Prevent Scale Deposition Research Articles

IMPROVEMENT OF THE OPERATION OF SUBMERSIBLE CONTAINERS OF DOWNHOLE UNITS FOR OIL PRODUCTION

The stable growth of oil production in the Russian Federation observed in recent years is characterized by commissioning of new fields and off-balance hydrocarbon reserves. In these conditions, occurrence of complications during operation of wells by mechanized method significantly increases the costs of enterprises and reduces the cost-effectiveness of oil production. The article presents statistical data on failures of submersible pumping units caused by complicated operating conditions. It is shown that one of the most widespread complicating factors is high corrosive activity of the well fluid and development of scaling that lead to failures of submersible pump units, reducing their operation time below the warranty period. It is indicated that out of the currently existing methods of preventing scale deposition and reducing the intensity of corrosion of downhole equipment in oil production the most technologically and economically feasible is the chemical method, which is realized through the use of inhibitors. Nowadays producers of oil and gas equipment produce in batch borehole containers for solid and encapsulated inhibitors. The main disadvantage of these submersible containers is uneven dosing of reagents into the wells. Experimental downhole submersible containers for liquid reagents are characterized by unstable and unreliable operation, complexity and high cost. The presence of significant disadvantages of experimental and commercially available submersible containers has necessitated the development of the most versatile, reliable and efficient products. The authors propose a design of a mechanized downhole submersible container equipped with a plunger pump and performing a uniform feeding of an inhibitor into a well.

Flexible, Linear, and Systematically Expanded Tetraphosphonate Bolaamphiphiles and Their Inhibition Performance against Calcite and Barite Scale Formation

Oilfield scaling is one of the most prevalent water-based oilfield production problems. Chemical inhibitors are often used to combat and prevent scale deposition. The phosphonate functional group is commonly used in many scale inhibitors. A series of bolaamphiphilic alkyldiamine tetrakis(methylenephosphonic acid)s have been synthesized from 1,X-diamines, where X in the polymethylene spacer groups has an even number of 2–12 carbon atoms. These inhibitors were coined CX-T (X is the number of C atoms between the N atoms on the inhibitor backbone, and T stands for tetraphosphonates). All tetraphosphonates showed excellent compatibility with calcium ions at 100 ppm or less, i.e., normal scale inhibitor dosage levels. At higher dosages, the calcium concentration and length of the alkylene spacer chain between the nitrogen atoms also determine the compatibility. Crystal structures were determined for the calcium “complexes” with the tetraphosphonates C2-T, C4-T, C6-T, and C8-T. All tetraphosphonates were investigated for calcite and barite scale inhibition under dynamic conditions using oilfield produced waters based on the Heidrun field water composition, offshore Norway. For calcite scaling, tetraphosphonates with ethylene (2 carbons) and hexamethylene (6 carbons) spacer groups gave the best inhibition performance. For barite scaling, the best inhibition was observed for the tetraphosphonates with ethylene and tetramethylene spacer groups, which relates to the ability of both disphosphonate moieties to interact with a single barium ion.

Investigating the Effect of Carbon Nano Additives on the Adsorption of GR & T Scale Inhibitor

Scale deposition is a prominent issue in the flow assurance that needs to be prevented to avoid reduction in the oil production. Scale includes various types of non-organic salts that might deposit in the reservoir and/or in the production tubing under different production conditions. A common practice to prevent scale deposition is to carry on scale inhibitor squeeze treatment. However, conventional squeeze treatment suffers from slow adsorption rate, limited adsorption amount and quick desorption rate. Collectively, the conventional squeeze treatment suffers from short lifetime and the operation must be repeated multiple times a year, which adds more cost. Nanotechnology is an emerging technology which has various applications in the oil and gas industry. Consequently, Nano carbon-based enhanced squeeze treatment (NCEST) was introduced to overcome squeeze treatment shortcomings and enhance the treatment lifetime through coating the nearby area of the wellbore with carbon based nanoparticles. However, the application of recent nanofluid-based coating technology was limited to specific scale inhibitors (EDTA & PPCA) as well as particular nanomaterials (CNT & GO). This work is aimed at investigating the adsorption of a new scale inhibitor (GR&T scale inhibitor) into four different carbon nanomaterials (Graphene Nano plates, Multi-layer graphene, carbon Nanotubes and Functionalized-carbon Nanotubes) under a static condition. Due to time and apparatus constraints, the scope of the work will be limited to investigating the adsorption of (GR & T) scale inhibitor which is provided by Petronas to only four carbon nanomaterials at concentrations within a range of (2000-20,000 ppm). In this research, the adsorption of (GR & T) scale inhibitor into four different carbon Nano additives was tested and screened. Then, the best carbon nanomaterial (Graphene Nano plates which has not been studied before in the zone of Nano carbon-based enhanced squeeze treatment) was selected for the next stages of investigation in which the optimum concentration as well as the optimum condition of dispersion were identified. Also, the role of surfactant addition with the introduction of a new, safer and cut-price surfactant (gum Arabic) on the adsorption and dispersion improvement was approached. Furthermore, the effect of soaking time upon the Nano additive adsorption was detected. On top of that, the maximum adsorption capacity of the carbon nanomaterial with higher concentrations of GR &T scale inhibitor was tested as well.

Carbon-based nanocoating for extended lifetime of conventional scale inhibitor squeeze treatment in sandstone reservoirs

Scale inhibition squeeze treatment is a common practice to prevent scale deposition within the downhole utilities, valve applications, and tubular components of the oil and gas producing wells. The conventional squeeze treatment has a short lifetime due to the reservoir rocks' limited adsorption of scale inhibitors and the quick desorption rate. As a result, this process has to be repeated multiple times per year, leading to massive increases in operational costs. Carbon-based nanomaterials are known for their high specific surface area, making them an attractive coating agent to enhance the capability of rocks’ surfaces to adsorb chemicals such as scale inhibitors. In this paper, carbon-based nanomaterials of graphene nanoplatelet (GNPs) and three different types of carbon nanotubes (CNTs) are proposed as novel nanocoating to extend the lifetime of the conventional scale inhibitor squeeze treatment. A natural polymer of Gum Arab (GA) was used to graft the nanomaterials surfaces to ensure a homogeneous and stabilized coating solution. The adsorption of diethylenetriamine penta (methylene phosphonic acid) (DTPMP) scale inhibitor into GNPs and CNTs was investigated using a UV–Vis spectrophotometer. Various characterization techniques such as FTIR, Raman spectroscopy, and XPS were performed to evaluate the interaction between DTPMP and the proposed nanocoating (GNPs/CNTs). Based on UV–Vis results, GNPs was found to be the optimal coating agent with an adsorption capacity of 135 mg/g at ambient temperature and 114 mg/g at 96 °C. Its coating gets saturated with DTPMP within 1 h of interaction. Increasing the initial scale inhibitor concentration was found to increase the adsorption capacity of GNPs. Based on the core flooding conducted on Berea sandstone, the injection of nanocoating into the core sample reduces the permeability by only 12%. Finally, the injected nanomaterial was safely transported through the core, and the primary retention mechanism was adsorption rather than physical filtration/plugging.

Experimental study of one-step economical retarded sandstone acid

The objective of this study is to experimentally evaluate a new acid combination of HEDP: CH3COOH as a retarded acid to minimize some limitations of high-temperature sandstone acidizing, such as fast acid-rock reaction and secondary precipitation pipeline corrosion. In this work, the acid–base titration, core-powder solubility test, scale deposition test, corrosion rate measurement and corefloods were carried out to evaluate the performances of the acid combination, including acidity characteristics, retarded performance, preventing scale rate, corrosivity and improving permeability. And then the microstructure and mineral content in sandstone samples were observed and analyzed with SEM–EDS. The results of evaluation tests indicated that the new acid combination has excellent performances on retarded rate, preventing scale deposition, permeability enhancement and lower corrosivity, comparing with conventional mud acid. The results of SEM and EDS showed that the microstructure and mineral content of sandstone changed after acid treatment. Compared with mud acid, the new acid system can react more with small particles on sandstone surface and less with the skeleton of samples and the decrease in the contents of Mg, Al, Na, K, Ca and Fe is relatively lower.

Electrochemical enhancement and inhibition of calcium carbonate deposition

Abstract Calcium carbonate is by far the most widespread scaling material. Its deposition in pipes and flowlines has been a long-standing problem for many industries. Hence, a lot of research is devoted to scale inhibition. One of the calcium carbonate scale management methods relies on removal of calcium ions from scaling solution by electrochemically enhanced deposition. Application of potential between two electrodes may result in oxygen reduction and water electrolysis. Both processes change the local pH in close proximity to the electrodes. Solution close to the anode is becoming acidic while that close to the cathode alkaline. Solubility of calcium carbonate is pH dependent. The alkaline pH in the vicinity of the cathode promotes precipitation of calcium carbonate. On the other hand, the acidic environment near the anode prevents anode from scaling. In this paper we show how the cathodic and anodic processes, respectively, accelerate and prevent scale deposition on graphite electrode surfaces. The growth of calcium carbonate at different calcium ion concentrations and different voltage magnitudes applied were followed using X-ray computed tomography. The morphology of the deposited calcium carbonate was studied using the scanning electron microscopy. The polymorphic forms of calcium carbonate deposited at different voltage magnitudes were identified using X-ray powder diffraction. A strong correlation between the scaling rate, the average crystallite size and the voltage applied was observed.

Water-soluble carboxymethylchitosan as green scale inhibitor in oil wells

A water-soluble carboxymethylchitosan (CMC) was prepared in water/isopropanol (2/8) medium, at 10 °C, and characterized by UV–vis, FT-IR and NMR techniques. Its performance as an environmentally friendly scale inhibitor in oil wells was evaluated under the physicochemical conditions of oil wells in northeast of Brazil, by using SEM, visual compatibility and dynamic tube blocking test. The synthesis conditions led to a degree of carboxymethylation of 0.45 and water-solubility in all pH range studied (1–11). CMC acted as a scale inhibitor of CaCO3 under synthetic brine medium, presenting a minimum inhibitor concentration (MIC) of 170 ppm (1000 psi, T = 70 °C). SEM images showed that CaCO3 crystals were deformed by CMC, which was attributed to effective interactions of CMC through its carboxylate ions and lone pair of electrons on OH and NH2 groups with calcium ions, preventing scale deposition.

Characteristics of scale deposition in gas-condensate wells

Formulation of the problem. The article deals with one of many possible complications that may occur in the process of gas and gas-condensate wells operation. In fact, scale deposits can be observed in wells at all stages of field development. Scale deposition inside the tubing has a negative impact on hydrocarbons production. This causes the decline of gas production rate. The major factor of scale deposits formation is overtreatment of water solution with different salts and the effect of field hydrogeology. Thus, special methods are used in practice to prevent scale deposition and combat this complication.The purpose of the article. To define the causes of scale deposition, the detailed analysis of well operation should be performed that will help to take the appropriate prevention measures. Methods. The authors’ own achievements as well as the research results of domestic and foreign investigators made the methodical basis for the article.Results. The production data of the wells from different fields have provided the information about scale deposition. Many of the described ways of combating and eliminating scale deposits are expensive, their use causes well downtime and production decline. Therefore, it has been proposed to take easy-to-use preventive measures.Scientific novelty and practical significance. During investigation of the production researches results and calculations the specialists of UkrNDIgas proposed to classify the wells with reduced production capacities within the field into groups and categories according to the degree of total salinity of formation water. It has been proposed to control the process of scale deposition by the results of water analysis, taken from the wells. Each well has the set limit values of salinity.Based on the operation analysis of wells in different fields, the calculated predicted results of scale deposition in wells according to the existing procedures and their comparison with the factual data from production fields, the specialists of the institute have developed the efficient complex multi-faceted measures.

Synergistic inhibition effect between 4-amino-5-methyl-4H-1,2,4-triazole-3-thiol, citrate ions and polycarboxylate for corrosion protection of C1010 steel in cooling water system

The inhibition efficiency of 4-amino-5-methyl-4H-1,2,4-triazole-3-thiol compound was studied by itself as well as in a mixture that included co-additives (polycarboxylate and citrate) for C1010 steel in a typical ground cooling water environment. Weight loss measurements, solution assay analysis, electrochemical impedance spectroscopy and potentiodynamic measurement techniques were utilized for the assessment of corrosion inhibition efficiency. The inhibition efficiency was found to be 70%, with 100 ppm inhibitor concentration, without any co-additive. This case was attributed to limited access of existing inhibitor molecules on the surface in the presence of various insoluble compounds that are readily formed with various cations and /OH− ions. In order to prevent scale deposition and strengthening of the inhibition efficiency, polycarboxylate was used as the dispersive agent and citrate ions were introduced for synergism. The SEM-EDS analysis clearly depicted that the mixture formulation (10 ppm 4-amino-5-methyl-4H-1,2,4-triazole-3-thiol + 1 ppm polycarboxylate + 2 ppm citrate) could prevent scale deposition and the attack of corrosive environment. Furthermore, the inhibition efficiency of this mixture was determined to be 89%. FTIR studies indicated the presence of both 4-amino-5-methyl-4H-1,2,4-triazole-3-thiol and citrate in the protective surface layer.

Impact of Antiscalants on the Fate of Barite in the Unconventional Gas Wells

Abstract Formation of barite (BaSO4) scale is a potential problem for unconventional (shale) gas extraction, as the excessive scale can reduce well productivity by plugging the proppant pack. This study was designed to evaluate the impact of antiscalants on the formation and transport of barite particles through proppant sand under well-controlled laboratory conditions using batch and column experiments. Extensive attachment of BaSO4 particles to proppant sand was observed at typical background salinity and in the absence of antiscalants due to relatively large barite particle size and screened electrostatic interaction. Presence of polymeric antiscalants can enhance the mobility of BaSO4 particles by decreasing their size and providing electrosteric repulsion. Ethylene glycol that may be added to hydraulic fracturing fluid to prevent scale deposition can reduce the size of BaSO4 precipitates but has no impact on the deposition of BaSO4 particles during transport through proppant sand. Polymaleic acid and...

Non-aqueous vs aqueous overflush scale inhibitor squeeze treatment in an oilfield offshore Norway

Abstract The field under study is located offshore Norway. Due to the need for pressure support, it is anticipated that seawater will be injected and continuous gas lift will be used in a number of wells. Barium sulphate scale deposition is expected as high concentrations of barium have been measured in the formation brine. Scale inhibitor squeeze treatments will form an important part of the scale mitigation plan. Squeeze treatments entail the injection of an inhibitor chemical to prevent scale deposition, the treatment generally consists of the following stages: preflush, main treatment, overflush and shut-in. The preflush stage is normally injected to condition the formation, with typically a mutual solvent being deployed to improve inhibitor retention and well clean-up times. The chemical slug is injected in the main treatment stage, generally as an aqueous phase. The overflush stage is deployed to displace the chemical slug deeper into the reservoir and thus expose the chemical to a greater surface area of rock to achieve a higher level of retention. Commonly, the overflush is deployed as an aqueous phase; however, it is not always feasible to inject large volumes of water in wells which are water sensitive or which already require artificial lift. Water is denser than hydrocarbons, and therefore more difficult to lift. In these circumstances, a non-aqueous overflush, generally marine diesel, may be preferable. The diesel volumes required are feasible for scale squeezes during the first years, although some additional logistic effort and costs are to be considered. The objective of this paper is to compare squeeze treatment lifetime achieved by conventional aqueous and non-conventional squeeze treatments, where non-conventional refers to treatments where the overflush is split into aqueous and non-aqueous stages, typically diesel being used for the non-aqueous stage. The simulation and optimisation calculations were performed using a specialised near wellbore model for scale treatments, where a two-phase flow model was used to describe the displacement process during the multi-stage overflush. Splitting the overflush was found to reduce the squeeze lifetime marginally, as the non-aqueous overflush is not as effective as a purely aqueous overflush in propagating scale inhibitor deeper into the formation. However, this is counterbalanced by the fact that a smaller volume of water needs to be injected in the formation, and so reducing the risk of formation damage and most important for this particular case, a smaller volume of water will need to be lifted, so the well may be set back to production with ease.

Agglomeration behavior in fluidized-bed evaporator for thermal seawater desalination

A novel seawater desalination process using a fluidized-bed evaporator was proposed to prevent scale deposition on the heat-transfer surface for the co-production of salt and pure water. In this evaporator, seawater is fed from the top of the bed and evaporation is caused by collision with heated fluidized particles. Because the liquid feed in the proposed evaporator may cause agglomeration of fluidized particles leading to defluidization, the agglomeration behavior was investigated. Seawater evaporation experiments indicated that when seawater is fed into the fluidized bed, agglomerates of fluidized particles are formed by liquid bridge of seawater feed initially. Subsequently, when liquid bridge breaks during evaporation, solid bridge forms between the particles, leading to their growth. With the repetition of this process, the agglomerates gradually increase. When the size of the grown agglomerates exceeds the mass that can be supported in the bed by the fluidizing gas, the accumulation of agglomerates begins. To describe the agglomeration behavior, we used the force balance of liquid bridge, solid bridge and hydrodynamic forces. Finally, a conceptual model, which can explain the agglomeration behavior, was developed.

Evaluating the Damage Caused by Calcium Sulfate Scale Precipitation During Low- and High-Salinity-Water Injection

Summary Scale deposition is a serious oilfield problem, when two incompatible waters interact chemically and precipitate minerals. Typical examples are seawater with a high concentration of sulfate ions and formation water with high concentrations of calcium, barium, and strontium ions. Mixing these waters may cause precipitation of calcium, barium, and/or strontium sulfate. The removal of the entire sulfate content from seawater might be a costly process and requires highly advanced techniques (nanofiltration). This study was conducted to investigate the damage caused by deposition of calcium sulfate precipitation and to describe the damage by use of the material-balance method, and then a new technique is proposed to prevent the damage caused by calcium sulfate scale. Coreflooding experiments were performed to assess the damage caused by calcium sulfate and a computed-tomography (CT)scan was used to locate the damage inside the core. Chelating agents, such as hydroxyl ethylene diamine triacetic acid (HEDTA), ethylene diamine tetra acetic acid (EDTA), and hydroxy ethyl imino diacetic acid (HEIDA), were used to prevent scale deposition in the Berea sandstone cores. The pressure drop across the core caused by scale precipitation will be predicted analytically. The results of the experimental data showed reduction of permeability by 20% from its initial value after seawater injection, caused by calcium sulfate precipitation. The results of the new analytical model showed that in approximately 1 month, the injection will stop or the injection pressure will exceed the fracture pressure of the formation. High-salinity-water injection caused severe formation damage, and the injectivity declined faster compared with the low-salinity-water injection. The material-balance calculations showed a good match between the experimental, field, and predicted data. The developed model of the pressure drop caused by calcium sulfate precipitation was used to predict the pressure drop across the core, and its result was in a good match with the experimental results. The new method was effective in preventing and removing sulfate precipitation.

地下水制御型高効率ヒートポンプ空調システムの研究開発

The developed system included a newly developed groundwater-source heat pump system capable of hybrid operation combining free cooling and heat pumping was installed. In order to prevent scale deposition in the piping and equipment through which groundwater was to flow and clogging of the wells and ground, a water treatment system was installed. Winter test operation was started in November, 2011. Summer test operation was started in June, 2012, and ended in September. Test data obtained in the first year of operation were analyzed. The successful test operation results thus obtained indicate that the developed system is superior in performance to a typical conventional system.

Control and management of brine disposal for inland desalination plants

Desalination is a solution for a range of water supply problems. A higher recovery rate is an important goal because it increases production and improves cost effectiveness. As the recovery ratio increases, however, the concentration of dissolved ions in the brine becomes high enough to form scaling caused by precipitation of super-saturated salts. These precipitates might form a scale not only on membranes’ surfaces but also in the brine disposal line. In order to prevent scale formation, special antiscalants are added to the reverse osmosis feed. It is important to emphasize that antiscalants only delay the onset of precipitation, resulting in possible scale precipitation in long outlet pipes. In addition to the tendency of scaling, brine disposal can be a serious environmental concern that needs to be studied and considered when building a desalination plant. Marine brine disposal can cause three possible hazards: precipitation on the pipe walls, soil and marine contamination. Since 2004, Mekorot has exclusively operated and maintained a unique 30-km long brine disposal pipeline to the Mediterranean Sea with the required permission from the Ministry of Environmental Protection. The pipe is used to dispose brine streams from the Gat and Granot BWRO desalination plants, which are located in southwestern Israel near the city of Ashkelon. A brine disposal pipe was developed by Mekorot as part of a coastal aquifer rehabilitation project and was chosen as the most economic solution for these two plants. A few years ago, an experimental system was run to obtain the design parameters for preventing scale deposition from a concentrate solution. Through the design of optimal operation of brine pipes, we prevent soil contamination and avoid scale deposition from concentrate solutions from both desalination plants. This paper reviews the management and control of the brine disposal pipe, including early scale detection, as well as the standard and special monitoring programs for the long brine disposal pipe at Mekorot.

보일러내 열 전달 효율 개선을 위한 초음파발신기 개발

보일러나 열교환기의 관 벽에 부착되는 스케일 방지용으로 설계된 초음파 발신기는 전기적 에너지를 초음파로 변환시켜주는 자왜소자와 발생된 초음파를 부하매질에 전달하는 도파봉으로 구성된다. 본 논문에서는 진동자로 사용되는 자왜소자의 형상설계와 진동자에서 발생된 초음파를 증폭시켜 부하매질로 전달하기 위한 몇 가지 형태의 도파봉에 대해 이론해석을 수행하여 필요한 사양을 도출하였다. 최종적인 도파봉의 길이는 음압 측정을 통해 선정하였다. 마지막으로 제작된 초음파발신기를 사용하여 보일러와 유사한 조건에서 스케일 방지효과를 확인하였다. Ultrasonic transmitter used for scale prevention in boiler or heat exchanger is composed of the magnetostrictive material which transforms electric energy into ultrasonic wave and the horn which amplifies generated ultrasonic wave and transfers it into medium loaded. In this paper, we have performed the shape design for magnetostrictive material and analyzed a few type of horns which amplify generated ultrasonic wave and found each solution theoretically. Final length of the horn has been determined by measuring the sound pressure in medium between theoretical value and experience data. At last we have given the results of our study for the effects of ultrasonic wave irradiated by manufactured ultrasonic transmitter on preventing scale deposition on test pipe under the similar condition to boiler.

Advantages of a New Chemical Delivery System for Fractured and Gravel- Packed Wells

Summary The deposition of scale, such as carbonates and sulphates, in production facilities represents a serious operational problem that can result in significant well productivity decline. Current scale control strategies can involve significant capital and operational expenditure. Development work, involving laboratory testing and a field trial, has demonstrated the technical benefits of a revolutionary method of downhole scale inhibitor delivery that can prevent scale deposition for a significant proportion of a well's lifetime. The method involves the slow release of scale inhibitor from porous proppants. Economic analysis indicates that significant benefits can be derived for a variety of field development and well completion types. The greatest economic benefits would be realized for subsea and minimum facility installations with high intervention costs, where squeeze delivery of inhibitor or mechanical workover are used for scale control. In addition, major economic benefits can be realized for horizontal wells with unfavorable pressure regimes, multilateral-type completions, multiple fractured wells, and many conventional completion types. The new chemical delivery method offers cost reduction through reduced deferred oil, efficiency of chemical usage, and fewer workovers using coil tubing and intervention vessels. Economic analysis has indicated that for some conventional and advanced well types, fracturing a well and deploying proppant impregnated with scale inhibitor, is economically preferable to a conventional strategy of squeeze treatment in an unfractured well. An additional economic benefit of proppant impregnated with scale inhibitor is increased well productivity. The benefit is derived from the combined effect of improved gel breaking, and scale inhibition during well cleanup. This has been demonstrated in laboratory testing and would appear to be confirmed by field observations. A further benefit of applying scale inhibitor as chemically impregnated proppant is the immediate treatment of produced water when water breakthrough occurs. This feature avoids the formation damage that can occur before squeeze treatment mobilization. In addition, for some applications involving large fractures there is the potential for lifetime well treatment. This paper describes the laboratory work, the field trial, and the economic benefits of the new product.

Field Performance of a Liquid Scale Inhibitor Squeeze Program

Introduction Although much has been written on the theory of preventing scale deposition, little in the way of field experience has been published. The production performance of the West Texas wells discussed here indicates that the inhibitor squeeze program has been effective in preventing scale buildup on the formation. preventing scale buildup on the formation. Introduction Scale in producing oil wells is a recognized problem in the oil field. This problem is magnified in waterflood areas where volumes of water produced are increased over primary levels. A great deal of progress has been made in scale mitigation products in recent years. Much has been published about the theory of preventing scale deposition and the process of squeeze treating (see References). Only a few case histories are available, however, on long-term, successful programs of squeeze-treating producing oil wells with a liquid scale inhibitor. The data presented here have been obtained from a long-term program of squeeze-treating producing oil wells with a liquid scale inhibitor on two West Texas waterfloods that produce from the Grayburg formation (dolomite) in the Foster field, Ector County, Tex. The development of the scale inhibitor program that is presently used in the Foster-South Cowden Coop Area and the South Foster Unit in the Foster field began in late 1967, when a solution was being sought for the problem of scale deposition in producing oil wells. This scale deposition was producing oil wells. This scale deposition was causing severe wellbore damage. Scale removal workovers had demonstrated only short-lived successes, and scale had been identified on both down-hole equipment and in returns during cleanout operations on wells in the area. The scale was composed of calcium sulfate and calcium carbonate, with most of it being calcium sulfate. The inhibitor program developed was designed to prevent the growth of these types of scale. Selection of Scale Inhibitor Type There are two types of scale inhibitors that can be used for applications of this nature: liquid scale inhibitors and solid scale inhibitors. Solid scale inhibitors were quite popular at one time, but, for several reasons, liquid inhibitors have received total acceptance for this program. Solid inhibitors must either be placed during fracturing or be dumped into the wellbore and allowed to dissolve slowly. Fracture stimulating a well each time a new treatment of scale inhibitor is needed is not economically attractive because it necessitates an expensive stimulation every 1 to 2 years. Dumping the solid inhibitors into the wellbore is not adequate since it does not insure that the inhibitor will properly contact the produced fluids. Liquid inhibitors, on the other hand, are quite flexible and easier to handle. Another important drawback to the use of solid scale inhibitors is that they are usually of the polyphosphate type and subject to chemical reversion. polyphosphate type and subject to chemical reversion. Improper placement of a solid polyphosphate inhibitor or a change in produced fluid volumes during the treatment could result in overtreatment. This over-treatment can cause the polyphosphates to revert to an orthophosphate which, if precipitated into a scale, is harder to remove than the carbonate and sulphate scales for which the wells were treated to begin with. JPT P. 812

Removal and Inhibition of Calcium Sulfate Scale in Waterflood Projects

Abstract The problem of preventing calcium sulfate scale deposition has become increasingly important in the last few years due to the increasing use of waterflood as a means of secondary recovery. Many methods have been proposed for removing or preventing scale deposition. A few chemicals and treatment methods have been effective, but there are many ineffective scale-removal agents and inhibitors still an the market today. This paper describes the results of a laboratory testing program that evaluated 98 potential-scale inhibitors and 20 scale-removal agents. The paper also describes a field testing program in which various removal methods and inhibitor placement techniques were evaluated in 19 wells, and it compares field and laboratory results. Introduction Deposition of inorganic scale in producing wells has been a costly problem in the petroleum industry. Scale not only restricts production, but causes inefficiency and failure of production equipment. Scale problems have an even greater impact on the economics of waterflood operations where injection wells are subject to deposition of inorganic sulfate and carbonate deposits. Scale control usually involves complementing treatments that first remove the deposited scale, then chemically prevent its recurrence. There is no effective all-in-one treatment that will both remove and inhibit scale deposits. In many cases, scale control must begin with a program of inhibition since some inorganic scales are difficult - even impossible - to remove by chemical treatment once they form. These scales, usually containing barium or strontium can be prevented from forming by proper use of inhibitors. Fortunately, most scales occurring in producing formation are calcium sulfate or calcium carbonate. These deposits normally can be removed chemically before further treatment to prevent recurring scale deposits is begun. Scale composition frequently changes during the production history of the well, causing many scales that are initially subject to removal treatments to become unresponsive to subsequent treatment. This makes it imperative to obtain the best scale-removal treatment possible before the scale inhibition program is started. Samples of the deposit need to be collected and analyzed to determine the proper treatment. Two techniques have been used to place inhibitor in the formation. One technique involves placing slowly-water-soluble polyphosphate crystals in the formation by hydraulic fracturing. The polyphosphate limits the choice of fracturing fluid since it is sensitive to acid or heavy brine and reverts to inactive calcium orthophosphate. Liquid phosphonate inhibitors also have been placed during fracturing operations with the expectation that they will leak off and adsorb to the rock matrix. Using liquid inhibitors in fracturing treatments will prevent scale deposition, but this is a comparatively expensive method of replacing inhibitor unless a fracture job is already planned for remedial stimulation. The second placement method is a matrix squeeze technique in which liquid inhibitors are injected into the formation at subfracturing pressures. This method is becoming increasingly popular because it is frequently undesirable to fracture the formation in a waterflooding operation. In addition, this technique is cheaper than fracturing. There are many chemicals that will prevent scale deposition. However, most will not remain in the formation long enough to make them economically feasible as inhibitors. To improve the economics of inhibitor squeeze treatments, a thorough laboratory investigation was undertaken to select the best scale inhibitors and determine what changes would be necessary to improve their formation longevity. This investigation was followed by a field development program in which removal chemicals, scale inhibitors, and treating techniques were evaluated on a cost-to-performance basis. The laboratory phase of the program necessarily began with a study of scale compositions and the downhole physics-chemical relations that cause deposition.

Sequestering Agents for Prevention of Scale Deposition in Oil Wells

Abstract Precipitation of insoluble mineral deposits, in and near the wellbore and on down-hole well equipment, lowers production rates considerably in many oil fields. Scale deposits have been prevented in industrial equipment by conditioning the water with phosphate sequestering agents. Such agents inhibit crystal growth so that, when the ions combine to form insoluble compounds such as calcium carbonate, calcium sulfate, and barium sulfate, these minerals remain in colloidal suspension. A 12-to–40 mesh, granular phosphate has been used successfully to prevent such deposition in oil wells. The phosphate granules are mixed with the sand injected into the producing formation during fracturing treatments. Tests show that the phosphate is slowly dissolved by produced well fluids, preventing scale deposition within the formation and on down-hole well equipment. More than 30 wells have been treated by this special phosphate fracturing method, and production data indicate that the problem of formation plugging by mineral deposition is being effectively overcome. Introduction A frequent oilfield problem is the well which declines sharply after being completed and tested for a good initial production rate. Often there is no apparent reason for the rapid decline, and the reservoir is known to hold large amounts of oil. In many of these cases, deposition of calcium carbonate, calcium sulfate, or barium sulfate may be curtailing production. Mineral deposition occurs in the wellbore, in formation flow channels adjacent to the wellbore, and on down-hole well equipment such as pumps, rods, and screens. Such deposition may be caused by changes in reservoir equilibrium near the wellbore, or by the mixing of incompatible brines from different formations in openhole completions. These difficulties occur both in primary and secondary production wells. Such deposits can sometimes be dissolved or disintegrated by acidizing, depending upon the amounts of carbonate they contain. If, however, the deposit consists principally of sulfates, it is usually necessary to fracture the well to overcome this obstruction. A summary was made recently of the results of fracturing treatments on 187 waterflood production wells. This summary covers three years, and includes some treatments completed as recently as a few months ago. In virtually every case the remedial fracturing treatments were necessitated by mineral deposition in the well that plugged off the flow channels and reduced production.