SPE 109818 Effective Matrix Acidizing in High-Temperature Environments Ricardo Aboud, Kern Smith, and Leandro Forero, BJ Services, and Leonard Kalfayan, Kalfayan Production Enhancement Services
Copyright 2007, Society of Petroleum Engineers This paper was prepared for presentation at the 2007 SPE Annual Technical Conference and Exhibition held in Anaheim, California, U.S.A., 11–14 November 2007. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, Texas 75083-3836 U.S.A., fax 01-972-952-9435. 01-972-952-9435.
Abstract World demand for energy is substantial and continues to grow. By 2020, it is expected that the world will need approximately 40% more energy than today, for a total of 300 million barrels of oil-equivalent energy every day. Meeting higher energy demands will require a portfolio of energy-generation options including but not limited to oil, natural gas, coal, nuclear, steam, hydro, biomass, solar and wind. New horizons are being explored. Wells are drilled in greater water depths. Drilling units are continually upgraded to target deeper hydrocarbon-bearing zones. Wellbore tubular metallurgy is continually upgraded. Drilling, completion and stimulation fluids are being developed for extreme temperature and pressure environments. As the preferred technology to enhance "oilfield" energy production, well stimulation has and will continue to have an important role in fulfilling the world’s future energy needs. Well stimulation generally uses fluids to create or enlarge formation flow channels, thereby overcoming low permeability, as in “tight” formations, and formation damage, which can occur in any formation type. A common and very successful stimulation option, matrix acidizing, utilizes acids that react to remove mineral phases restricting flow. Depending on the formation and acid type, flow is increased by removing pore-plugging material; or by creating new or enlarged flow paths through the natural pore system of the rock. However, higher-temperature environments present a challenge to matrix acidizing effectiveness. High temperatures can negatively affect stimulation fluid properties and certain acid reactions. Thus, careful fluid choice and treatment designs are critical to successful high-temperature matrix acidizing. With proper fluid selection, design, and execution, matrix
acidizing can be applied successfully to stimulate hightemperature oil & gas wells and geothermal wells. These types of wells have some common features, but they also have significant differences (e.g., completions, mineralogy, formation fluids and formation flow) that influence stimulation designs and fluid choices. This paper summarizes best practices for designing matrix acidizing treatments and choosing stimulation fluids for hightemperature oil & gas wells and geothermal wells. Included are case histories from Central America. Lessons learned about differences and commonalities between stimulation practices in these these well types are also discussed.
Introduction As today’s rate of finding new reserves is lower than in previous decades, exploration has turned more to deeper basins. Deeper wells are typically hot (greater than 250º F, for example). Permeabilities Permeabilities are also often lower and occasionally are the result of a network of natural fissures. Offshore wells in the Gulf of Mexico are now reported to reach bottomhole temperatures of 500º F. Recently discovered gas fields offshore Brazil have bottomhole temperatures ranging from 350 to 400º F. Over the past years, great improvements in matrix acidizing have taken place, parallelling the developments in hydraulic fracturing. Provided that the forecasted production/injection results make economic sense, matrix acidizing is still simpler, often less risky, and more economic to implement than hydraulic fracturing. Sophisticated laboratory equipment, expertise, and well testing software can help the engineer diagnose production or injection damage effects and mechanisms – making it easier to select proper well candidates and optimize job design. Treatment placement is better ensured through the use of chemical or mechanical diversion methods and technologies, and placement tools (coiled tubing, straddle packers, etc.). On-site quality control is enabled by modern sensors, monitors and software, enabling the engineer to determine the evolution of skin with time, and radius of formation treated. Modern blending and pumping equipment have provided the means to mix acid continuously without the need for pre-blending fluids. This eliminates the need for 10 mixing tanks on location, and enhancing safety on location . Matrix acidizing treatments are designed to remove or bypass formation damage by injecting fluids of low pH into the
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reservoir below fracturing pressure. In sandstones, the primary objective is to remove any existing formation damage and restore the reservoir permeability (in the near-wellbore region) to its original state or as close as possible. This process results in matrix flow with a flow capacity approaching the undamaged well (skin = 0). Similarly, in limestones, the primary objective of a matrix acidizing treatment is to bypass formation damage through the formation of channels, called wormholes. This process results in “true” stimulation (or stimulation of the formation radially from the wellbore) — thus the potential for negative skin — and the possibility of a flow capacity greater than in the undamaged well. Properly designed and executed acid treatments provide a method for improving the productivity of oil and gas wells and injectivity of injection wells. The success of these treatments depends to a great extent upon proper acid selection and treatment design. Today, with the increasing shift to unconventional sources of hydrocarbon and energy, there is an increasing application of matrix acidizing for stimulation of wells in very hightemperature environments. For example, some reservoirs in the Gulf of Mexico have bottomhole temperatures up to 500º F, and more recently a new gas field offshore Brazil has temperatures up to 400º F. In general, this environment requires greater due diligence because of the unique complexities associated with use of acids at elevated temperatures. Technological and process improvements over the years haveenabled the oil service industry to provide fit-for-purpose matrix acidizing solutions for high-temperature environments. Compared to hydraulic fracturing, matrix acidizing can be a much simpler, more economical and at times a relatively lower-risk stimulation technique. Sophistication with laboratory equipment, well testing software and technical expertise allows a greater number of practitioners to properly select well candidates and optimize job design. Improved quality assurance of job execution can also be realized through improvements in the reliability of placement tools rated for high-temperature use (coiled tubing, straddle packers, etc.) Modern process-controlled acid blending and pumping equipment has elevated on-site quality control and safety management. Along with the quality improvements from modern sensors, monitors and software, skin evolution (changes) can be assessed in real time and changes in treatment volumes can be made "on the fly." This paper discusses matrix acidizing of sandstone reservoirs in High-Pressure/High-Temperature (HPHT) wells, producing geothermal wells and Steam/Hot Water Injection (SHWI) wells. Despite the focus on sandstone matrix acidizing, most of the challenges here are equally applicable to limestone formations.
High-Pressure/High-Temperature (HPHT) wells Wells with pressures and temperatures exceeding 10,000 psi (69 MPa) and 300° F (149° C), respectively, are generally termed High-Pressure/High-Temperature (HPHT). Such wells
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are becoming more common as the oil industry searches for newer hydrocarbon production opportunities in deeper horizons. In addition to greater depths, more wells are now drilled and completed in increasingly hostile downhole environments. The advent of HPHT wells has resulted in a step change in the metallurgy required for high-pressure completion tubulars and equipment. It is not possible to simply increase the API tensile grade of the tubulars, since HPHT wells usually contain some amount of hydrogen sulfide (H2S), carbon dioxide (CO 2), corrosive brine, or combinations that can be extremely corrosive. High-alloy steels are now the standard metallurgy used in oil & gas production wells drilled into deep, hot reservoirs. Alloyed steels used in the petroleum industry are called corrosion-resistant alloys (CRA). The most commonly used CRAs are the chromium alloys, such as 13Cr and duplex stainless steels. In extreme environments, highly alloyed nickel austenitic stainless steels, such as inconel, incoloy, and hastelloy, are used. There is increasing concern when the wellbore contains highalloy metals, such as stainless and duplex steels, as they are susceptible to hydrogen embrittlement and chloride stress cracking. When combined with the possibility of erosion corrosion caused by high production rates, acidizing HPHT wells poses further risk.
Geothermal wells Geothermal energy is today an important energy resource. Regions where geothermal energy sources occur generally lie along boundaries of tectonic plates of the earth. Given the rising cost of conventional hydrocarbon resources, geothermal energy today is a viable option in some areas. Currently, geothermal resources provide energy for direct heat and electric power generation in over 30 countries including United States, Italy, Iceland, Azores (Portuguese islands), Turkey, Russia, China, Japan, Indonesia, New Zealand, Philippines, Mexico, Nicaragua, El Salvador, Guatemala, and Costa Rica. For example, in the Philippines, geothermal production provides 27% of the country's total electrical generation. In the U.S., electrical energy generated from geothermal resources is more than twice that from solar and wind combined. In 1972, the worldwide capacity of geothermal power plants was about 800 MW. Today it is 8900 MW21. One major advantage of geothermal energy is that it is a renewable energy source that does little damage to the environment. Geothermal power plants emit only about 1 to 3% of the sulfur compounds and < 1 to 4% of carbon dioxide (C02) emitted by coal- and oil-fired power plants. Certain binary cycle geothermal power plants have no emissions at all. Geothermal energy originates from heat contained in the earth’s crust. When magma (molten rock) come quite close to the surface where the crust has been thinned, faulted, or fractured by plate tectonics, heat is transferred to water and forms steam, hot water or a mixture of both. Once the temperature of a hydrothermal resource is around 220 °F and above, it can be used to generate electricity. Most electricity-
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producing geothermal resources have temperatures from 300 to 700 °F, but can up to 1,000 °F in some areas. Geothermal wells are relatively shallow, with well depths typically ranging from 5,000 to 9,000 ft. Reservoirs are normally underpressured relative to a full column of fresh water. And wells are produced at maximum attainable rates through either open hole, slotted liner or casing strings (tubing-less) to minimize friction loss. A well life of 20 years is normally considered adequate for geothermal wells. However, through acidizing, wells may be able to safely produce for considerably longer and at higher commercial rates. Geothermal field performance can also be enhanced through stimulation of injection wells; given the importance of injectors, this will be discussed separately in the next section. The most common workover operation in geothermal wells is cleaning mineral deposits from inside the well casing. Most common deposits are calcite, silica and silica-rich sulfide deposits, and various mixed scales. Drill cuttings removal (from natural fractures) in new producers and injectors may also be a need. Geothermal wells generally produce from naturally fractured andesite formation rock (volcanic quartz) although certain fields produce through the primary rock permeability. Therefore, acidizing in geothermal wells is most closely analogous to sandstone acidizing. However, the fluid system to be used and the treatment method may greatly differ depending on the type and magnitude of the rock permeability. Despite the existence of a g reat number of geothermal wells in the world, the number of wells stimulated is relatively low when compared to their oil and gas counterparts. Among the different stimulation techniques in oil and gas wells, only matrix acidizing can be considered useful in geothermal wells, and relatively speaking, it has been the predominant stimulation method attempted. This is mainly due to: • •
• • •
Advances in acid chemistry 1,4 More detailed investigations of the interactions between acid systems and rocks (and scales) with different mineralogies 14, 5 Inability to achieve formation parting pressure during fluid injection into geothermal wells (thermal effects) Formations are typically naturally fractured Limited budget assigned to stimulation (largely considered unconventional in geothermal fields)
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case of geothermal wells, reinjection of geothermal fluids (non-steam phase) is often necessary to miminize land subsidence tendencies, recharge the reservoir, and manage disposal of large produced volumes of brine over the longer term. It is not uncommon for an individual geothermal injection well to dispose of heat-depleted brine at rates up to 100,000 bbls per day. Therefore, most of these injection wells are completed with large-diameter wellbores. Injectivity decline may occur, especially if fluids are not handled properly before injection. Even with the best brinehandling conditions, long-term injectivity loss may still occur. In geothermal wells, reduced well injectivity is usually associated with scale deposition inside the surface injection line, well completion tubulars and perhaps in the formation (natural fractures). The most common scales are quartz (silica and silicates), carbonates and sulphates. Loss of injectivity can also be related to reservoir interference of neighboring injection wells or mechanical integrity problems in the completion tubulars. Suspended solids and corrosion products in injection wells usually require special surface processing and acidizing treatments to make large-scale reinjection or water disposal plans viable.
Challenges in HPHT Well Acidizing As the search for oil & gas continues in deeper horizons, there are evolving factors that must be considered with respect to acid stimulation: •
Complex completions — Completion designs are continually advanced to meet a number of challenges, such as higher temperatures, higher bottomhole pressures, more severe well trajectories, and, of course, well economics. The use of completion tools to perform multiple services (such as gravel packing and stimulation in a single trip) has become common in some offshore basins. Under this scenario, completion tools must be designed to present low-torque valves and long endurance against erosion and corrosion. These completions must address future well interventions, preferably rigless.
•
High-pressure matrix injection limitation — HPHT wells normally possess a high fracturing gradient, indicative of low formation matrix permeability. Acid stimulation of either producer or injectors requires a high injectivity rate in order for the formation to “accept” acid. Proper acid chemistry is necessary; viscous acid sytems, for example, may require a high injection surface pumping pressure. If not considered in advance, there may be undesirable consequences, such as inordinately long pumping time (and greater exposure of tubulars to acid), and higher safety risk (acid remains longer in surface pumping lines, under high pressure).
•
Treatment placement / diversion limitations — Chemical diverters are limited in temperature, typically up to about 250° F. High temperatures and deep environments limit
Nevertheless, broad implementation of acid stimulation in geothermal fields has not been established. However, its production enhancement potential is considerable. In recent years, there have been a few papers reporting success with matrix acidizing of geothermal wells 3, 10. Most geothermal wells continue to produce without stimulation, other than in few selected areas.
Steam and Hot Brine Injection Wells Injection wells are an important part of a geothermal project or enhanced oil recovery / steam-stimulation project. Maintaining injection is essential for long-term, economic operation. In the
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use of placement techniques such as packer systems and sometimes coiled tubing. •
•
•
Special tubular metallurgies and corrosion — Protection of completion and production equipment is a primary concern during HPHT acidizing operations. This concern increases when the wellbore contains high-alloy metals, such as stainless and duplex steels, that are susceptible to hydrogen embrittlement and chloride stress cracking. The higher the temperature, the more difficult it is to protect metal against corrosion, and the more required inhibitor loadings increase, resulting in greater likelihood of formation damage. In addition, protection times are reduced dramatically, which can limit well stimulation treatments (for example, fluid volumes caused by pump time limitations). These problems become increasingly severe in formations with bottomhole temperatures greater than 250 oF (l20 oC). However, a combination of organic acids (acetic and formic) can be used instead of HCl in HPHT applications to minimize corrosion and stress cracking problems. Although the base cost of an organic acid blend is higher than that of HCl, reduction in inhibition costs can result in a final acid blend that is both technically and economically acceptable. Alternatively, a modestly reducing acid concentration, minimizing contact time, or using cooling preflushes may also be feasible options. HPHT wells are typically expensive, and well metallurgies have been continually upgraded in order to maximize well life. Extensive lab testing is required to ensure acid corrosion protection before a final acid formulation is chosen. Flowback of acid treatment — When flowing back producer wells after acid treatment, there is a risk that unspent or partially spent acid may return to surface. This requires special HSE procedures and practices to handle flowback fluid, such as proper return tanks in which the return fluids can be neutralized and properly discharged. Perceived risk — Sometimes the dispersant package included in corrosion inhibitors can increase the tendency for acid/oil emulsions to form in areas in which the formation crude contains high concentrations of paraffin or asphaltene.
Challenges in Geothermal Well Acidizing Geothermal wells present special acidizing challenges. Matrix acidizing treatments must address the following issues: Corrosion of completion — Corrosion in geothermal environments, in which all conditions for severe electrochemical reactions exist, is recognized as a major problem, except for wells producing dry steam. The effect of 300 to 700 °F temperatures and an aqueous environment makes corrosion protection a big issue. Metallurgies become more difficult to inhibit against acid corrosion as temperature increases. Corrosion can result in a series of undesirable reaction products, which can cause plugging in the formation (iron sulfides are among the most notorious). Acidizing geothermal wells requires large water cooldown pads in order
to reduce temperature, preferably to the 200 ºF range, where corrosion inhibition can easily last for the duration of the acid treatment. Corrosion may also be induced by the production fluid itself (especially hot brine). Therefore, some completions may require a post-flush containing corrosion inhibitor or even continuous injection of corrosion inhibitor. Placement/diversion method limitation — Placing acidizing fluids in geothermal wells must be done by “bullheading” or through coiled tubing. Bullheading necessarily requires high pumping rates, as the acid does spend faster under high temperatures. In some cases, when acid stimulation is preceded by a mechanical clean-out with workover rig, the acid is placed through drill pipe. High treatment rates are normally required — and are beneficial — for stimulation of the long intervals and natural fractures typically encountered in geothermal formations. This differs from typical oil- and/or gas-bearing sandstone formations, in which acid is injected into small pore spaces (matrix conditions) and across relatively short intervals. Injection pressure is not an issue, as wells often take fluid on vacuum. The injection rate (and acid volume) is of greater importance. Because oil is not present in geothermal wells, there are no issues related to wax, paraffin, asphaltene or emulsions. Therefore, simplified treatments (reduced additives, larger volumes, fewer steps) are applicable in geothermal wells. Single-step acid treatments are possible because conventional preflushes (including acid) and overflushes are not necessary. Recent experiences with geothermal well stimulation in Central America have proven that using special acid systems with complexation chemistry (in HCl or HF systems), as well as HF systems with low total acidity, have been very successful. Application has been through bullheading (even at low rates) down production tubing. Treatment diversion has proven to be ineffective in geothermal wells. Open-hole or slotted liner completions are common, with the intervals exceeding several hundred meters. High-temperature foam systems may improve zone coverage, but not reliably or extensively. Gelling agents for thickening acid are not effective in geothermal liner completions. Highrate acid injection has proven to be the only reliable method for effective acid placement, but this technique is limited to wells with one production zone. If a well has more than one zone, selective acid stimulation is required. In such cases, preliminary well logging (spinner and temperature surveys) is necessary to evaluate and design the best placement procedure. •
Flowback of acidizing fluids — As acidized production wells are returned to production, there are naturally environmental concerns. Geothermal fields are often near populated areas, and wells are tested and flowed to the atmosphere. Noise and odors affecting the local population are of concern for the geothermal operators when flowing back wells after stimulation. Overdisplacement of acid (on the order of thousands of cubic meters) is very effective in minimizing this situation. Generally, wells are allowed to heat up after acidizing, but that can take from several days to several weeks
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before well production testing can be conducted. The combined effects of over-displacement and heat-up time – in conjunction with improved fluid designs – can minimize or eliminate flowback odors and populationrelated problems. Air compresion equipment may be needed to pressurize wells that are unable to flow by themselves after acidizing. Operators must be aware of this need before intervention. Erosion of production lines may occur if drill cuttings are produced back during blowdown of a well after stimulation. Care must be taken in this regard. A temporary flow line may be required until solids production has ceased. •
Various/mixed scales — The main damage mechanism in geothermal wells is scale deposition (commonly in the wellbore or in liner slots/perforations). Scales are deposited by different causes, including incompatibility of invading fluids (completion, acidizing, drilling fluids) and produced fluids (water with high content of dissolved minerals, hot brine). Also, natural pressure drops in the reservoir or wellbore can result in carbonate scale formation. As fluids cool, saturated levels of dissolved silica become over-saturated, and silica scale can drop out regardless of reservoir fluid type (hot water, or dry steam, or combination of both). In general, these scale deposits are more common and severe in geothermal operations than in oilfield operations. Although the scale deposits encountered are basically similar, the following parameters result in some important differences: 1) 2) 3)
Reservoirs with “exotic” mineralogies High temperatures (up to 700 °F) with relatively low reservoir pressures High mass flow rates
Some of the most commonly encountered scales are barium sulfate, heavy metal sulfides from large temperature drops; pressure-sensitive scales such as calcium sulfate; calcium carbonate (CaCO 3) from CO2 flashing; and silicon oxides (quartz, SiO 2) and barium sulfate (BaSO4) from ion-rich brine that deposits these compounds upon cooling in the wellbore. Also, as mentioned before, since the mass flow rate in geothermal wells is usually very high, massive amounts of scale deposits can accumulate over short periods of time. The acceleration of deposition usually increases once the process starts, and tubular (orifice) decreases as scale builds within. Also, reservoir pressure declines with time and cumulative production may exacerbate the conditions leading to scale formation. As a result, the flow restriction caused by scaling deposits has a greater influence than that seen in most oilfields. Some scaling may be so intensive or so hard that a mill or high pressure jetting nozzle may be required.
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The inhibitors in use are typically polyacrylate, polymaleic acid or phosphonates. Their application typically requires a threshold dosage of about 2 to 10 mg/kg. A chemical metering pump on the surface can be used to introduce the treatment via a ¼ or ½-in. corrosion-resistant capillary string to a depth below the flashing level in the well. •
Invasion of drill cuttings to formation natural fractures — Geothermal well production intervals are normally below the water gradient and are usually drilled using air, foam, mud, water or combinations. In any case, drill cuttings invasion into the natural fractures may impair the flow capacity of the natural fractures and limit production below natural capacity. Additional damage can be created by the use of damaging additives in the mud system. It is challenging to dissolve cuttings and remove mud damage. Proper laboratory acid dissolution tests are required to establish appropriate acid design.
•
Limited Information — Geothermal operation practices differ from oilfield operations in that most geothermal operators do not take steps to obtain, store, analyze and track individual well information and performance trends. Coring, production tests, injection tests, build-up and drawdown tests, and other information that could be important and useful is usually partially or totally missing. A change in the mind of the geothermal industry is necessary in this regard. The benefit of acid stimulation of geothermal wells is apparent even with the minimal information available. Imagine the potential if the gathering of such information were standard practice.
There is a considerable upside in production enhancement potential in geothermal fields if a broader implementation of acid stimulation takes place. Proper maintenance and operation of geothermal wells is of vital importance in the success of a geothermal project. The worldwide geothermal industry has been growing modestly in the last two decades. These assets are now aging and in some cases, repairs or rebuilding are necessary to extend their life and maintain generation capacity. Geothermal wells are a reliable source of power and it is best if the wells can be allowed to run continuously. Considerable experience has been gained in how best to operate and maintain the geothermal wells.
Variations of Acid Treatment Design for Geothermal Wells and Oil & Gas Wells While sandstone acidizing in oil and gas wells has advanced, and geothermal well acidizing has taken advantage of those advancements and knowledge, certain methods and rules of thumb do not apply to (and should not be applied in) geothermal wells. Consider the following: •
Injecting a scale inhibitor downhole can mitigate scale buildup by “coating” the calcite crystals with a long molecule polar substance as they form, thus preventing them from adhering to each other and to the tubulars.
Acid designs based on formation mineralogy — Due to the volcanic nature of the rock, geothermal mineralogy differs in complexity and acid reactivities. Sometimes geothermal formations contain iron minerals (chlorite,
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pirite, hemtite, etc.), as well as zeolites and calcite. They are often present as fracture-filling minerals, rather than as grains or as pore-filling mineral phases. Therefore, geothermal well acid designs based on oil and gas sandstone mineralogy guidelines have usually resulted in poor or limited stimulation response. Field experiences in Central America geothermal acidizing candidates have shown outstanding results using HCl-complexing agent solutions and high HF concentration/low total acidity solutions (also containing complexation agent). •
•
Acid fluid design — With geothermal acidizing, most treatments can be effectively addressed by using HCl and HCl:HF acid systems. HCl systems are used alone to remove calcite scale inside tubulars, or as a preflush for HCl:HF acid treatments. Rock/acid solubility tests are recommended to evaluate the use (or not) of HCl preflush, if actual formation (core) sample is available. HCl:HF systems are used to enhance injection/production by removing damage created during the drilling process and to dissolve silica scale for injections wells. High HF concentrations (5% to 9% HF) have proven to be effective in geothermal well stimulation. Treatment volumes — Oil and gas sandstone acidizing is usually performed in wells with known intervals, and treatment volumes are usually expressed in gallons per foot based on porosity, permeability and treating radius. Most geothermal fields are completed in openhole or with slotted liners to produce from formation faults or through natural fractures. The effective production/injection interval is not always accurately known nor easily determined. Most production/injection improvement in geothermal wells comes from scale removal, enhanced flow paths resulting from fracture face rock dissolution, removal of mineral phase from natural fractures and fissures, or drill cuttings removal. Determining proper treatment volumes in geothermal well acidizing should consider several factors: 1) 2) 3)
4)
5)
Objectives: Carbonate scale removal; silica scale removal; cuttings removal; formation stimulation Placement method: Coiled tubing; bulheading Contact time required: Depends on whether objective is scale removal (calcite or silica) or reservoir stimulation Pumping rate: Depends on placement method, stimulation objective (scale vs. formation treatment), logistics and facilities Type of well: New well, damaged old well
Depending on these factors, volume requirements can vary quite a bit. In general, treatment volumes are much larger in geothermal well acidizing than in oil and gas sandstone acidizing. One thing geothermal wells have in their favor is that complete damage removal is not necessary. Partial removal of damage may eventually result in complete damage removal when the treated well produces back. The high-rate, high-
energy backflow from geothermal wells can blow out damage that was not dissolved by acid. Plugging material that was softened, broken up or detached from downhole tubulars and fracture channels can be produced back through a largediameter casing completion.
General Geothermal Well Acidizing Procedures Successful acid treatment prodcedures for Central America geothermal wells are summarized below. In Central America, bullheading procedures have been developed. Treatment designs are based on the objective(s) of the particular acid job. •
New Wells: New wells are stimulated just after drilling in order to maximize production/injection potential from the outset. Jobs are conducted with a drilling rig. For these wells, the volume of HCl acid preflush is calculated based on core sample solubility tests. Table 1 summarizes the basic procedure. Treatment Stage
Treatment Volume & Rate
1. Preflush and cooling
Fresh water: High rate using rig pumps to cool wellbore below 200 °F.
2. Preflush: 10% HCl – 15% HCl (with 0.2% vol HV Acid)
32,000 gallons @ 10-14 bpm
3. Main acid: 4% HCl-5% HF + organophosphonic acid complex (HV-acid)
40,000 gallons @ 10-14 bpm
4. Overflush: Fresh Water
40,000 gallons @ 10-14 bpm
5. Overflush: Fresh water
Several hours at low rate depending on water supply and availability.
Table 1: Basic acidizing treatment procedure for new geothermal wells •
Old Geothermal Production Well: Production wells can decrease output over time as a result of scale deposition. Where severe scale deposition is present inside the competion, a mechanical/chemical treatment is preferred. When available, coiled tubing is a powerful method for simultaneous mechanical and chemical removal of scale. Otherwise, mechanical clean-out can be conducted with a workover rig followed by a bullheaded acid stimulation. Table 2 summarizes a basic procedure for a rig bullheading geothermal acidizing treatment in old production wells.
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Treatment Stage
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Treatment Volume & Rate
1. Preflush and cooling
Fresh water: Well used to be cooled down after mechanical scale removal. Wellbore below 200 °F.
2. Preflush: 15% HCl (with 0.2% vol HV Acid)
25,000 gallons and above depending on the injection test results after the mechanical clean out @ 10-14 bpm
3. Main acid: 4% HCl-5% HF + organophosphonic acid complex (HV-acid)
15,000 gallons @ 10-14 bpm (Optional Stage but recommended to improved results) Same volume as main acid stage or minimum 1 hour @ 10-14 bpm
4. Overflush: Fresh Water
5. Overflush: Fresh water
Several hours at low rate depending on water supply and availability.
Table 2: Basic acidizing treatment procedure for old geothermal wells •
Old Geothermal Injection Wells: Silica scale can be a problem in geothermal water injection wells. Injection rate can be dramatically reduced by scale deposition in the formation fracture network and in the completion. Injection reduction can also originate in the injection surface pipe system. Scale formed inside the surface injection facilities can become broken and dislodged from the pipelines when contacted by cold water, a routine occurrence. Contraction — expansion cycling of the pipe due to hot/cold/hot water flow — causes this phenomenon. If a filtering system is not installed before the wellhead, the dislodged silica scale will reach the well bottom and eventually build to reduce injection capacity. In cases where severe scale deposition is present inside the competion, a mechanical/chemical treatment is preferred. When available, coiled tubing provides an effective mechanism to simultaneously perform mechanical and chemical treatment. Otherwise, mechanical clean-out can be conducted using a workover rig followed by a bullheaded acid treatment. Several bullheaded acid jobs have been performed in Central America geothermal wells to date to improve water injection in silica-scaled wells. Treatments have been very successful. For wells with HCl/rock solubility below 10%, a “single-step” acid treatment procedure (using an HF acid system) is applied. Table 3 sumarizes a basic procedure for bullheading geothermal acidizing treatment in silica-scaled geothermal wells.
Treatment Stage
Treatment Volume & Rate
1. Preflush and cooling
Fresh water: High rate using rig pumps to cool wellbore below 200 °F.
2. Preflush: 7.5% - 10% HCl + organophosphonic acid complex (HV-acid)
15,000 gallons or lower depending on scale and formation solubility tests. Can be eliminated in single-step HF treatments.
3. Main acid: 4.5% HCl-8% HF + 4% organophosphonic acid complex (HV-acid)
25,000 – 40,000 gallons @ 10-14 bpm first half of the stage volume. @ 1 bpm second half of the stage volume Same volume as main acid stage @ 10-14 bpm
4. Overflush: Fresh Water 5. Overflush: Geothermal Injection water
Geothermal injection system can be placed back on line.
Table 3: Basic treatment procedure for old injection wells
Case Histories HPHT Well Example An HPHT well located in South America was producing from a sandstone reservoir consisting of 95% quartz and 4% kaolinite. The dominant cements in this sandstone are kaolinite and silica overgrowths. Kaolinite also exists as a loosely packed pore filling material. Permeability ranges from 70 to 300 mD, with fairly low porosity (8% to 13%). Formation damage contributors include oil-based drilling fluid effects and kaolinite and quartz fines migration. Laboratory core flow tests supported pumping an unconventional 6% HF equivalent main acid treatment in this well. The well treatment initially increased production rate from 2,100 to 3,700 BOPD (76% initial incremental oil production). Three months after treatment, production rate increased further to over 4,000 BOPD. The treatment steps are shown in Table 4 below: Treatment Step
1) Crude Oil displacement 2) Formation water displacement 3) Preflush – 15% Acetic Acid 4) Main Acid – Acetic:6% HF 5) Overflush – 15% Acetic Acid 6) Diverter – N2 foam 7) Repeat steps 3-6 (4 more times) 8) Displacement – 3% NH 4Cl/Diesel
Volume (gal/ft)
50 100 50
The acetic/HF main acid mixture also contained a phosphonic acid complex to stabilize acid reaction products in solution. Fluid compatibility testing identified the potential for iron induced acid sludging. Therefore, the tubulars were pickled
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with 7.5% HCl to remove rust and debris prior to the HF treatment. Also, an acetic acid preflush and overflush, as well as an acetic acid:HF blend were used to ensure compatibility. Average injection rate during the treatment was approximately 2 BPM with a maximum pressure of 4500 psi. Five stages were used to treat the interval.
After the acid stimulation jobs, the wells were shut in for several weeks to allow temperature build-up. Table 7 compares the pre- and post-job wellhead pressures (psi) and Power Generation Potential (MWe) at operational power conditions (100 psi).
Geothermal Well Example
WELL
Test Temp ( F)
15% HCl AVERAGE SOLUBILITY
5% SSA AVERAGE SOLUBILITY
% SOLUBILITY TOTAL
194
27.75 %
50 %
77.75 %
˚
1
194
2
9.2 %
26.1 %
35.3 %
Table 5: Acid Solubility of Drill Cuttings
Based on the HCl solubility and the previously known calcite deposition problems, it was decided to use both HCl and HF acid systems. The HCl acid system formulation included an organophosphonic acid complex (ion-complexation agent, HV acid). This system is designed to remove carbonate and ironcontaining scales and inhibit re-precipitation or re-scaling in one step. The HF formulation involves controlled in-situ generation of HF based on the organo-phosphonic acid complex acidity and hydrogen ion release characteristics. Table 6 sumarizes the treatment designs.
WELL
Fow Rate (bpm)
15% HCl with 0.2% vol organophosphonic acid Volume
4% HCl-5% HF + 1.5% organophosphonic acid Volume
1
14
26,418 gal
18,493 gal
2
14
26,418 gal
15,851 gal
Table 6: Acid Treatment Volumes & Pumping Rate
Generation Potential (MWe)
Pre
Post
Pre
Post
1
322 %
48
131
2.2
7.1
2
340 %
Not stable
113
Not stable
3.4
WELL
Two geothermal production wells in Central America were treated to remove damage created during the drilling process. Both wells were considered to have high calcite deposition potential. Neither was able to reach and maintain flowing conditions, and they were thus shut for 8 and 11 years, respectively. Very limited information on rock mineralogy was available and only a few drill cuttings were sent to the lab to test for acid solubility testing. Table 5 sumarizes the average solubility per well and acid system. Acid stimulation treatments were performed by bullheading acid through the wellhead to avoid extra rig costs.
WHP (psi)
MWe Increase (%)
Table 7: Pre- and Post-Treatment Well Compari son
Geothermal wells were successfully stimulated with new technology HT acidizing fluids, with cost-effective procedures based on experience in geothermal acidizing. After years of shut in, both wells improved dramatically and could establish flowing conditions sufficient to be placed online to the geothermal power generation plant.
Steam Injection Well Examples Two geothermal injection wells in the Asia Pacific region were treated in 2006 to remove large deposits of high-silicacontent scale in slotted liner, liner/formation annulus and in formation fractures. Given the relative absence of calcite material present, these jobs were conducted with a single-step, buffered 9% HF treatment. The procedure for scale removal involved a three-step approach to assess the efficacy of different scale removal techniques: 1st Step – Scale drill-out (SDO) 2nd Step – High-efficiency jetting nozzle (on drill pipe) that includes stress cycles with water 3rd Step – High-efficiency jetting nozzle (on drill pipe) that includes stress cycles with 9% Single-Step HF
The results from these treatments are shown below with the injectivity after each stage. Incremental increases were realized with each technique; however, the greater benefit was seen with the use of the acid treatment. Injectivity Pre-Job Injectivity (kg/hr) After SDO (kg/hr) After Jetting w/water (kg/hr) After Jetting w/9% HF (kg/hr)
Well 1 300 472 634 924
Well 2 255 280 338 436
SPE 109818
9
Conclusions Very high-temperature oil and gas wells and geothermal wells can be acidized successfully. HPHT wells and geothermal wells can be stimulated successfully utilizing unique HF systems with higher HF concentrations. Experience in acidizing geothermal wells in Central America indicates that understanding mechanisms restricting production (or injection), and understanding treatment objective(s) are the keys to success. Acid stimulation of geothermal wells, in particular, is underutilized. The potential production enhancement benefit is tremendous but can only be accomplished through broader implementation of acidizing in geothermal fields.
Acknowledgements The authors would like to thank BJ Services for permission to publish this paper. The authors also wish to thank to LAGEO S.A de CV for permission to publish well information and preand post-stimulation results. Thanks also to the people involved in the field execution of the treatments, and for those tireless scientists and engineers, from the different disciplines, trying always to reach new frontiers of matrix acidizing, in its many aspects.
5.
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6.
Hashem, M.K., Nasr-El-Din, H.A., Hopkins, J.A., ‘An Experience in Acidizing Sandstone Reservoirs: A Scientific Approach’, paper SPE 56528 presented at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, TX, 3-6 October.
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9.
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11.
Taylor, K.C., Nasr-El-Din H.A., Saleem, J.A., ‘Laboratory Evaluation of Iron-Control Chemicals for High Temperature SourGas Wells’, paper SPE 65010 presented at the 2001 SPE International Symposium on Oilfield Chemistry held in Houston, TX, 13-16 February.
12.
Rae, P., Di Lullo, G., ‘Single Step Matrix Acidizing with HF – Eliminating Preflushes Simplifies the Process, Improves the Results’, paper SPE 107296 presented at the 2007 SPE European Formation Damage Conference held in Scheveningen, The Netherlands, May 30-June1.
13.
Rae, P., Di Lullo, G., ‘Matrix Acid Stimulation – A Review of the State-Of-The-Art’, paper SPE 82260 presented at the 2003 SPE European Formation Damage Conference held in The Hague, The Netherlands, 13-14 May.
14.
Thomas, R.L., Nasr-El-Din H.A., Mehta, S., Hilab, V., Lynn, J.D., ‘The Impact of HCl to HF Ratio on Hydrated Silica Formation During the Acidizing of a High Temperature Sandstone Gas Reservoir in Saudi Arabia’, paper SPE 77370 presented at the 2002 SPE Annual Technical Conference and Exhibition held in San Antonio, TX, September 19- October 2.
SI Metric Conversion Factors ºAPI bbl cp ft ºF gal lbm psi MW
141.5/(131.5 + ºAPI) 1.589 874 1.0* 3.048* (ºF – 32)/1.8 3.785 412 4.535 924 6.894 757 2.390585
E – 01 E – 03 E – 01 E – 03 E – 01 E + 00 E – 05
= = = = = = = = =
g/cm3 m3 Pa·s m ºC m3 kg kPa cal/sec
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