinking mechanism will not work at the low pH of the acid system before neutralization The third component is a breaker, usually a low-solubility or delayed-release source of fluoride ions (such as encapsulated calcium fluoride, CaF 2 ). As the SVA stage reacts with the formation and neutralizes, the crosslinker will start to become effective, producing a dramatic increase in viscosity Because this increase in viscosity happens right where the formation has been stimulated, this system is extremely effective under the right circumstances. Finally, once the treatment is over, the fluoride breaker (and for some systems the continuing increase in pH as the acid reaches complete neutralization) reduces the viscosity of the system so that it can flow back out of the formation.
- When hydrochloric acid is injected into a formation it has a pH of nearly zero. The pH of the acid increases as the acid reacts with the carbonate rock. At a pH value of approximately 2, it is claimed that the polymer reacts with the iron (III) crosslinker and forms a very viscous gel. At pH 2, it is nearly completely spent. The viscosity of the acid can reach 1,000 mPa.s and is able to divert unreacted acid into other zones in the formation. At pH values greater than 4 to 5 the viscosity of the gel is claimed to decrease as the polymer and crosslinker dissociate reducing iron (III) to iron (
- VES systems designed for matrix or acid fracturing operations exhibit viscosity as a function of acid strength Viscoelastic surfactant systems (VES) use specialized surfactants to produce an increase in viscosity as the acid neutralizes, سورفکتانتها کشش سطحی آب را بوسیله جذب سطحی فصل مشترک هوا – آب کاهش میدهند همچنین باعث کاهش کشش فصل مشترک آب و روغن بوسیله جذب سطحی فصل مشترک مایع- مایع میشوند تعداد زیادی ملکول سورفکتانت میتوانند در توده محلول به هم وصل شده و تشکیل تودهای به نام میسل (micelle) میدهند. به غلظتی که در آن این میسلها شروع به تشکیل شدن میکنند غلظت بحرانی تشکیل میسل CMC گویند وقتی میسلها شروع به تشکیل شدن کردند دم آنها تشکیل یک هسته مانند یک قطره روغن و سر یونی انها یک پوسته بیرونی میسازد که تماس مطلوب با آب را بهبود میبخشد. Surfactants (SURFace ACTive AgeNTS) tend to congregate at the interfaces between materials. Surfactants used in water-based systems tend to have an ionically-bonded head and a covalently-bonded tail. Consequently, they orient themselves at the surface of the water with the tails facing outwards, away from the water. As the concentration of surfactant increases, eventually a point is reached where no more surfactant molecules can be positioned at the fluid boundary. At this point, the surfactant forms spherical micelles, with the tails facing inward. If surfactant concentration increases even further, the micelles start to interact with each other, to form elongated structures which will impart viscosity to the fluid system. This concentration is called the critical micelle concentration (CMC). The point at which the CMC occurs is a function of pH, temperature and surfactant concentration, as well as the concentration of certain salts used to promote CMC propagation. At even higher concentrations of surfactant, increasingly complex structures (referred to as vesicles) will impart even more viscosity. One significant feature of VES fluids is that they tend to be very shear-sensitive. This means that whilst they have very high apparent viscosity at low or zero shear, during pumping they exhibit very low friction pressure. These characteristics are ideally suited to this application. These systems are also broken by contact with oil or by changing the internal brine concentration (such as when mixed with formation water). When an acid is injected through a wellbore it reacts with the rock formation causing the pH of a system and cation (such as Ca2+ and Mg2+) concentrations to increase. (as afunction of dissolved chloride ion and pH)
- Why do we use VES instead of Polymer-based fluid? Polymer can do the same job instead of VES!!! polymer-based fluids is that they leave a polymer residue in the formation. Has a different rheological properties formation of the wormlike micelles depends on the change in the surfactant packing parameter The VES is compatible with a wide range of completion brines, like CaCl 2 , CaBr2, KCl, and NH4C; causing no damage to the formation
- In this technique contrasts in viscosity (and to a lesser extent, density) are used to preferentially place the acid. The fracture is created with a pad fluid that has viscosity at least 50 cp greater than the non-viscous acid that follows it After the fracture is created, the low-viscosity acid channels through the viscous pad, rather than displacing it over a broad front. This technique produces much more efficient use of the acid, as it tends to be placed exactly where it is needed.