9. STIMULATION BY ACIDIZING
Contents
EXECUTIVE SUMMARY ... 9-1 9. STIMULATION BY ACIDIZING ... 9-3 9.1 Introduction ... 9-3 9.1.1 Objectives of Well Stimulation by Acidizing ... 9-4 9.2 Well Acidizing Stimulation Technology ... 9-4 9.2.1 Total Skin factor and its use in OMV Petrom for Making Decision for Acidizing ... 9-5 9.2.2 Best Candidate Selection Process for Acidizing ... 9-7 9.2.3 Review of the Most Frequent Damages in OMV Petrom and General Selection of
Treatment ... 9-7 9.3 Well Acidizing Methods Applied in OMV Petrom ... 9-10 9.3.1 Sandstone ... 9-13 9.3.2 Carbonate ... 9-15 9.4 Technology Workflow of Best Practices for Fluid Selection, Treatment Design and Job
Execution ... 9-18 9.4.1 Sandstone Matrix Acidizing Treatment ... 9-18 9.4.2 Applied Sandstone Design Procedure ... 9-29 9.4.3 Carbonate Acidizing Best Practices ... 9-36 9.4.4 Planning and Job , Execution of Acidizing Treatment ... 9-45 9.4.5 Job Evaluation and Control ... 9-48 9.5 Configuration of Surface Equipment for Acidizing ... 9-52 9.6 Fluids and Materials Used for Acidizing ... 9-53 9.6.1 Additives (corrosion inhibitors, Iron-Control Agents, Clay Stabilizers etc) ... 9-53 9.7 Quality and Safety Requirements for Acidizing ... 9-54 9.7.1 Quality Control ... 9-54 9.7.2 Health, Safety and Environmental Aspects of Acidizing ... 9-57 9.7.3 Personnel (Training, Supervision) ... 9-59 Appendix 9-A Commercially Available Acid Systems Specification Details... 9-60 Appendix 9-B Commercially Available Additives and Solvent Specifications ... 9-66 List of Figures ... 9-70 List of Tables ... 9-72
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EXECUTIVE SUMMARY
EXECUTIVE SUMMARY: 9. STIMULATION BY ACIDIZING
No.
Strongly Recommended
1.
Review the well logs, reservoir characteristics and previous workovers to identify shortlist candidates with damage to the wellbore, in the perforations and / or within the formations. Clarify the factors causing skin damage on shortlist candidates and determine which near wellbore flow restrictions can be removed by acid treatment.
2. Involve careful consideration of fluid selection, the pumping schedule, acid placement techniques and on-site treatment monitoring.
3.
Use developed workflows (Figure 9-10 to Figure 9-16) for proper fluid selection required for sandstone acidizing.
Mineral Composition > 100 mD 20-100 mD < 20 mD <10% Silt and < 10 % Clay 15% HCl 10% HCl 7.5% HCl >10% Silt and >10 % Clay
>10% Silt and < 10 % Clay >10% Silt and > 10 % Clay
10% HCl 7.5% HCl 5% HCl
4. Reduce the concentration of the HCl if the formation is partially or totally dolomite and should be lowered wherever silicate content of the dolomite is high in order to avoid precipitation. Follow selection workflow in Figure 9-20.
5. In case of high bottomhole temperatures use slower reacting weak organic acids. Special attention should be paid to the concentrations of formic acid to avoid precipitation of calcium formate.
6. Use retarded HCl (by gelling or emulsifying the acid), or organic acids if bottomhole temperature is high (>120 oC).
7. The cleanliness of all tanks that will hold water or acid should be verified and the acid tank must be circulated before pumping. 8. Mix chemicals in recommended sequences.
9. Always keep foam quality above 70%.
10. Carry out acid pickling of tubing string for all important (costly) jobs.
11. Put the well into production immediately (no reaction break) in high temperature wells. 12. Use nitrogen displacement for gas wells.
13. Use diverting for long (> 25 m) perforated intervals.
14. Use HBF4 when problems with migrating fines exist, what is often case in the maturated wells completed with gravel pack. 15. Verify availability and specifications of all fluids (additives, acid, surfactants, diverters) required to complete the stimulation job 16. The injection rate and pressure is to be monitored and the pressure kept below predefined levels (especially breakdown pressure in sandstone). 17. Fluids pumped during the stimulation job are to be sampled and analysed for post-treatment review.
18. Real-time formation response to stimulation fluids should be recorded in a Field-Acid-Response-Curve (FARC) to enable swift corrective action to be undertaken during the treatment job.
19.
Use standardized treatment report which describes fluid QC data, pump rates, tubing and annular pressure measurements, types and volumes of fluids and diverters, deviations from the program, pumping interruptions and any other problems which influenced the execution of the treatment job.
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EXECUTIVE SUMMARY: 9. STIMULATION BY ACIDIZING
No.
Not Recommended at All
1. To exceed frac pressure during treatment operation. 2. To use HF + KCl or formation brine.
3. If doing foam injection frac pressure is reached do not decrease foam quality, just stop nitrogen. 4. To start treatment if all fluids which are pre-blended at the service company facility are not subjected to quality checks. 5. To use diverting for short (< 25 m) perforated intervals.
6. To use mud acid to treat formations if HCL solubility is > 20%. 7. To start acidizing treatment if sufficient injectivity is not obtained. 8. To use of HCl preflush after dry tests in exploratory/wildcat wells.
9. To continue the treatment if the surface pressure rises sharply or rises continuously for certain volume of acid (0.5-1m3). 10. To delay the well shut-in time after acidizing treatment in order to minimize precipitation of reaction product. 11. To use NaCl, KCl, or CaCl2 brines in any HF treatment stages or in any stage immediately preceding or following HF stages.
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9. STIMULATION BY ACIDIZING
9.1 Introduction
There are two basic stimulation methods which can be used to eliminate formation damage and increase well productivity: matrix acidizing and fracturing (hydraulic and acid).
Matrix stimulation by acidizing is injecting an acid/solvent at below the fracturing pressure of the formation in order to dissolve/disperse materials that impair well production in sandstone reservoirs or to create new unimpaired flow channels in carbonate reservoirs.
In the case of injecting acid below the fracturing pressure the injected acid dissolve some of minerals present, and hence, reestablish or increase the permeability inner-wellbore vicinity (not deeper than 0.1 to 0.3m in sandstone reservoir and 1 to 3 m in carbonate reservoirs). Matrix acidizing can significantly enhance the productivity of a well when near-wellbore formation damage is present, and conversely, is of little benefit in an undamaged well. Thus, matrix acidizing should generally be applied only when a well has a high skin effect that cannot be attributed to partial penetration, perforation efficiency, or other mechanical aspects of the completion.
The most common acids used in OMV Petrom are hydrochloric acid (HCl), used primarily to dissolve carbonate minerals, and mixtures of hydrochloric and hydrofluoric acids (HF/HCl), for attacking silicate minerals such as clays and feldspars. Other acid formulations, particularly some weak organic acids, are used in special applications.
Acid fracturing, resulting from the injection of fluids at pressures above the formation fracture/parting pressure, is intended to create a path of high conductivity by dissolving the walls of the created fracture in a non-uniform way. Acid fracturing is sometimes used to overcome formation damage in relatively high-permeability formations. However, carbonate reservoirs of relatively low permeability may also be candidates for acid fracturing. In acid fracturing, the reservoir is hydraulically fractured and then the fracture faces are etched with acid to provide linear flow channels to the wellbore.
Acid fracturing of relatively homogenous carbonates will produce smooth fracture faces that will retain little fracture flow capacity when treating pressure is released. Acid fracturing of heterogeneous carbonates can develop non-uniform etching of the fracture face. The area that is not etched acts as a support for the etched areas, thus providing flow channels in the fracture and significant increases in well productivity. It is suggested that laboratory tests be conducted on cores to determine the etching characteristics of the rock before treating a well. In some instances, the non-etched area of a heterogeneous carbonate will be softened by acid and will not support the fracture when treating pressure is released. The only alternative would be hydraulic fracturing and propping with sand. Two other problems can exist in acid fracturing: (1) Un-dissolved fines can significantly reduce fracture flow capacity if not removed with spent acid and suspending agents, usually surfactants or polymers will materially aid in the removal of these fines (2) Emulsions can block the etched fracture. API RP 42 tests should be performed to select an emulsion preventing surfactant for the acid treatment.
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Acid fracturing is rarely used in the treatment of sandstones, because acid, even hydrofluoric acid (HF), does not adequately etch these fracture faces. However, treatments have been successful in some sandstone formations containing carbonate-filled natural fractures. Removal of these carbonate deposits often results in sufficient conductivity to yield excellent treatment results.
The results of field studies in Sotanga Meoţian, Targoviste Răsvad Gura Ocnitei Meoţian III, Calinesti Dacian, Moreni, Gura Ocnitei and South Dacian, which are in an maturated/advanced stage of production consisting mostly of high permeability sand layers with high variation of stability (good to poor ) have been used in formulating the stimulation acidizing best practices in OMV Petrom.
9.1.1 Objectives of Well Stimulation by Acidizing The key objectives of well acidizing in OMV Petrom are to:
• Remove near wellbore formation damage and decrease skin factor • Restore damaged matrix permeability in near well-bore reservoir area • Improve matrix permeability in near well-bore reservoir area
• Maximize well productivity
• Remove deposits from well tubular/wellbore cleanout.
The improvement in productivity of wells that can be realized with matrix stimulation as shown in
Figure 9-1 The plot shows that acidizing is more effective in restoring the original permeability by removing formation damage, than in increasing permeability over its original value. This is used as principal guidance in the company for selecting the best well candidate for application of stimulation by acidizing.
9.2 Well Acidizing Stimulation Technology
In sandstone formations, acid treatments aim to remove near-wellbore flow restrictions and formation damage. The goal of these treatments is to return the near-wellbore area to its natural condition. In carbonates, dissolving matrix is one of the objectives, but bypassing a damage of the nearwellbore by creating new channels is the primary target.
Usually, wellbore damage is caused by drilling or completion operations, fines migration, clay swelling or polymer plugging. To select an optimized fluid system for effective stimulation, the type of damage and the formation mineralogy must be known. The structured process of the design of a well acidizing stimulation job the following main phases:
1. Candidate selection and proper diagnosis of damage type - The best candidate well for a stimulation treatment is selected, regardless of the type of stimulation/remediation needed. Candidates are wells with damage to the wellbore, in the perforations and / or within the formations which is acid-removable. If the damage is not acid-removable, then it should not be acidized and is not a candidate. During this phase, the best treatment for the type of damage must be determined by assessing and, ideally, measuring the skin. The economically most attractive candidate is then selected based upon expected production gains.
2. Fluid selection - The appropriate fluids, acid types, concentration, treatment volumes and additives are selected. Careful thought should be given to the determination of appropriate additives and combinations for each case.
3. Pumping schedule and execution sequences - The number of stages and how much to pump in each stage (volumes, rates and time) are determined.
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4. Acid placement and techniques - detailed simulation of the acidization process using the planned pumping schedule should be undertaken, including diversion. A major reason for unsuccessful acid treatments is that the acid does not go where it needs to go. Determination of the proper fluid placement method is thus a key factor in acid treatment design in both carbonates and sandstones. 5. Treatment monitoring, quality control and on site evaluation -The actual skin changes resulting from the stimulation treatment are compared to the predicted results. Quality control steps (during rig-up, before pumping, during pumping and flowback) should be implemented.
9.2.1 Total Skin factor and its use in OMV Petrom for Making Decision for Acidizing The skin is an important factor to decide whether or not to stimulate a well and what generic type of treatment would be most suitable. Since it represents the total additional pressure drop as compared to ideal conditions, in the near-wellbore region, its value is the combined effect of several parameters, including formation damage. To properly interpret the skin and therefore determine the appropriate remedial action, field engineers must analyze the contribution of each factor. This analysis should involve identifying skin damage which could be removed by stimulation and may result in additional opportunities for production improvement such as re-perforating. Candidate identification therefore requires an understanding of the various skins and recognizing skin damage. The production of newly completed well or worked-over well may be lower than expected, due to wellbore damage from the drilling/completion/workover process, or by mechanical difficulties in the overall completion process. All of these problems will result in an additional pressure drop near the wellbore, and thus affect the skin factor. Therefore, the key to candidate selection lies in the analysis of the various skin components. In Table 9-1 these skin component characteristics are summarized. Table 9-1 Summarized skin components
Skin Components Characteristics
S Total skin factor (Horner skin)
Sdam Skin caused by formation damage (positive). It is the component that needs to be removed with the matrix treatment.
Spart
Skin caused by limited perforation height (positive). It results from the well not being perforated over the complete reservoir height, such as to minimise gas or water coning.
Sdev
Skin caused by wellbore deviation (negative). At high deviation angles, the increased effective length of the reservoir section open to inflow increases the natural well productivity.
Sperf Skin caused by the presence of small perforations (positive or negative). The skin depends on the perforation size and phasing.
Sd,perf
Skin caused by reduced crushed-zone permeability around perforations (positive). Difficult to estimate due to many parameters that cannot be estimated reliably, like permeability of crushed zone, actual depth of penetration.
Sperf
Skin caused by gravel packing (usually positive). Theoretically, it may have a negative value in underreamed, open hole, gravel packed wells because of the increased effective wellbore radius.
Sturb
Skin caused by turbulent (non-Darcy) flow, mainly applicable to gas (positive). It is often caused by flow convergence because of inadequate dimensions and an inadequate number of perforations.
Figure 9-1 illustrates how the skin factor varies with the damage ratio, kd/k, and damage zone radius,
rd, for a vertical well with a radius of 0.0762 m. These variables determine the magnitude of the skin
factor and control the well productivity. For instance, a reduction in permeability to less than one tenth of the initial value within 0.6 m of the wellbore axis results in a skin factor of approximately 18.7.
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Figure 9-1 Skin factor as a function of damage radius and damage ration (kd/k)
The skin effect is a composite variable. The following sources of the nonideal flow should consider: • Formation damage,
• Limited entry completions effects, • Perforation effects,
• Saturation blockage near the wellbore, and • Gravel-pack completion effects.
The composite skin factor can be calculated from well test data. It is very important to separate the observed skin factor into its components and to establish which near-wellbore flow restrictions can be removed by stimulation treatment and which require workover or recompletion. For good understanding of the skin related concepts it is enough to consider pseudo-steady flow only.
Figure 9-2 Pressure profile of damaged and undamaged well
Skin, S, is the composite of all non-ideal conditions affecting flow into the wellbore, and may generally be written, with its main components, as:
𝑆 = 𝑆𝑑𝑎𝑚+ 𝑆𝑝𝑎𝑟𝑡+ 𝑆𝑑𝑒𝑣+ 𝑆𝑝𝑒𝑟𝑓++𝑆𝑔𝑟𝑎𝑣𝑒𝑙+ ∑ 𝑃𝑠𝑒𝑢𝑑𝑜𝑠𝑘𝑖𝑛𝑠 (9-1)
The last term in the above expression represents an array of pseudoskin factors. These pseudoskin effects are generally mechanical, resulting from obstructions to flow or because of turbulence effect and additional pressure drop. The real skin due to formation damage is that portion of the total skin that can be removed by matrix treatments. Sdam describes the permeability of the damaged to
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9.2.2 Best Candidate Selection Process for Acidizing
Despite the extensive research efforts done by the industry on the root cause of formation impairment and its remediation by matrix treatment, the failure rate of matrix acidizing treatments today is estimated at 60 to 70%. Worldwide, this failure rate represents a loss of millions of dollars in wasted stimulation expenditure and missed production. The primary causes for failed treatments have been poor candidate selection and poor treatment design with respect to fluid selection and placement. Another reason for the high failure rate of matrix acidizing treatments is the lack of proper technology transfer to the field. Because the industry often sees matrix treatments as low-technology treatments, little attention is given to design.
Many candidates are normally selected by each Asset and they are sending for evaluation. The process of candidate selection applied in Assets includes:
• Prepare list of candidate wells,
• Review of well logs/records, reservoir characteristics and information on the completion/previous workovers,
• Map the productivity of each well,
• Establish reasonable upper production potential for matrix stimulation techniques, • Evaluate potential mechanical problems, and
• Focus on wells with the highest reward and lowest risk.
The candidate wells are then analyzed by Stimulation Team in Production Engineering according to the following six criteria:
1. PVT matching in order to select the best PVT correlation to simulate well behavior when acid is injected.
2. Verification of the remaining reserves and the current water saturation.
3. Evaluation of an approximate damage type from history well data and skin factor using an analytical model (Resestim 7 in house made software or licensed software Prosper for integrated system analysis).
4. Predict well productivity index (PI) increase after stimulation job based on new skin. 5. Make production forecast using material balance equation for oil and gas wells. 6. Estimate NPV and Cash Flow based on production forecast.
All economically feasible wells are candidates. The design of the stimulation is made for the economically most attractive candidates. A system for the selection of the acid should be used and the calculation of the other design parameters is based on models/algorithms that will be explained later.
9.2.3 Review of the Most Frequent Damages in OMV Petrom and General Selection of Treatment
Once damage has been characterized in a well, its origin must be ascertained to help determine the correct remedial action. Various types of damage can exist since almost every operation performed on the well is a potential source of damage. The physical characteristics of the damage are an essential parameter since this determines the desired characteristics of the treating fluid. The physical characteristics of the damage are the main criterion adopted to categorize the various types of damage indicated in Figure 9-3 (seven basic types of damages).
Emulsions
The intermixing of oil- and water-base fluids in the formation often results in the formation of emulsions. Emulsions can have high viscosity, particularly water-in-oil emulsions. Typically, they are
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formed due to invasion of drilling/completion filtrate or treatment fluids into the formation. High pH filtrates from mud or cement slurry or low pH filtrate from acidizing can emulsify some formation oils. Similarly, hydrocarbon filtrates from oil-based drilling or stimulation fluid can form emulsions with some formation brines. Emulsions are stabilized by surface active materials (surfactants) and by fines, which are either present in the "treating" fluids or are generated through the fluid/rock interaction. Generally, mutual solvents with or without demulsifiers are used for treating such problems.
Figure 9-3 Formation damage types Wettability Change
Partially or totally oil wetting a formation reduces the relative permeability to oil. This may occur due to adsorption of surface active materials from oil-based drilling, workover or completion fluids on the rock. This type of damage is removed by the injection of mutual solvents to remove the oil wetting hydrocarbon phase, followed by the injection of strongly water-wetting surfactants.
Water Block
A water block caused by an increase in the water saturation near the wellbore decreases the relative permeability to hydrocarbons. Waterblock can form either during drilling and completion operations through invasion of water-base filtrate, or during production through fingering or coning of formation water. The formation of a water block is favored by the presence of pore lining clays such as illite. The hairy shape and large surface area of these clays increase the adsorption of water on the pore wells.
A water block is usually treated by reducing the surface tension between water and oil (HF acids). Nonaqueous acids (such as alcoholic acid) are particularly suitable in (gas) wells where a water block problem is suspected because they also increase the vapor pressure and reduce the surface tension between water and gas.
Scales
Scales are precipitated mineral deposits. They can precipitate in the tubing, perforations and/or formation. Scale deposition occurs during production because of the lower temperatures and pressures encountered in or near the wellbore. Scales can also form by mixing of incompatible waters: formation water and either fluid filtrate or injection water. Various solvents can be used to dissolve scales, depending on their mineralogy. The most common types of scales encountered in a well are:
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• Carbonate scale (CaCO3 and FeCO3): CaCO3, is the most common scale, occurring in reservoirs rich in calcium and carbonate and/or bicarbonate ions. Hydrochloric acid will radial dissolve all carbonate scales.
• Sulphate scales occurring mainly as gypsum (CaSO4, 2H2O) or anhydrite (CaSO4). The less common barytine (BaSO4) or strontianite (SrSO4) is much more difficult to remove but, their occurrence is more predictable. EDTA will dissolve calcium sulphate. Barium and strontium sulphates can also be dissolved with EDTA provided the temperature is high enough and the contact times sufficiently long (typically 24 hr soaking period is required for a 4000m well with a BHST of about 100oC
• Chloride scales such as sodium chloride: These are easily dissolved with fresh water or very weak acidic (HCl, acetic) solutions.
• Iron scales such as sulphide (FeS) or oxide (Fe2O3): Hydrochloric acid with reducing agents and sequestrant will dissolve such scales and prevent the reprecipitation of by-products such as iron hydroxides and elemental sulphur.
• Silica scales: Generally occurring as very finely crystallized deposits of opal or chalcedony. Hydrofluoric acid can dissolve silica scales.
• Hydroxide scales such as magnesium (Mg[OH]2) or calcium (Ca[OH]2) hydroxides: Hydrochloric acid or any acid that can sufficiently lower the pH and not precipitate calcium or magnesium salts can be used to remove such deposits.
Contact time is a very important factor to consider in the design of a scale removal treatment. The major problem when treating scale deposits is to allow sufficient contact time for the acid to reach and effectively dissolve the bulk of the scale material. The treating fluid must contact and effectively dissolve most of the scale in order for the treatment to be successful.
Organic Deposits
Organic deposits are precipitated heavy hydrocarbons (paraffin or asphaltenes). They are typically located in the tubing, perforations and/or the formation. Although the mechanisms of creation of organic deposits are numerous and complex, the principal mechanism is a change in temperature or pressure near the wellbore during production. The heavy hydrocarbon fractions do not remain dissolved in the oil and begin to crystallize. Cooling down the wellbore or injecting of cold treatment fluids has the same overall effect as a temperature drop during production.
The deposits are usually re-dissolved by organic solvents. Blends of solvents can be tailored to a particular problem, but an aromatic solvents is an efficient, general purpose solvent, particularly for paraffins. The addition of a small amount of alcohols is often beneficial when dissolving asphaltenes. Organic deposits must not be confused with another type of deposit called sludge. This deposit is a reaction product between certain crude oils and strong inorganic acids. Once formed, sludge cannot be dissolved.
Mixed Deposits
Mixed organic/inorganic deposits are a blend of organic compounds and either scales or silts and clays. When migrating fines associated with an increase in water production in a sandstone reservoir become oil-wet, they act as a nucleation site for organic deposits. This type of combined deposits requires the use of a mixed solvent.
Silts and Clays
Damage due to silts and clays includes the invasion of the reservoir permeability by drilling mud, the swelling and/or migration of reservoir clays. Clays or other solids from the drilling, completion or workover fluids can invade the formation. When the differential pressure is sufficiently large and the
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size of the particles is smaller than the pore throat openings, they are forced into the pore network and tend to plug the network, resulting in damage.
When water-based filtrate from drilling, completion, workover or treating fluids invades the porosity of the reservoir, it can disturb the equilibrium between the clays and formation water. This is normally due to a change in salinity, which creates imbalances in the forces between clays. Smectite clays can swell and drastically reduce permeability. Flocculated aggregates of kaolinite can be dispersed, and subsequently block pore throats. This disturbance of native clays is the most common and, probably the most important cause of damage.
During production, particles can become dislodged and migrate with the produced fluids. The particles can bridge near the wellbore resulting in reduced productivity. When the damaging particles come from the reservoir rock, they are usually referred to as "fines". This is a generic term that includes clays (phyllosilicates with a size of typically less than 4 micrometers) and silts (silicates or aluminosilicates with a size between 4 and 64 micrometers). These particles are soluble in hydrofluoric acid mixtures.
Damage due to fines is located in the near wellbore area within a 0.9 m to 1.2m radius. Damage may also occur in a gravel pack in sandstones it is removed by treatment with an acid containing HF: Mud Acids of various strengths or Clay Acid systems. An HCl system is normally used to remove fines damage in a carbonate formation. Since the fines are not dissolved, yet are dispersed in the natural fractures or in the wormholes just created, nitrogen is normally recommended when the well has low bottom pressure. The nitrogen will enhance fines removal.
Due to the complexity of the fines problem and its impact on treatment design this manual contains, in the following two chapters, detailed information on the removal of fines damage in sandstones and carbonates respectively.
9.3 Well Acidizing Methods Applied in OMV Petrom
There are two principal matrix acidizing treatment methods used in OMV Petrom in which applied treatment pressure at the bottom is lover than formation fracturing pressure are:
1. Sandstone acidizing, and 2. Carbonate Acidizing
Matrix acidizing of sandstones with mud acid is directed at silt and clay damage removal. A treatment may also be designed to remove other types of damage, such as: emulsion, wettability change, water block, organic deposits, and mixed deposits. Samples of the formation, produced fluids, and possibly even tubing, are important to ascertain formation damage type and well condition. The sensitivity of the formation to a treating fluid may result in deconsolidation due to dissolution of the cementing material. Precipitates may form from Fe, Na, K dissolved by mud acid. Fines released during HCl or Mud Acid stages may create damage. Low permeability wells are very susceptible to this damage mechanism.
The primary objective of matrix acidizing in carbonates is to dissolve the matrix, but most of all, to bypass damage, by creating wormholes and thus to increase the effective wellbore radius and its average effective permeability. The formation is therefore actually stimulated (unlike in sandstone reservoirs), and the skin value is decreased, often to negative values.
Considering the main types of potential damages the general best practice workflow of well stimulation by acidizing is shown on Figure 9-4.
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Figure 9-4 Formation damage types and treatment selection The final fluid selection for treatment
The first step in planning to acidize any type of formation (sandstone and/or carbonate) is to use key reservoir characteristics like gross lithology, mineralogy composition and temperature for fluid selection. The general workflow applied in OMV Petrom for basic fluid selection is shown in Figure 9-5.
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9.3.1 Sandstone
Treatment fluid selection in sandstone formations is highly dependent on the mineralogy of the rock as well as the damage mechanism. Hydrofluoric (HF) acid is typically used to dissolve the damaging silicate particles (Figure 9-6). Nonacid systems are sometimes used to disperse whole mud and allow it to be produced with the treating fluid. The criteria for selecting the treating fluid for any treatment stage are mineralogy (solubility of minerals in acid, clays/silt, iron and zeolites content and other lithology criteria such as chlorite and glauconite content), petrophysical properties (permeability) and well conditions (temperature, formation damage mechanism).
Figure 9-6 Constituents of sandstone which are soluble in HCl/HF acid systems HF Reactions in Sandstones
The reaction of HF acid with the damaged matrix occurs in three steps. Live HF reacts with sand, feldspar and clays, which results in silicon fluorides and some aluminum fluorides as reaction products. The HF acid provides the greatest dissolving power during this phase, while only a small amount of HCl is consumed. The depth of invasion of the live HF acid is normally 5-15 cm from the wellbore. The primary stage is the stage that removes skin damage. The reaction of hydrofluoric acid (HF) on the pure quartz component of sandstone described by the equations 9-2 and 9-3 results in silicon tetrafluorid (SiF4) and water:
O
H
2
+
SiF
SiO
+
4HF
2⇔
4 2 (9-2)SiF
H
2HF
+
SiF
4⇔
2 6 (9-3)The stoichiometry of this reaction shows that 4 moles of HF are needed to consume one mole of SiO2. However, the produced SiO4 may react with HF to form fluosilicic acid (H2SiF6) resulting in the
silicon hexafluoride anion SiF62-.
If the reaction goes to completion, 6 moles of HF, rather than 4, will be consumed to dissolve 1 mole of quartz. A complication is that the fluosilicate may exist in various forms, so that the total amount of HF required to dissolve a given amount of quartz depends on the solution concentration.
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Table 9-2 Primary chemical reaction in acidizing
HYDROFLORIC ACID - HF Quartz:
4HF + SiO2 ↔ SiF4(silicon tetrafluoride) + 2H2O
SiF4 + 2HF ↔H2SiF6 (fluosilicic acid) or SiF4 + 2F- ↔SiF62- (Silicon hexafluoride anion)
Albite (sodium feldspar):
Na AlSi3 + 14HF + 2H+ → Na+ + AlF2+ + 3SiF4 + 8H2O
Orthoclase (potassium feldspar):
KAlSi3O8 + 14HF + 2H+ → K+ + AlF2+ + 3SiF4 + 8H2O
Kaolinite:
Al4Si4O10(OH)8 + 24HF + 4H+ → 4AlF
2+4SiF4 + 18H2O
Montmorillonite:
Al4Si8O20(OH)4 + 40HF + 4H+ → 4AlF2+ + 8SiF4 + 24H2O
Calcite:
2HF+ CaCO3→CaF2 + CO2 + H2O Note: CaF2 is very low soluble FLUOBORIC ACID – HBF4
HBF4 + H2O → HF +HBF3OH rapid response
HBF3OH + HF + H2O →HBF4 slow reaction
Fluoboric acid-based solution (Clay Acid)
One of the key problems that can occur after acidizing is migration of fine particles in both, unconsolidated and consolidated sandstones causing the blockage of the pores, and in some cases increasing the tendency of forming viscous stabilized emulsions. Migration of fine particles after reaction with HF is primarily related to the concentration of HF and its reaction speed. To avoid undesirable precipitations of secondary products of reaction, rock deconsolidation and migration of fine particles, some special acids compositions have developed that can help in avoiding a problems. The most frequent used is Fluoboric acid (HBF4)
Fluoboric acid (HBF4) is used to produce HF through the hydrolysis according to the chemical reaction
shown in Table 9-2. At any time there is only a limited amount of HF acid available and the probability of forming precipitates of fluosilicates, fluoalumintes or silica is decreased significantly.. The acid is consumed by reaction on clay surface minerals followed by hydrolysis to produce more HF. Because of this, HBF4 is considered as acid with delayed reaction (“retarded acid”). If the
temperature is higher than 95 oC, the kinetic of the hydrolysis is rapid. The reaction of fluoroboric
acid with silica is approximately 10 times lower if temperature is less than 65 oC. A major advantage
of HBF4 is its ability to inhibit the migration of fines present in sandstone by coating the initial surface
with borosilicate as a product of reaction during treatment. Experimental results showed that when the cores containing pore lining illite have been treated by HBF4, the poorly crystallized precipitate of
KBF4 has been observed at the outlet of cell and it does not have a damaging effect. The positive
effects of using HBF4 and major advantages of its application are:
• The dissolving potential of clay acid is still high (for example, 8% of HBF4 is approximately
equal to 2%HF).
• The borosilicate coating stabilizes fines and makes them less sensitive.
Because of these HBF4 is recommended always when problems with migrating fines exist, what is
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Precipitation of reaction product
When the live HF has been consumed, the secondary reaction proceeds as the reaction of dissolved silicon fluorides on clay and feldspar. This reaction releases a large amount of aluminum and other cations into solution, consumes a large amount of HCl, and forms silicon precipitates and sodium and potassium fluosilicates, which can precipitate if the selected HF concentration is too high relative to the minerals that contain sodium and potassium. The reaction is complete when the silicon fluorides are no longer present, which is normally within 1.2 m from the wellbore. The precipitation of fluosilicates can be very damaging, and is one of the main causes of HF treatment failures, particularly in formations containing large amounts of K-feldspar. However, it is not really a problem if the fluid is kept in motion. If live HF is shut in during an acid job, severe and permanent damage to the matrix permeability can result from silica gel precipitation.
Reaction with feldspar, chert, mica and clay components of sandstones also results in SiF62-anion,
but, in addition, produces a range of aluminum complexes: AlF2+, AlF+
2, AlF3, AlF4-, AlF52- and AlF63s-.
The concentration of each aluminum complex depends on the concentration of free fluoride ions in the dissolving solution. Some of these products combine with free sodium, potassium, and calcium ions to produce four compounds with varying degrees of solubility in the spending acid:
• Sodium fluosilicate ( Na2SiF6),
• Sodium fluoaluminate (Na3AlF6),
• Potassium fluosilicate ( K2SiF6), and
• Calcium fluosilicate ( CaSiF6).
Matrix treatments are always designed to prevent the formation of these compounds in order to remove any risk of precipitation.
The tertiary reaction proceeds as the reaction of dissolved aluminum fluorides on clay and feldspar. The tertiary reaction is slower than the secondary reaction and it is much faster on clays than on feldspars. However, it is an important reaction that must be considered, because it causes further reduction in the HCl content of the spent HF. Once the acid is consumed, alumino-silicate scaling occurs, within a distance of 1.2 m to 1.8 m from the wellbore.
There are many precipitation reactions that take place during an HF sandstone acidizing job. These reactions are unavoidable, but their effect on stimulation response can be minimized with proper fluid selection and treatment design
In Table 9-3 damaging HF reactions in sandstones resulting in precipitation are summarized.
Table 9-3 Damaging HF reactions in sandstones
Reaction Precipitate(s)
HF + carbonates (calcite, dolomite) Calcium and magnesium fluoride (CaF2, MgF2) HF + clays, silicates Amorphous silica (orthosilicic acid) (H4SiO4)
HF + feldspars Sodium and potassium fluosilicate (Na2SiF6, K2SiF6)
HF + clays, feldspars Aluminum fluorides (AlFn3-n) Aluminum hydroxides
HF + illite clay Na2SiF6, K2SiF6
Spent HF + formation brine, seawater Na2SiF6, K2SiF6 HCl-HF + iron oxides and iron minerals Iron compounds HF + calcite (calcium carbonate) Calcium fluosilicate 9.3.2 Carbonate
There are two basic types of acid treatments applicable to carbonates in OMV Petrom. They are characterized by injection rates and pressures. Acid treatments with injection rates below formation fracturing pressure, called matrix acidizing and acid treatment with injection rates above fracturing
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pressure (called acid fracturing, see Chapter 11). Matrix acidizing is applicable only to formation exhibiting formation damage. In the case of naturally fractured formations acidizing at matrix rates even in an undamaged carbonate formation may result in an acceptable stimulation response. Whereas the purpose of sandstone acidizing is to dissolve the damage, the primary objective of matrix acidizing in carbonates is to dissolve the matrix, but most of all, to bypass damage, by creating new channels and thus to increase the effective wellbore radius and its average effective permeability. The dissolution of carbonate rocks by acid results in rapid generation of irregularly shaped and empty channels called wormholes, as shown in Figure 9-7. Because of the randomness of porous media, it had been shown that during dissolution two neighboring pores can coalesce if sufficiently enlarged. It is difficult to model or predict the development of wormhole formation in a real rock as the mineralogy will never be 100% carbonate.
Figure 9-7 Various Wormhole structures
The formation is therefore actually stimulated (unlike in sandstone reservoirs), and the skin value is decreased, often to negative values.
Acids used in carbonate acidizing and chemistry of reactions Commonly used acids to stimulate carbonate formation are:
• Hydrochloric (HCl),
• Acetic (CH3COOH)/ week organic acid, and
• Formic (HCOOH)/week organic acid.
Carbonate acidizing solely with HCl, is not complicated by a tendency for precipitates to form, as is the case for sandstone acidizing. The reaction products CaCl2, MgCl2 (dolomites) and CO2 are readily
soluble in water. Therefore, the formation of a precipitate or a separate CO2-rich phase is generally
not a problem.
Under comparable conditions weak organic acids react more slowly than hydrochloric acid and they can be used instead of HCl when high bottomhole temperatures (above 200oC) prevent efficient
protection against corrosion. Acetic acid is easier to inhibit than formic acid and is used more often.
Table 9-4 illustrates the maximum protection times with corrosion inhibitors at various temperatures and acid concentrations.
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The following factors affect the spending rate of acid in carbonate formations: temperature, pressure, acid type, acid concentration, acid velocity, reaction product and formation composition (structure and mineralogy). Acetic and formic acids react with CaCO3 to form calcium acetate and
formate.
The formic acid concentration must be limited to about 10% as calcium formate precipitates above that level. Acetic acid can be used at higher concentrations, as calcium acetate remains soluble, but best practice is to use not more than 10% acetic acid. None of the organic acids react appreciably with SiO2. They react with iron compounds or minerals containing iron. Acetic acid forms a complex
with iron in solution and helps prevent iron precipitation up to 60oC. In reservoirs with high iron
content, it is necessary to cut back on HCl concentration or substitute part or all the HCl with acetic acid.
Chelating agents, such EDTA (ethylendiaminetetraacetic acid), are even weaker acids than acetic and formic acids. For example, 9% disodium EDTA solution has the approximate dissolving power of 2.2% HCl. It is not common to use chelating acid in matrix acidizing because of their cost relative to the common acids (HCl, acetic and formic acid) and lower dissolving power.
The summarized chemical reactions of HCl and organic acids with carbonate are shown in Table 9-5.
Table 9-5 The reaction of HCl with carbonates
HYDROCHLORI AClD Calcium carbonate :
2HCl + CaCO3↔CaCl2 + CO2↑ + H2O Dolomite:
4HCl + CaMg(CO3)2 ↔ CaCl2 + MgCl2 + 2CO2↑+ 2H2O Siderite:
2HCl+ FeCO3 ↔ FeCl2 + CO2 + H2O
Organic Acids Calcium carbonate and Acetic Acid :
2CH3COOH + CaCO3↔Ca(CH3CO2)2 + CO2↑+ H2O Dolomite and Acetic Acid:
4CH3COOH + CaMg(CO3)2↔Ca(CH3CO2)2 + Mg(CH3CO2)2 +2 CO2↑+ H2O Calcium carbonate and Formic Acid :
2HCOOH + CaCO3↔Ca(HCO2)2 + CO2↑+ H2O Dolomite and Formic Acid:
4HCOOH + CaMg(CO3)2↔Ca(HCO2)2 + Mg(CH3CO2)2 + 2CO2↑+ H2O
However, despite the simplified chemistry, HCl acidizing of carbonates is a difficult process to model. The reason for this is the high rate at which the reactions take place as compared with that of HF with the various minerals prevalent in sandstones.
Wormhole growth depends on the acid injection rate, the diffusion rate and the formation’s surface reaction rate. Wormholes will only form if the diffusion rate determines the overall spending rate, which happens if the acid/rock reaction rate is high. The diffusion rate determines the rate at which acid travels from the bulk of the fluid to the rock surface as shown on Figure 9-8.
The treatment objective is to form the longest and deepest penetrating wormholes as possible. Wormholing efficiency under expected downhole and surface treating conditions is a major criterion in fluid selection.
Images shown in Figure 9-9 are neutron radiographs of cores acidized under different conditions. Experiments have shown that the quantity of rock dissolved, i.e., the acid penetration depends on acid velocity. One advantage of wormhole formation is that the near-wellbore damage can be bypassed and the “effective” treated zone becomes much larger than in sandstone acidizing (for the same amount of rock dissolved) or in matrix acidizing of carbonates using slow reacting acids when
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the kinetics is limited by surface reactions. In addition, problems of deconsolidation in the near-wellbore area are less severe.
Figure 9-8 Wormholing controlled by diffusion
Major wormhole structure possibilities can be categorized, as a function of injection rate and acid/rock reactivity, as follows:
• Face dissolution (no Wormholing),
• Conical (single channel with limiting branching),
• Dominant wormholes (primary channels with some branching), • Ramified wormholes (extensive branching), and
• Uniform dissolution.
Figure 9-9 Various Wormhole structures (Fredd and Fogler, SPEJ, 1998, 1999; Hoefner and Fogler, AlChEJ, 1998)
9.4 Technology Workflow of Best Practices for Fluid Selection, Treatment
Design and Job Execution
9.4.1 Sandstone Matrix Acidizing Treatment
Fluid Selection for Acidizing Treatment
Fluid selection for each stage of the treatment must take account of all of the parameters previously discussed: dissolution of damage, compatibility with rock minerals and reservoir fluids and potential damaging reaction products. Since silts and clays are the component minerals that react with HF acid to cause potentially damaging precipitates, the higher the silt and clay content, the greater the risk of precipitation. Increasing the HCl:HF ratio is one way to retard precipitation. HCl increases the dissolving power of the HF and low-HF content reduces the precipitation of silica. Therefore, as the silt and clay content of the formation increases, the recommended HCl: HF ratio also increases. The
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presence of HCl sensitive clays will also affect the type of acid chosen. X-ray diffraction (XRD) analysis is the most common test used to determine formation mineralogy.
In OMV Petrom two different models for acidizing fluid selection are in use: • Model 1: Use mineralogy composition and rock/reservoir permeability. • Model 2- Use mineralogy composition and temperature.
Formation solubility in both HCl and HCl: HF can be used to approximate the total silt and clay content. The difference in these solubilities correlates well to silt and clay content by XRD analysis as seen in Table 9-6. Solubility information, however, does not indicate the type of clay present.
Table 9-6 Solubility of Common Minerals in Acid
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Model 1-Sandstone Acidizing Workflow
Model 1- Preflush/Overflush stage Fluid Selection
Using mineralogy composition and reservoir permeability workflow for selecting the best fluid for pre-flush treatment is shown in Figure 9-10 and summarized Table 9-7 if the content of carbonate is less than 20%, HCl is used as a preflush to an HF acid. Normally the greater the permeability, the lower the chance of creating fines migration damage during the HCl preflush.
Since clay and silt type materials may react with HCl to produce mobile fines, the HCl concentration decreases with increased fines content. The clay content is the dominating species due to its large surface area and cation exchange capacity (CEC).
Figure 9-10 Model 1 Preflush/Overflush Fluid Selection
Table 9-7Model 1 Preflush Fluid Selection
Mineral Composition
> 100 mD
20-100 mD
< 20 mD
<10% Silt and < 10 % Clay 15% HCl
10% HCl
7.5% HCl
>10% Silt and >10 % Clay
>10% Silt and < 10 % Clay
>10% Silt and > 10 % Clay
10% HCl
7.5% HCl
5% HCl
At the presence of HCl sensitive minerals, like chlorite, glauconite and zeolites it is advisable to keep the pH low to so all reaction products dissolved and the selected fluid for preflush should be corrected according to the following practices shown in Table 9-8.
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Table 9-8 Model 1 Preflush /Overflush fluid selection including presence of HCl sensitive minerals
Zeolites Chlorite+Galuconite Silt and Clay
>2 Any Any Any 10% Acetic
>=2 >6 Any Any 10% Acetic
<=2 3-6 >10% Silt and >10 % Clay Any 5%HCl+5%Acetic
<=2 3-6 <10% Silt and < 10 % Clay Any 7.5%HCl+5%Acetic
0-2 <=3 >10% Silt and >10 % Clay >100 10%HCl+5%Acetic
0-2 <=3 <10% Silt and < 10 % Clay >100 15%HCl+5%Acetic
0-2 <=3 >10% Silt and >10 % Clay 20-100 7.5%HCl+5%Acetic
0-2 <=3 <10% Silt and < 10 % Clay 20-100 10%HCl+5%Acetic
0-2 <=3 >10% Silt and >10 % Clay <=20 5%HCl+5%Acetic
0-2 <=3 <10% Silt and < 10 % Clay <=20 7.5%HCl+5%Acetic
0 <=3 >10% Silt and >10 % Clay >100 10%HCl
0 <=3 <10% Silt and < 10 % Clay >100 15%HCl
0 <=3 >10% Silt and >10 % Clay 20-100 7.5%HCl
0 <=3 <10% Silt and < 10 % Clay 20-100 10%HCl
0 <=3 >10% Silt and >10 % Clay <=20 5%HCl
0 <=3 <10% Silt and < 10 % Clay <=20 7.5%HCl
Acid Concentration (%) Lithology Criteria (%)
Permeability (mD)
Summarizing the previous table, the following rules/best practices have been using:
If
4-6% chlorite/glauconite
then
use <20md Guidelines with 5% Acetic AcidIf
6-8% chlorite/glauconitethen
use only 10% Acetic Acid preflush to Mud AcidIf
<2% Zeolitethen
use 5% Acetic Acid in all HCl systemsIf
2-5% Zeolitethen
use only 10% Acetic Acid preflush Model 1 Main Treatment Fluid SelectionSilt and clay content and permeability are used as selection criteria. Silt and clay percentages are calculated internally from the input lithology. The total of mica and feldspars are considered to be silts. The total of kaolinite, mixed layer, illite, smectite, glauconite, chlorite, and zeolites are added for clays.
The permeability of the formation influences the selection of the treating fluid in two ways. First, permeability affects the type and extent of damage. A highly permeable formation can easily be penetrated by foreign solid particles of fluids, and the depth of the damage can be large. On the other hand, low permeability sandstone will merely be damaged by invasion of foreign particles. However, this type of formation can be more sensitive to the invasion of foreign fluids because the small pores often contain a large quantity of clays that have a high reactivity toward fluids. The permeability also influences the amount of damage caused by precipitates. A low permeability formation is more severely damaged by precipitates than a formation of high permeability. The same is true for damage resulting from water block. In some cases, the type of produced fluids precludes the use of some treating fluids. This applies to gas wells, where it is preferable to minimize the use of purely water based fluids. Agents that lower surface tension (surfactants, alcohols) and/or gases (foams) are recommended. In other cases, adverse reactions between acids and formation oils or formation waters dictate the use of only specific acid formulations. Figure 9-11 and Table 9-9
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Figure 9-11 Model 1 Main/Base Treatment Fluid Selection Table 9-9 Model 1 Main/Base Treatment Fluid Selection
Mineral Composition > 100 mD 20-100 mD < 20 mD <10% Silt and < 10 % Clay 12% HCl +3%HF 8% HCl +2%HF 6% HCl +1.5%HF >10% Silt and >10 % Clay 13.5% HCl +1.5%H9% HCl +1%HF 4.5% HCl +1%HF >10% Silt and < 10 % Clay
>10% Silt and > 10 % Clay 12% HCl +2%HF 9% HCl +1.5%HF 6% HCl +1%HF
If
4-6% chlorite/glauconite
then
use <20md Guidelines with 5% Acetic AcidIf 6-8% chlorite/glauconite
then
use 10% Acetic Acid preflush to Mud Acid plus 5% acetic acidIf
chlorite/glauconite > 8%,then
use 10% acetic acid and organic mud acidIf
<2% Zeolitethen
use 5% Acetic Acid in all HCl systemsIf
2-5% Zeolite then use 10% Acetic Acid preflush and overflush to mud acid containing 10% acetic acidIf > 5% Zeolite then use 10% Acetic Acid preflush and overflush to 10% citric acid / HF.
Formations with more than 2% zeolites are considered sensitive and use the above flowchart for acid selection.
For moderate zeoloite compositions, acetic acid is used as the acid preflush and overflush and is added to the conventional mud acid formulations with the HCl. The organic acid is to keep the pH low, acting like a buffer in these acid solutions. Reaction products are more soluble in low pH. For higher zeolite compositions, acetic is also used for the preflush and overflush, but organic mud acids made with citric acid are recommended.
The workflow (Figure 9-12, Figure 9-13 and Figure 9-14) and Table 9-10 lists the recommendations
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Figure 9-14 Model 1 Main/Base Treatment Fluid Selection including presence of high sensitivity Clays, Zeolites and Glauconite
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Table 9-10 Model 1 Main/Base Treatment Fluid Selection including presence of high sensitivity Clays, Zeolites and Glauconite
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Model 2-Sandstone Acidizing Workflow
Model 2- Preflush/Overflush stage Fluid Selection
The formation temperature is an important factor because it influences the efficiency of corrosion inhibitors and the reaction rates. Several treating fluids decrease reaction rates at high temperatures and provide deeper live-acid penetration. The workflows shown in Figure 9-15 and Figure 9-16 as well as in Table 9-10 and Table 9-11 can be used as guidance for fluid selection for Preflush/Overflush and Main treatment.
Figure 9-15 Model 2 Preflush/Overflush Fluid Selection including presence of high sensitivity Clays, Zeolites and Glauconite
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Table 9-11 Preflush /Overflush fluid selection including presence of HCl sensitive minerals and temperature
Model 2 Main Treatment Fluid Selection
Figure 9-16 Model 2 Main Treatment Fluid Selection including presence of high sensitivity Clays and reservoir temperature
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Table 9-12 Main Treatment Fluid Selection including presence of HCl sensitive minerals and temperature
9.4.2 Applied Sandstone Design Procedure
A sandstone acidizing design procedure in OMV Petrom consists of the following distinct stages: 1. Tubing pickling stage/wellbore cleanup
Wellbore cleanup is commonly used to remove scale, paraffin, bacteria or other materials from the tubing, casing or gravel-pack screen. The injection string (production tubing, drill pipe or coiled tubing) should be cleaned (pickled) prior to pumping the acid treatment. The pickling process may be multiple stages, consisting of solvent and acid stages. An acid pickling job of tubing/casing can be done by simply spotting around 2.4 bbl/1000 feet (1.2 lit/m) of 3-20% HCl down the tubing and up the annulus. A typical pickling solution is a 7.5% HCl solution containing an iron control agent and corrosion inhibitor. Often the same acid mixed for use in the HCL preflush may be used as the pickling solution.
2. Preflush
Non-Acid
A water displacement stage, consisting of 3-5% NH4Cl solution, depends on concentration of smectite, illite, kaolinite, chlorite and feldspar, according to:
Concentration%=3+(%smectite*0.3+%illite*0.12+%kaolinite*0.08+ %chlorite*0.12+%feldspar*0.05) This is considered to displace formation water containing bicarbonate and sulfate ions. Typical volumes are 500 to 1000 l/m (40 to 80 gal/ft)
Acid preflush
The main purpose of the standard preflush with 5%-15% HCl is to dissolve carbonate constituents of the reservoir. This is to prevent the possibility of forming CaF2 as a mud acid precipitation product.
Numerous acidizing jobs in OMV Petrom have proved that the best practices is to execute pre-flush with at least 50% of the volume of acid fluid for base/main treatment.
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Typical volumes are 620 to 1240 l/m (50 to 100 gal/ft) and it is preferable that the preflush penetrates the same distance as the HCl/HF mixture.
Organic acids, such as acetic and formic, should be used in conjunction with, or instead of, HCl in sensitive formations the. Although they will dissolve the carbonate, they work more slowly and are especially applicable for high temperature conditions. When pumping organic acids as stand-alone fluids, they should be mixed in ammonium chloride rather than fresh water. Organic acids also act as a low-pH buffer and chelating agent that helps minimize the tendency of iron compounds to precipitate as the acid spends. However, they do not dissolve iron scale or prevent clay swelling. If iron and carbonate contents are high, both an acetic acid and HCl preflush can be used. If carbonate content is not high (less than 5%), then the organic acid can be applied only, without using HCl preflush. The best practice in OMV Petrom is to use 10% acetic acid contain 5% NH4Cl.
Ammonium chloride is added for clay stability as use of acid without the addition of NH4Cl could cause clays swelling.
3. Main Treatment
The main acid phase is commonly a mixture of HCl/HF. Volumes may range from 120-3000 l/m (10-250 gal/ft) and more common volumes used in OMV Petrom are in the range 120 to 240 l/m (10 to 20 gal/ft). Volume is somewhat arbitrary, but should have a logical dependence on formation permeability, acid sensitivity, type and severity of damage and length of the treated interval. Risks associated with acidizing-such as fines migration, precipitation of reaction products, and rock deconsolidation-normally can be controlled (if not minimized or eliminated) by use of proper volumes and concentrations of acids.
Mud Acid should not be used in formations with > 20% HCl solubility. Pore lining clays will be dissolved by mud acid. Thus, an abundance of chlorite in the pore throats may result in iron control problems. High permeability formations may experience deep invasion of particulates (drilling mud, barite, etc.).Low permeability formations will not experience severe particle invasion but will be more sensitive to damage by precipitates. Sludge or emulsion tendency of crude will dictate the use of a specific acid system. Treatments in gas wells include mutual solvents or alcohols. High temperature decreases live acid penetration and increases corrosion rates. Wells with low bottom hole static pressure (BHSP) should be treated with energized/foamed fluids.
The well shut-in time after treatment should be minimized to reduce precipitation of reaction product. It is mandatory to avoid using NaCl, KCl, or CaCl2 brines in any HF treatment stages or in any
stage immediately proceeding or following HF stages. 4. Overflush/Aterflush
Overflush (or afterflush) is an important part of a successful acidizing treatment. The purposes of the overflush are:
• Displace nonreacted mud acid into the formation,
• Displace mud acid reaction products away from the wellbore,
• Remove oil-wet relative permeability problems caused by some corrosion inhibitors, • Redissolve HF precipitates, if an acidic afterflush is used.
Typical overflushes for mud acid treatments are: • Water containing 3 to 8% ammonium chloride,
• Weak acid (3 to 10% HCl) in the cases when HCl is used as preflush fluid.
• Acetic acid in the same concentration as HCl if formation mineralogy and temperature do not allow application of HCL. Alternatively, 3-8% of NH4Cl solution can be used.
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Usually, the Overflush/Afterflush treatment can be performed with the same fluid concentration as used in the preflush. The typical volumes of 360 to 1200 l/m (25-100 gal/ft) are also very similar to those used in the preflush. The same fluid and concentration can be used in most cases. In gas wells, and sometimes in extremely water-sensitive formations, nitrogen is an effective overflush. The afterflush should occur immediately after the main acid injection in order have the most beneficial effect and to minimize precipitation of Si (OH)4.
Wells should be put on production immediately after the treatment. In such case, the afterflush volume should be at least the same as the main HCl/HF volume. In cases when wells have to stay closed in for some time (which is to be avoided), the afterflush volume should be at least twice the HCl/HF volume in order to displace the reaction products to a distance where their influence is negligible (1 to 1.5m radial penetration).
Certain chemicals (additives, inhibitors, iron complexing agents) may be used in addition to the basic solution of acid or NH4Cl in order to reduce problems with emulsion and sludge formation or prevent
corrosion and scale precipitation.
A large overflush is necessary to prevent the near-wellbore precipitation of amorphous silica. At formation temperatures of 95 °C or higher, amorphous silica precipitation occurs when the mud acid is pumped into the formation. The precipitate is somewhat mobile at first, but may set as a gel after the flow stops. It may be diluted and dispersed far enough from the wellbore to reduce its harmful influence if it is kept moving by the overflush.
Diversion techniques
One of the main reasons that acid treatments fail is that the injected acid is not correctly placed and does not have full contact with the damage. Selection of the proper fluid placement method is a key success factor in acid treatment design in both sandstones and carbonates and acid diversion is a challenge that has to be faced in either lithology.
As acid is pumped, it flows preferentially along the most permeable path into the formation. The treated zone is commonly not adequately converged by the injected acid due to significant zone heterogeneities caused by big variations in zone properties. The acid opens high permeable zones even more, and less permeable, damaged zones are almost guaranteed not to receive adequate treatment. Some technique to divert the treatment fluid toward more damaged formation or damaged perforations is therefore mandatory. To approach full damage removal, acid must be diverted to the sections that accept acid the least – that is, those are most damaged
There is a variety of diversion techniques, but there are three basic methods of acid placement (diversion techniques) as shown in workflows (Figure 9-17 and Figure 9-18 ):
• Mechanical placement
o Packer isolation system ,
o Ball sealers (Not used in OMV Petrom) o Coiled tubing
• Chemical diversion
o Bridging and plugging agents (inert materials in the of large sized particles from 10-100 mesh, such as silica sand, water soluble agents like rock salt and benzoic acid, oil-soluble agents such as resins etc.)
o Particulate diverters (small particle size, commonly below 0.1 mm and those can be water-fine grade of benzoic acid and oil soluble- blends of hydrocarbon resins)
• Foam Diversion (The most useful in gas well acidizing, in gravel pack completions and generally more effective in higher-permeability formations with deeper damage)
• Gels (more reliable than foam, but could be damaging, because higher concentration, gels will stay unbroken and therefore will not be completely cleaned up causing. This will damage the perforations. Commonly used is Hydroxyethylcellulose-HEC).
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Figure 9-17 General Workflow for choosing a diversion method for matrix acidizing
Treatment fluid can be directed exclusively toward a low-permeability zone using injection string (tubing, drillpipe or coiled tubing equipped with mechanical packers). Flow can be blocked at individual perforations taking most of the treatment fluid by injecting ball sealers that seat on the perforations.In sandstone, microscopic agents such as oil-soluble resins can create a filter cake on the sand face. Chemical diverters such as viscous gels and foams created with nitrogen are used to block high –permeability pathways within the matrix. The requirements on any diverting agent are stringent. The agent must have limited solubility in the carrying fluid, so it reaches the bottom of the hole intact, it must not react adversely with formation fluids, it must divert acid. Also, the used diverter agent must be able to cleaned up rapidly and thereby avoid harming production. Ball sealers drop into the rathole as soon as injection halts or, if they are of the buoyant variety, they are caught in ball catchers at the source. Benzoic acid flakes dissolve in hydrocarbons. Oil-soluble resins are expelled or dissolved during the ensuing hydrocarbon production. Gels and foams break down with time.
In practice, acid and diverting agents are pumped in alternating stages: first acid, then diverter, then acid, then diverter, and so on. The number of stages depends on the length of the zone being treated. Typically, one acid diverter stage combination is planned for every 5-8 m of formation.
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The current diverter technologies work sporadically and many times do more harm than good. Recent work shown that even when a diversion technique such as ball sealers is applied properly, over one third of the perforation become permanently blocked because the balls become lodged in the perforation. Chemical diverters often misused or do not meet expectations – rock salt is sometimes used by mistake with HF acid producing plugging precipitates, and so-called oil-soluble resins are infrequently only partially soluble in oil. It is necessary to choose properly the non-damaging diversion techniques whose effectiveness can be proved and documented. Foam and the use of inflatable packers on coiled tubing are viable techniques for positive diversion.
Figure 9-18 Diversion selection workflow Injection pressure and rate strategy- Design model
Additional reservoir parameters (fracture gradient, porosity, height, etc.) are required to calculate/estimate injection pressure and rate constraints for the acid.
The acid use for the main treatment stage should be injected at a pressure that will not cause fracturing of the formation. In cases of very severe damage, the pressure may need to be increased above the fracturing pressure for a short period of time, but should be returned below fracturing pressure as quickly as possible. Application of this injection strategy during any treatment stage will allow removing damage more successfully. Maximum allowable injection pressure at the surface to avoid formation breakdown is defined by Eq. 9-4.
