Sand Management in Oil and Gas Production PDF

CHAPTER VI SAND MANAGEMENT Sand in oil and gas production refers to granular particles of rock or mints mate particles can composton nuate, feldspar, ano rock These particles can range from fine silt to coarse gravel and are ofen found in se particies ones ide hydrocarbons. and prael roa occurs w...

CHAPTER VI SAND MANAGEMENT Sand in oil and gas production refers to granular particles of rock or mints mate particles can composton nuate, feldspar, ano rock These particles can range from fine silt to coarse gravel and are ofen found in se particies ones ide hydrocarbons. and prael roa occurs when surface witche earamlized from i reservoirtion brought to the soir pressures, extracted oil or gas. This rebe trif ered by high resent pressures, dish production rates, and certain rock formations that sense of sand islodge and enter the production stream. The presence of sand in production facilities can have several adverse effectessors, and sise abrasive wear on equipment such as pumps, compressors, and separators, leading to premature failure and increased mainteduction costs. Additionally, sand can reduce the efficiency of production systems by clogging valves, filters, and separators, impacting fluid flow dynamics and leading to operational disruptions. In some cases, unmanaged sand production can also result in environmental contamination if not properly Figure 44. Sand Production contained and disposed of. Several factors affect sand production, including reservoir characteristics such as rock strength, porosity, and permeability. Weak or unconsolidated formations are more prone to sand production. High production rates and low reservoir pressures can destabilize the reservoir rock and mobilize sand. The design and execution of well completions, including the integrity of the wellbore and completion equipment, also influence sand production. Furthermore, drilling practices, such as the choice of drilling fluids and techniques, can impact the likelihood of sand production by affecting reservoir stability. and production or sanding is the production of the formation sand alongside with the formation fluids (gas, oil and water) due to unconsolidated nature of the formation. The migration of formation sand caused by the flow of reservoir fluids. Figure 45. Sand production erodes hardwares, block tubulars, creates downhole cavities, and must be separated and disposed in the surface. The production of sand is generally undesirable since it can restrict productivity, erode completion components, impede wellbore access, interfere with the operation of downhole equipment, and present significant disposal difficulties.Understanding these factors and implementing effective sand management strategies are essential to minimizing sand production and its impact on production facilities. Forces That Impact Sand Production Understanding the forces that impact sand production is crucial for effective sand management in oil and gas production. Several key factors influence the stability of reservoir rock and the likelihood of sand mobilization. These include the role of cementing materials in binding sand grains, the effects of cohesion or capillary forces, and the strength of grain-to-grain cementation. 65 Each of these forces plays a significant role in determining the stability of the reservoir and the potential for sand production. By comprehensively evaluating these factors, operators. 1\. Cementing Material Cementing materials play a critical role in determining the stability of the reservoir rock. These materials bond sand grains together, providing structural integrity to the rock formation. In consolidated formations, cementing materials, such as calcite, silica, or clay minerals, fill the spaces between sand grains and bind them together. This binding action helps prevent sand from becoming mobilized and produced with the hydrocarbons. When cementing materials are present in sufficient quantities and are well-distributed, they contribute to the strength and stability of the reservoir rock. However, in cases where these materials are insufficient, poorly distributed, or degraded, the rock may become weak and unconsolidated, increasing the risk of sand production. Effective cementing practices during drilling and completion are essential to ensure that the formation maintains its integrity and reduces the likelihood of sand production. 2\. Cohesion (Capillary Forces) Cohesion, or capillary forces, results from the interaction between fluids and sand grains within the reservoir. These forces arise due to the wetting properties of the fluids present in the reservoir, which affect the adhesion of sand grains to one another. In a common fluid phase, such as oil or water, capillary forces can contribute to the stability of the sand grains, helping to hold them together and prevent their mobilization. The presence of a wetting phase that interacts favorably with the sand grains can enhance cohesion and reduce the likelihood of sand production. However, changes in fluid composition, pressure, or temperature can alter the wetting characteristics and capillary forces, potentially destabilizing the sand grains and increasing the risk of sand production. Understanding and managing these fluid interactions are important for effective sand control and minimizing production issues. 3\. Limited Weak Grain-to-Grain Cementation Limited or weak grain-to-grain cementation refers to the insufficient bonding between individual sand grains within the reservoir rock. In formations where the cementation is weak, sand grains are not effectively bound together, making the rock more susceptible to disintegration and sand production. This situation can result from a lack of sufficient cementing materials or ineffective cementation processes during the rock\'s formation. Weak grain-to-grain cementation can lead to a higher propensity for sand production as the reservoir rock becomes unstable under production conditions. Factors such as reservoir pressure changes, production rates, and fluid interactions can exacerbate the effects of weak cementation, leading to increased sand mobilization. Addressing weak cementation through improved well design and completion practices is crucial for minimizing sand production and maintaining operational efficiency. can better manage and mitigate the challenges associated with sand production. Factors Affecting Sand Production in Oil and Gas Operations Sand production is a common issue in oil and gas extraction, particularly from weak or unconsolidated formations. Several factors influence the likelihood and severity of sand production, Including reservoir rock properties, production rates, well completion design, drilling practices, and reservoir conditions. Below is a detailed examination of the factors affecting sand production: 1\. Properties of Reservoir Rock The inherent properties of the reservoir rock, such as rock strength, porosity, and permeably, are fundamental factors that determine sand production: Rock Strength: The mechanical integrity of the reservoir rock, which depends on how well the rock grains are bonded together, is crucial in preventing sand production. Weak or unconsolidated formations, where the rock grains are loosely bound or poorly cemented, are more prone to sand production. These formations can easily disintegrate under the stresses applied during production, leading to the mobilization of sand particles into the wellbore. ii. Porosity and Permeability: Porosity refers to the void spaces within the rock that can store hydrocarbons, while permeability measures the ablity of fuids to flow through these voias Rocks with high porosity and permeability tend to have weaker structural integrity, especially if they are not adequately consolidated. In such cases, the rock matrix can become unstable, making it susceptible to sand production when fluids flow at high rates or pressures change. 2\. Production Rates and Reservoir Pressures The dynamics of production rates and reservoir pressures significantly impact sand production: High Production Rates: Rapid extraction of hydrocarbons increases the fluid velocity within the reservoir and through the wellbore. This increased velocity can erode the surrounding ii. rock, causing the detachment and mobilization of sand particles. Additionally, high production rates can create turbulence, which further exacerbates sand production. Low Reservoir Pressures: As reservoir pressure depletes over time, the support provided to the rock structure diminishes. This can cause the rock to collapse or erode, resulting in secomes motion. When the pressure drop is significant, the dellablization ode, resurint in becomes more pronounced, and the likelihood of sand production increases. 3\. Well Completion Design The design and implementation of well completions play a crucial role in managing sand production: Wellbore Integrity: The condition of the wellbore and the quality of completion materials influence sand production. Poorly designed completions, inadequate casing, or poor cementing can lead to wellbore instability, allowing sand to migrate into the wellbore. ii. Completion Equipment: The type and condition of completion equipment, such as screens and gravel packs, are critical in controlling sand production. Properly designed and maintained sand control equipment prevents sand from entering the production stream. However, if the equipment fails due to improper design or maintenance, sand can reach the surface and cause operational issues. 4\. Drilling Practices The techniques and materials used during drilling operations can also impact sand production: i. Drilling Fluids: The choice of drilling fluids affects the stability of the reservoir rock. Improperly formulated drilling fluids can alter the formation conditions, potentially increasing sand production. Properly designed drilling fluids help maintain formation stability and minimize sand production risks. II. Drilling Techniques: The methods used during drilling, such as rotary drilling or hydraulic fracturing, can influence sand production. Techniques that exert high stress on the formation or cause significant rock fragmentation can increase the likelihood of sand production. Careful selection of drilling techniques is essential to minimize these impacts. 5\. Degree of Consolidation The degree of consolidation of the reservoir rock is a significant factor affecting sand production: Unconsolidated Formations: Poorly consolidated or unconsolidated formations, particularly Sandstone reservoirs with permeability ranging from 0.5 to 8 darcies, are more prone to sand production. These formations lack sufficient cementation to hold the grains together, making them susceptible to disintegration and sand production under production stresses. 6\. Reduction in Pore Pressure 18 the reservoir pressure depletes over the life of a well the support provided 1 the overlying rock layers diminishes: 67 i. Production Engineering lI Formation Instability: A reduction in pore pressure increases the stress on the rock matrix, leading to grain detachment and the creation of lines that are produced with well fluids, This phenomenon is especially common in reservoirs that have weakly consolidated or unconsolidated formations. 7\. Increasing Water Production Sand production may increase with the onset of water production as the water cut rises: Water Flooding Operations: Methods like surfactant foding, polymer flooding, and aln. The flooding, followed by water or brine injection, can lead to considerable water production. The sand production. presence of water can reduce the cohesive forces between sand grains, resulting in increased 8\. Production Rate Threshold Every reservoir has a specific threshold pressure below which sand production is minimized: i. Exceeding Threshold Pressure: Engineers often ignore this threshold to maximize production rates, especially from sandstone reservoirs. Producing at rates higher than this threshold can lead to sand production, which may not be economically viable in the long run 9\. Reservoir Fluid Viscosity due to potential damage to equipment and loss of reservoir integrity. The viscosity of the reservoir fluid also affects sand production: Viscous Drag Forces: High reservoir fluid viscosity results in higher frictional drag forces on the formation sand grains compared to low-viscosity fluids. The effects of viscous drag are more pronounced in heavy oil reservoirs containing high viscosity, low gravity oils, leading to sand production even at low flow velocities. /Induced Causes of Sand Production operational causes leng practices) AV= 1 Frictional drag Force. Sand production can be significantly influenced by various operational and environmental factors, which induce stress and lead to the destabilization of reservoir rock. Key induced causes include: 1\. High Production Rates: When production rates exceed critical limits, the increased flow Pin Pressure. velocities and pressure differentials can induce mechanical failure in the reservoir rock. This e sanô failure can propagate and cause sand to migrate along with the hydrocarbons. High Productio production rates can disrupt the equilibrium of the reservoir, leading to the detachment of sand grains from the rock matrix and their subsequent entrainment in the production stream. 2\. Onset of Water Production: The introduction of water into the production stream can adversely affect the stability of the reservoir rock. Water production can dissolve the - cement cementing materials that bond sand grains together, reducing the rock\'s structural integrity. dissolves Additionally, water can alter the cohesive forces, such as capillary pressure, that help to keep bond sa sand grains in place. This disruption in cohesive forces can lead to sand mobilization and gral increased sand production. 3\. Poor Drilling, Completion, and Production Strategies: Several practices during drilling, completion, and production phases can contribute to increased sand production: i. Horizontal Well Placement and Deep Perforations: Landing a horizontal well or perforating close to gas-oil and oil-water contacts can expose the well to high-pressure differentials and unstable rock formations. These practices can lead to increased sand production due to the Stress and pressure changes introduced by such well placements. High Skin Effects: High skin, resulting from mechanical or chemical damage during drilling, completion, and workover activities, can create significant pressure drops around the wellbore. This increased pressure drop can exceed the compressive strength of the rock matrix, causing sand production. wellbore clean-up. Inadequate Rock Property Knowledge: A lack of accurate knowledge regarding the incorrec geomechanical and petrophysical properties of the reservoir rock can lead to poorly designed and executed drilling and completion strategies. Inadequate understanding of these iv. propistes san result in strategies that do not account for the rock\'s stability, increasing the risk of sand production. Production Engineering lI ineon fracture: in high-pressure, high temperature (HP.HT) enviroling ef, cl can injection for cooling can induce thermal fractures in the rock. The sudden cooling erecomes dessablizeds and fractures, leading to sand production as the rock matrix becomes destabilized. V. Cyclica Shock Loading: Repeated star-up and shut-down cycles can create cactico shock loading conditions on the reservoir rock. This dynamic stress can lead to the fractuand of tructock matrix and the detachment of sand grains, increasing the likelihood of sand production. Impacts of Sand Production in Oil and Gas Operations Sand production can have significant detrimental impacts on both surface and subsurface oil ans gas production systems. It can lead to loss of well potential, integrity issues, reduction in process facility capacity, and complications in reservoir management. Below are the key impacts of sand production: 1\. Impact on Well Potential With the onset of sand production, operators typically choke back the well to control the production rate and manage sand influx. However, this often results in a severe loss of deliverability the economic output of the well. or well potential. The need to reduce production rates to mitigate sand-related issues directly impacts 2\. Integrity Issues Sand production poses several integrity challenges for downhole and surface equipment. Erosion can damage downhole tools and wellhead systems. Choke valves, which regulate the flow of fluids, are particularly vulnerable to rupture due to severe erosion. Sand-laden flow can erode subsea networks and pipelines, leading to increased maintenance costs and potential safety hazards. 3\. Process Facility Capacity Reduction sard particles can accumulate in equipments le Sand production reduces the capacity and efficiency of surface processing facilities due to sand separator accumulation in pipework and separators since sand can accumulate in flowlines, pipework, and separators, reducing the effective volume available for fluid flow and separation processes. Sand production can lead to the formation of stabilized emulsions, which are difficult to separate. This can aggravate fines aggregation and settlement at the separator base, reducing separation efficiency and increasing the risk of equipment damage. Abrasive sand particles can damage surface equipment, leading to frequent shutdowns and costly repairs. 4\. Reservoir Management Challenges Sand production affects reservoir management, particularly with water re-injection and maintaining reservoir integrity. Severe erosion of injector chokes due to sand production can compromise produced water re-injection systems, reducing reservoir pressure maintenance and sweep efficiency. Sand production necessitates stringent filtration standards to avoid particle plugging of the reservoir, which can cause severe skin effects and impact overall reservoir performance. 5\. Potential Harmful Effects of Sand Deposition Sand deposition in flowlines and pipework can lead to several operational and integrity issues. Sand deposition reduces the cross-sectional area of howlines and pipework, increasing pressure drop and creating zones of under-deposit corrosion. This happens because sand deposits can form Sudden changes in operating conditions can cause corrosive cells that accelerate metal loss. leading to rapid erosion of internal surfaces. Sand deposits ocalized \"sand storms\" within pipelines, increase the risk of pigs (pipeline deaning devices) becoming stuck during towline or pipeline cleaning operations, necessitating costly interventions, ats wit a aligs that choke equipment, resulting in very high erosion rates of internal com data and itin sort period. Sand can heck, instrumentation tapings, leading to incorrect process dala and improper operational decisions. Sand particles cantalso any trace radioactive scales, which can accumulate and pose health and environmental risks. Production Engineering Il Types of Sand Production Sand production can manifest in various forms depending on reservoir conditions, well three types: transient sand operations, and production dynamics. The types of sand production can be broady categorized into. production, continuous sand production, and catastrophic sand production. Each pedesents unique challenges and requires differen managemen suralegies. Transient Sand Production - Short term Transient sand production refers to a temporary phase where production sand concentration declines over time under constant well 2000 conditions. observed in specific operational scenarios such as: phenomenon is frequently 3 800 Clean-up Operations: After perforating or acidizing a well, the initial production may bring significant amounts of sand, which gradually decreases as the well cleans up. Bean-up Procedures: During bean-up, which involves gradually increasing the well\'s production rate, transient sand production may occur. ili. Water Breakthrough: After water breakthrough in a well, € 0c transient sand production can be triggered by changes in fluid dynamics and formation stability. The sand concentration, cumulative sand volume, and decline period can vary significantly depending on the reservoir and well conditions. For instance, the sand volume can range between 1 to 200 liters, while the decline period can last from Fig 1 Transiend sand production 1 to 500 hours. Figure 46. Transient Sand Production 2\. Continuous Sand Production - long term Continuous sand production is characterized by a sustained level of sand production throughout the life of the well. This type of sand production is commonly observed in fields with unconsolidated or weak formations where sand control measures are either not implemented or are only partially effective. The acceptable level of sand concentration in production fluids is determined by several operational constraints such as: high sand concentrations can erode production equipment and pipelines, exceeding the sand handling capacity of separators can reduce separation efficiency, handling and disposal of sand produced with the hydrocarbons must be managed safely and economically, high sand content can damage artificial lift equipment like pumps, offshore wells might have more stringent limits due to logistical challenges. Typical Sand Cut Levels For a Prouders, me Yokoat sane a crite tom 106.006 210210 po), ma vices For gas producers, the typical sand concentration is around 16 kg per 1,000,000 m\' (1 Ib/MMscf) of surface gas, which translates to a downhole sand concentration of about 4 g/m° (1.5 pptb). ii. Much higher acceptable sand cut levels, up to 28,000 g/m° (10,000 pptb), have been reported under specific conditions where the system can tolerate such levels. \- sudden a severe 3\. Catastrophic Sand Production Calastrophic sand production refers to events where there is a sudden and man is intux of sand no the wellbore, leading to severe operational challenes. These events can result in the well choking or failing due to overwhelming amounts of sand entering the system. Types of Catastrophic Sand Production Production Engineering lI In some scenaros, slugs of sand create sand bridges of moderate volume within the tubing or choke during orater bean-up or shutin operations. These bridges ran estrict fow and cause the wel to choke, leadingto signficant operational dowtime and potental equipment damage. In more severe cases, a massive influx of sand fills and obstructs the wellbore, potentially resulting in a complete loss of production. The volume of sand associated with massive sand failure can vary significantly based on the well design and resevoir characteristics, ranging from several cubic meters to tens of cubic meters. It\'s important to note that catastrophic sand production may sometimes be considered an extreme form of continuous sand production. If the sand production rate becomes excessively high and persists over time, it can transition from a continuous production scenario to a calastrophic event. Mechanism of Sand Production Sanding, or sand production, is a common phenomenon in sandstone reservoirs during oil and gas production. It involves the disintegration and movement of sand grains from the reservoir formation into the wellbore and subsequently to the surface. Sanding generally occurs in two stages: Stage 1: Mechanical Failure of the Reservoir Rock Sanding begins with the mechanical failure of the reservoir rock in the near-wellbore area. This mechanical failure is primarily due to changes in and SANDING. in a sandstone peouction redistribution of stresses that occur as the well is lecuncal Stress allure of momitatoe drilled or produced. Factors such as changes in pore stress redistrution inesa redstrution Stess reosttion Stesss fluos pressure, drawdown pressure, and production rates can cause stress redistribution around the wellbore. When a well is drilled, the removal of rock and the subsequent fluid extraction alter the in-situ stress distribution. The reduction in support from reservoir pressure as fluids are produced can lead to the collapse of the formation in the near-wellbore area. However, mechanical failure does not automatically lead to sand production. The rock may fail structurally, forming fractures or disaggregating, but the sand grains may still remain in place until mobilized by fluid Viscous Viscous drag forces flow forces imo or met- dro id Sor Stage 2: Erosion of the Falled Material by Viscous Drag Forces Figure 47. Sanding Mechanism Once the rock has failed, sand production can occur when the flow of production fluids generates viscous gia loes of vet how his the poolie the aled nateral mo the elime it such Factors Influencing Sand Mobilization: \- i. The degree of natural intergranular cementation and compaction within the reservoir rock plays a significant role in determining its stability. Poorly cemented or loosely compacted formations are more susceptible to sanding. ii. iii. The friction between sand grains and their cohesion also affects the likelihood of sanding. If the cohesion is weak, sand grains are more easily dislodged and transported by fluid flow. Higher viscosity fluids (e.g., water with a high concentration of dissolved salts) and higher flow rates generate greater drag forces. Ií these forces exceed the formation\'s resistance, loose sand grains are carried along with the production iuids. When the destablizing forces from fluid flow overcome the strength of the rock, sand production occurs. This process leads to the detachment of sand grains from the rese Noir matrix and their movement into the wellbore and up the production flow path to the surface. Formation Sand Characteristics and Classification When managing sand production in oil and gas operations, it\'s important to distinguish between different types of produced solids, their nature, and their behavior. Produced solids are insoluble, inorganic, non-deformable particles associated with hydrocarbon production, unlike produced solids, often termed \"produced solids,\" organic particles like paraffin waxes or asphaltenes, which are semi-soluble and deformable. These materials. are generally classified into natural and artificial Types of Sand Based on Properties The formation of sand is described as a granular material, has a particle diameter between 0.0625 and 2 mm, and consists of mostly silicon dioxide (SiO2) and some other minerals. In general, there are four types of sand that classified based on the variation of their properties, and can be classified as: 1\. Quicksand is antunstable and easily movable sand that lacks cementation and compaction! usually associated with high water saturation. Quicksand has low load-bearing capacity and requires special control measures to prevent sanding. Partially consolidated sands are sands that have some degree of cementation but are not fully compacted. They have moderate porosity and permeability, which can lead to potential 3 sanding it production rates are not managed properly. easy to Friable or semi-competent sand are relatively weak and can easily crumble or break apart. They may have some cementation but are still prone to failure under stress conditions, especialty during high production rates. 4\. Consolidated sand are well-cemented and compacted sand with high strength and stability. These sands generally do not require sand control as they can maintain their integrity under production conditions. Sand Type Quicksand Partially Consolidated Sand Friable or Semi-Competent Sand Consolidated Sand Table 3. Sand Type and Characteristic Characteristic \- Completely unconsolidated sand \- No cementing materials. \- Small cohesive force and compaction. \- Very difficult for drilling and core sampling operations. \- Sand production occurs at the early stage of well production. \- Has some cementing agents but still weakly consolidated. \- Coring is done easily. \- Core sample obtained is very brittle and crumbles easily. \- Open hole conditions collapse easily. \- Well cemented. \- Core sample is easily obtained. \- Initially, sand production does not occur. \- Over time, sand production may occur as the well produces. \- Difficult to decide whether to apply sand control completion. \- Very well cemented sand. \- Usually does not require sand control methods. Sand Consolidation and Strength Factors Production Engineering lI The strength of sandstone formations is influenced by factors such as compaction, cementation, and the dissolution of sand grains at contact points. Consolidation is associated with the presence of cementing agents like quartz. calcite, and dolomite, which bind sand grains together, increasing the rock\'s load-bearing capacity. Unconsolidated sands are sands trapped in environments with insufficient cementing agents, this sand type has high porosity and permeability, making it prone to sand production. Sand control is necessary for such formations. 2\. Consolidated sands are formations are well cemented and do not require sand control due to their strong structural integrity. Characteristics of Produced Sand Particles Produced sand particles, which are a type of \"produced solids,\" have several physical properties that influence their management: the particle size distribution, shape and angularity, density, and concentration. The size of sand particles can vary widely, typically ranging from 50 to 150 micrometers (um). The distribution of particle sizes affects how sand is managed during production. Produced sands usually have high angularity, leading to poor shape factors. Angularity aids in grain-to-grain locking, which is beneficial for gravel pack filtering but can also stabilize oil emulsions, complicating oil-water separation. The relative density of most produced sands averages around 2.65. Clays, which may also be produced, have a similar density but are generally smaller in size and present in lower concentrations. Sand particle concentration can fluctuate daily, even within the same well. A sand-prone well can yield up to 5 parts per million by volume (ppmv) of sand, which translates to significant quantities depending on the production rate. Sand Prediction Sand prediction in reservoir evaluation is crucial for identifying the likelihood of sand production during oil and gas extraction. Sand production can lead to equipment damage, wellbore instability, and reduced productivity. Therefore, predicting sand production helps in selecting appropriate sand control methods to minimize its adverse effects. Some of the analytical techniques used for sand prediction include: 1\. Logging analysis, 2\. Core-based tests, 3\. Numerical simulators 4\. Drill stem tests (DST) Logging Analysis Logging analysis is a crucial method in evaluating reservoir formations for predicting sand production potential. It involves the use of various well log data to assess key rock properties, such as hardness, density, and porosity, which are critical indicators of sand production likelihood. One of the most important logs used in this analysis iS the sonic log, which records the transit time of a sound wave traveling through the formation. The transit time, measured in microseconds per foot (us/fi, Provides valuable information about the formation\'s characteristics. A shorter transit time (less than 50 us) typically indicates that the sand is hard, with low porosity and high density. Such formations are more consolidated and less likely to produce sand. Conversely, a longer transit time (greater than 95 us) suggests that the sand is soft, with high porosity and low density, indicating a weaker formation that may produce sand when subjected to stress. By analyzing sonic log data, engineers can quickly Screen formations to determine if sand control is needed, though this requires calibration with specific geological formations to ensure accuracy. Porosity logs, including neutron and density logs, are also vital tools in the evaluation process for Predicting sand production. The neutron log measures the hydrogen content within the formation, Which correlates with porosity levels; higher readings indicate higher porosity. The density log, on the other hand, measures the electron density of the rock, where lower readings are associated with 73 higher porosmationese porosiy ou provide insight inio the considation ste of the resenir formatione porosty is above ine for sand control requiriami to on arcaty. measure meniscessitating say is contre 30% the tormation is er neonso i land on ocean. Production, nated trad unlikely to prol In contrast ormalon vi no i o an germany vel-consolidatedional mikely to produce sand. The range between 20% no a 20 am guous ang may require additional ambiysis and data interpretation to determine the neoly fang coura. Calibration and combined log analysis play a significant role in accurately predicting sand production and determining the need for sand control. The approach involves com preing so cho readings with known geological formations to identify patters in sand production. This melnsd als for the creation of a \"formation properties log\" by combining dala trom sonic, neutrom, and densy logs. The combined analysis helps to categorize the formation into \"strong\" and\"eak\" intensay. Weak intervals are more likely to produce sand under certain conditions of pressure drawdown, while strong intervals are less likely to do so. Although this method has been used for more than two decades, there is a tendency for the formation properties log to over-predict the need for sand control. and to leverage field experience for more accurate predictions. As such, it is crucial to use this analysis in conjunction with other data sources, like core samples, Guidelines for sand control requirements are typically derived from porosity data, which can be obtained from either laboratory core analysis or well logs. In natural porous media, porosity indicates the degree of cementation within the formation. For instance, high porosity levels greater than 30% often signal poorly consolidated formations that may require sand control due to their potential to produce sand under production stresses. On the contrary, formations with lower porosity (below 20%) are generally well-cemented and less likely to produce sand, making sand control unnecessary. However, when porosity falls between 20% and 30%, the decision becomes less clear-cut, and scenario, must additional factors, such as rock mechanical properties and the specifics of the pressure drawdown be considered. This nuanced understanding underscores the importance of integrating various logs and calibrating them with geological formations to ensure accurate and reliable predictions for sand production and control requirements. Core-based analysis Core-based analysis is an essential method for assessing the mechanical properties of reservoir formations to predict sand production potential. This method involves testing core samples extracted from the reservoir to determine their strength and hardness characteristics. Two commonly used core-based tests are the Unconfined Compressive Strength (UCS) test and the Brinell Hardness Number (BHN) test. These tests provide highly reliable data for evaluating sand consolidation and help in making decisions about the need for sand control measures. The Unconfined Compressive Strength (UCS) test measures the resistance of a core sample to uniaxial deformation. The test involves applying force to the sample unti i fais, therby determining its compressive strength. The underlying concept is that the haida nid more consolidated a material is, the greater the force required to deform it. UCS is a critical indicator of rock strength and stability, with higher UCS values suggesting well-consolidated sands that are less likely to produce sand under production stresses. Conversely, lower SS values indicate weaker formations that may be prone to sand production. The asus anagemen sis are proda on is to. classify sand consolidation levels, aiding in the prediction and managemen tofsand production isks. Table 4. Sand consolidation based on UCS Test Young\'s UCS (psi) Porosity Description (%) Modulus (YM, psi) \< 35 \< 50,000 0 \< 30 \< 300,000 Zero strength dry sand Very weak damp sand \< 200 Weakly cemented Weak more Production Engineering lI cemented ≤ 500 Gray area \< 1000 \< 25 \< 22 ≤ 500,000 Consolidated rock ≤ 4000 \< 1,000,000 \< 5000 \< 20 \< 2,000,000 \< 18 \< 3,500,000 The Brinell Hardness Number (BHN) test is another core-based analysis that evaluates ent, hardness and consolidation of sand by measuring the material\'s resistance to indentation. In this te 15 a spherical indenter is pressed into the core sample with a controlled force for a duration of 10 to 15 seconds, creating an indentation. The size of the indentation provides a measure of the materialis hardness; a smaller indentation indicates a harder and more consolidated material. The BHN is calculated based on the applied force, the diameter of the indenter, and the diameter of the indentation. Like the UCS test, the BHN test results are used to classify sand consolidation levels. A higher BHN indicates a stronger formation less likely to produce sand, while a lower BHN suggests a weaker formation with a higher risk of sand production. Both Unconfined Compressive Strength (UCS) and Brinell Hardness Number (BHN) tests are integral to core-based analysis because they offer direct measurements of rock properties that are highly relevant for predicting sand production. The reliability of these tests makes them invaluable for developing effective sand management strategies in petroleum engineering. The classification of sand consolidation based on UCS and BHN test results helps engineers identify zones within the reservoir that may require sand control measures, thus optimizing production and reducing the risk of equipment damage and wellbore instability. Numerical Simulators Numerical simulators are advanced tools used to predict sand production in reservoir formations by applying various modeling strategies. These strategies include analytical and empirical relationships, physical model testing, and numerica models. Experimental studies are typically limited to predicting the onset of sand production and can be constrained by scale and boundary effects, which may affect the accuracy of the results. Physical models, although capable of predicting the volumetric sand production, are often time-consuming and expensive due to the small-scale setup of experiments, which can lead to boundary-related inaccuracies. Analytical models offer the advantages of fast processing and ease of use but are generally suitable only for predicting the onset of sand production. They also have significant limitations, such as being able to model only a single mechanism of sanding under highly simplified boundary and geometrical conditions that may not refect the complexities of real field-scale problems. Numerical models, however, are more powerful 100/s that can predict both the onset and volumetric sand production. They can be integrated with analytical correlations and validated or calibrated using experimental data to improve their accuracy and applicability. 75 Two primary mechanisms are involved in modeling sand production: mechanin an \# instabiity due ho sromechanical instability. Mechanical instability involves degradation -induce wellbore duadito stress conditions, while hydromechanicst instairy results from tow-induced pressure ments acting on the degraded material surunal in she cavity, such as perforationsie open bottomholes. Numerical modeling techniques or these chanisms are generally ceraties into two approaches: continuum and discontinuum. The continuum approach treats material ag continuous, assuming the cannot be divided into smaller fragments when deriving the go across differential equations. This assumption simplifies the modeling of material behavior across continuous domains. On the other hand, the discontinuum approach accounts for discontinutes where the magnitudes of deformation across the discontinuity are similar to the rest of the continaterial This approach is valuable for simulating localized failures, such as tracturing or separation of material blocks. The discrete element approach is a valuable tool for simulating sand production to understand the mechanisms of sanding at a granular level. However, it is not suitable for large-scale discrete because it requires significant computational resources and time. Additionally, calibrating discrete element models is complex due to several uncertainties, as replicating the exact arrangement of particles to match actual physical materials is nearly impossible. Over the past two decades, researchers have calibrated micro-properties in these models against actual sand behavior to improve accuracy. Nevertheless, continuum-based models are more commonly used for field-scale problems because they are better suited to large-scale simulations. To address the limitations of both approaches, hybrid models have been developed that combine the benefits of both continuum and discontinuum models. These hybrid models are designed to solve complex problems by integrating the advantages of both modeling techniques, providing more comprehensive solutions to the challenges of sand production prediction. They are particularly useful for handling complex geological formations where both continuum and discontinuum behaviors are present. For comprehensive sand management, a combination of these numerical methods-analytical models, continuum and discontinuum approaches, and hybrid models may be necessary to accurately predict and manage sand production in different reservoir conditions. Drill Stem Test Drill Stem Test (DST) is considered one of the most reliable approaches for predicting sand production in reservoir formations. This method involves gradually increasing the production rate and drawdown until the maximum production rate or drawdown is reached. The DST provides valuable information by allowing direct observation of sand particles being detected at the surface at maximum pressure drawdown, a process known as field observation of sanding. However, despite its effectiveness in observing sand production, DST does not provide sufficient data on reservoir depletion, water production, and other time-dependent parameters, which limits its comprehensiveness for reservoir evaluation purposes. A Drill Stem Test consists of testing individual wells to predict potential sand production. When a production well is completed using conventional methods, it can naturally flow reservoir fluids while gradually increasing production rates through a choke valve. As production rates increase, sand particles may be produced or a maximum acceptable rate may be reached. The DST enables the determination of an optimum production rate haro stras the production of fids free of sand, helping in the development of an appropriate sand control strategy. demonstrated the application of DST in real-world scenarios. It was found that many of China\'s A study by Pingshuang es a restond scenarios. it was found that many i chines offshore oilfields produce from unconsolidated sand reservoirs, leading to varying levels of sand production. In the Beibu Gulf of the South China Sea, reservoir rocks range from consolidated to unconsolidated. During DST operations for two specitic wells in this regien, sand particles were observed in the surface oil/gas separator, occupying up to half of the separator volume. This 76 observation confirmed the presence of sand production and highlighted the utility of DST in identifying and managing sand production risks in challenging reservoir environments. Sand Monitoring and Detection Maintaining well integrity, assessing the need for sand control, and ensuring the efficiency of well completions in petroleum production all hinge on effective sand monitoring and detection. Identifying sand production early enables timely interventions that can optimize production and safeguard well infrastructure. To detect sand, various methods are employed, including wellhead shakeout or grind-out tests, volumetric sand traps or sand fillers, erosion sand probes or safety plugs, fluid sampling, acoustic transducers, and erosion monitoring. These techniques are designed to detect sand in the production stream providing critical information to guide the implementation or adjustment of sand control measures. The sand filter method is a commonly used practice for sand detection. Sand filters, typically with mesh sizes of 20 and 40 um, are installed at the upstream part of the test separator. During routine monthly well tests, production flow from the well is diverted to the test separator through a manifold. Throughout the test period, the differential pressure across the sand filter is closely monitored. An increase in differential pressure can indicate sand accumulation in the filter. Periodically, the sand filter is removed and cleaned to visually inspect for the presence of sand or debris produced from the well. This method provides a straightforward approach to detect and quantity sand production, enabling operators to take corrective actions if necessary. The Sand Erosion Corrosion Monitoring (SECM) is another essential tool for sand detection and monitoring. SECM provides online readings that measure the corrosion or erosion rates, in the flow lines of each well. The data is extracted periodically from the system for trend analysis. An increase in the erosion rate can indicate the presence of sand production, which suggests that corrective measures are needed to prevent further damage. One common corrective practice is pressure drawdown control, where the choke size is reduced to limit sand production. By managing the pressure drawdown to stay within the sand production limit, operators can mitigate the risks of erosion and damage to well components while maintaining optimal production rates. Table 6. A Review of Different Sand Prevention Methods wallbore 1 De mcano may naaceum na sand Control Method Major Limitations Chemical Consolidation Some permeability reduction -cnsolidation Colect peres) -filguu Placement and reliability issues \- uneven placement Short intervals only \- degrade due to exposure to high temp Screens, Slotted Liners, Lack of zonal isolation \- allows Fluid to flow into the Special Filters High placement and workover costs Longevity of devices Plugging and screen collapse Screen erosion Potential damage during installation Permeability Index (PI) reduction Inside-Casing Gravel Difficult placement and workovers Packing High cost of installation Positive skin development Pl reduction Open-Hole Gravel Complexity of operation Packing Necessity for extensive underreaming in most cases High costs of installation 77 Propped Fracturing (Frac-and-Pack, Stress- Frac, etc.) Production Engineering I\| Permeability recovery Risks of tip screen-out during installation Selective Perforating Directional control and tortuosity issues (in inclined wells) Fracture containment control Proppant flow-back on production Oriented Perforating Problematic in relatively homogeneous formations Need for formation strength data Reduces inflow area Necessity for full stress mapping Theoretical analysis required Production Rate Control Perforation tool orientation needed Limited field validation available Erosion of facilities Sand monitoring required Separation and disposal required Potential for lost production Sand Control Table 7. Guideline for Sand Control Approach Selection Technique Highly Heterogeneous Intervals Heterogeneous Intervals Horizontal Well Zonal Isolation Standalone Screen Low LoW High Medium Open-Hole Gravel Packs High High Low Low Open-Hole Expandable Screen High High Medium High Cased Hole Gravel Packs High High High Low Medium Medium Low Frac Pack High Historical Approaches of Sand Production Control Conventional methods for managing sand production have focused on preventing sand from entering production equipment. These methods include chemical consolidation, wire-wrapped screens, gravel packing, frac-and-pack, and expandable screens. They are based on the principle of sand exclusion, ensuring that no sand enters the production equipment. To achieve this, conventional lechniques often involve minimizing the production fate to reduce the amount of sand that can enter the wellbore. The choice of sand control method is typically guided by sand prediction analyses, which assess the risk and potential extent of sand production. These analyses have led to the development and refinement of numerical approaches aimed at predicting the onset of sand production. Sand influx is often regarded as a significant factor limiting production rates. Limiting sand influx can affect the economic return on a project by reducing how rates to levels where no sand is 78 produced, prive cang equip mech damage, and minimizing the need for costly workovers. Sand productions. Thead to mechanical failures, formation rock diao a costl emoraver amaged well components. The fore, effective sand management is crucian pimeng producion ai avoiding costly repairs and replacements. Heavy oil wells contace in amoring on eucio route for validating the reliability and cost-effectiveness of various sand management practices. Sand management in these wells often involves a modified combination or strategies to define safe operating limits where sanding is considered operatively tolerable. This approach seeks to avoid or delay the expenses associated with overly conservative sand control measures while enhancing well productivity through continuous well clean-up. Instead of completely eliminating sand influx, this method accepts some level of controlled sanding, thus balancing cost and productivity. Commonly, sand control represents high-cost and low-risk solutions, whereas sand management aims to reduce costs while actively managing risks. Sand management approaches include continuously monitoring sand production, adjusting operating parameters like drawdown rates, and employing less intrusive sand control techniques. Tables 5 and 6 (referenced in the text) provide an overview of various techniques and guidelines to help select the appropriate sand control method based on specific well conditions and expected sand production scenarios. These tables outline possible applications and highlight the balance between the risks and costs associated with different sand control strategies. Guidelines for Controlling Sand Production Effective sand management is essential for maintaining well integrity, optimizing production, and ensuring the efficiency of well completions. The Control Framework provides a structured approach to verify that sand production control information is accurate and complete. This framework includes monitoring tools for produced solid particles, such as production limits, downhole equipment, conventional sand removal facilities, and surface separation equipment. 1\. Production Limits A conservative \"Zero Sand Production\" approach involves setting production limits based on pressure drawdown criteria. This method uses well testing and Permanent Downhole Gauges PDGs) to establish drawdown limits that minimize sand production. While this approach is cost-effective and requires minimal capital expenditure, it can reduce fluid production and may necessitate frequent adjustments to the solid particle production map. Monitoring instruments detect fuctuaions in sand production and help optimize pressure drawdown. An alternative strategy is to manage sand production by diluting it across multiple wells, reducing the impact on individual wells. 2\. Downhole Equipment To prevent sand from entering the wellbore, various downhole equipment options are employed: i.. Sand Screens and Slotted Liners are mechanical barriers prevent solids from entering the well. They are often used with gravel packing to enhance filtration. Gravel packing, which involves placing gravel around the screen, is effective due to its resistance to erosion. However, sand control equipment can wear out over time and may require additional measures such as Thru Tubing Sand Screens (TTSS) or ceramic sand screens for enhanced durability ill. Figure 48. Sand Screen Chemical Consolidation uses resins like furans, epoxies, or phenolic resins to bond sand grains together, creating a filter barrier. It involves multiple stages including acid cleaning, pre-flush, and resin injection. Although effective, it requires careful implementation and may not be suitable for all conditions. Expandable and Multi-Path Screens provide greater flexibility compared to conventional screens and can be combined with pre-coated gravel to enhance resin placement. Compnses three sandwiched layers Unexpanded No Change in Weave Expanded Figure 49. Expandable Screen V. Frac Packs combine hydraulic fracture stimulation with gravel packing, frac packs are effective but come with challenges such as proppant flow-back and fracture containment. control. 3\. Surface Facilities Conventional surface facilities are employed to manage sand production, but they may require periodic workovers. These facilities encompass several components designed to mitigate the impact of sand. Profile instrumentation is utilized in separators to continuously monitor and manage sand production levels. Erosion-resistant choke valves are engineered to endure the wear caused by sand, extending the equipment\'s lifespan. Sacrificial tees are strategically installed in flow lines to safeguard critical equipment from erosion. Additionally, sand jet or suction devices are employed to facilitate the removal of sand in various separators. Despite advancements in these technologies, maintenance remains necessary, especially during transient conditions characterized by high sand concentrations. To prevent erosion and damage, it is often effective to reduce flow rates during periods of elevated sand production. In terms of solids separation design, the most advantageous position for removing solid particles is upstream of the choke valve. This placement helps protect downstram equipment from damage. Techniques employed for solids separation include cyclonic separators, which leverage increased gas void 80 ration to effecte valve, raze solids from multiphase fuids, Welhead desanders, installed yerore the chopractical, dize fressure energy lo ananies Wellion firingy. removing solids uptream is ime targe, dunsteam desander o an he pestioned ortof separatirs, alhough this may necessitate larger equipment to accommo ce he inoses oats€ 4\. Surface Facilities: Solids Separation Design The optimal strategy for solids removal in surface facilities is to address solids before they ener the choke valve Separators ach protects downsteadismen sure as nomines, valves, heat. exchangers, and aningrators. Upstream removal allows solids to sexposed to high temperatures. which helps in cuis, aided m before separation. Cyclonic technoogy is etective for separating saids in multiphase fluids ided by increased gas void traction (erothay is ate viscosity and enhances settling velocity. Wellhead desanders, installed before the choke vade, use valve pressure to aid separation, mitigating erosion issues. I spatial constraints preven upsteam removal, multiphase desanders can be placed downstream of the choke valve, before the separator. This location still allows for particle removal but does not protect the choke valve and may require larger equipment due to lower pressure. Solids that reach the separator are less effectively managed. Fine particles can stabilize emulsions, while larger particles sette and require cleaning. Medium-sized particles can cause plugging in downstream water treatment systems. In produced water treatment, liquid desanders placed at the separator outlet use separator pressure to energize cyclonic separation, while other devices like nut shell filters (NSF), corrugated plate interceptors (CP\|), and cartridge filters (CF) are used at lower pressures. CPI devices remove coarse particles, and NSF and CF devices further reduce particle sizes for water injection. Choke er Wellstream desander with integral accumulator Wellhead desander with extemal accumulator Solids transport and disposal system Figure 50. Cyclonic location based solids separation equipment at surface facilities 5\. Wellhead Desander Design The development of the wellhead desander (WHD) aimed to enhance the effectiveness of cyclonic technology in handling multiphase flow regimes. Initially, desanding hydrocyclones were widely used to remove particles from produced water before injection, but their efficiency in two-phase (gas-liquid) flow was less understood. In 1995, British Petroleum\'s Farm production facility insights into their design and operation. Wellhead desanders are primarily used for well cleanup tasks such as frac flowback capture and coiled tubing wash. These units are designed to operate under high pressure conditions, handling up to 68,950 kPa and managing up to 15,000 barrels per day (BPD) of condensate and 105 million standard cubic feet per day (MMSCFD) of gas. Capable of separating 95 to 98% of solids down to 10 um, these devices have become standard in many surface facilities, both offshore and onshore, for handling heavy oil, gas-condensate, high-pressure high-lemperature (HPHT) environments, and gas-only applications. 81 The operational principle of multiphase desanders combines hydraulic and pneumatic perrita force times the terpe ose separation into onialensty direines These orces, ranging rom 400 toe, minimizithe fere of graviy, to bate de rapid separation of solid particles ram ing chamber (eide This tech or in oral for periodic discharge waited wei tes as comice to ow lightweight design. unterruptede sighs technology offers a high throug harge, ie ratio, res fings a compact and Multiphase desanders are employed both as service tools and as components of systems. As so Memove so they are installed upsteam processing o the choke to ease solids during workovers, such Well head well fuid 2 colled tubing was tout, acid washing, well testing, frac flowback, or under-balanced drilling. When Wellhead ป่ามหล integrated into surface facilities, they can be placed either after the choke valve. installations before the choke protect downstream equipment, those after the choke allow for lower pressure ratings, safeguard the separation system. The early installations addressed critical applications where downhole tools fell short in protecting topside equipment. With expanded use and improved predictive models, multiphase desanders have k management. discharge Figure 51. (left)Wellhead desander operation, and (right) wellhead desander with oversized accumulator 6\. Chemical Consolidation Treatments Chemical consolidation treatments are used to stabilize poorly consolidated formation reservoirs, which make up about 70% of the world\'s hydrocarbon fluids. These formations are typically young and lack natural cementation. Techniques include using resin-coated particles, saturating formations with bonding resins, and placing resin-treated sand to form screens. Methods involve creating a mixture of hydrocarbon carrier, resin, and particulated solids. Effective sand consolidation requires low injection pressure, minimal preparation time, high compressive strength, resistance to well fluids, and high permeability. Various resins like polyester, phenol-formaldehyde, and epoxy are used, with polymerization facilitated by catalysts. While chemical methods offer advantages over mechanical techniques, they are limited by high costs and challenges in uniform chemical injection. Examples of commercial processes include the Sanset process, which uses phenol-formaldehyde resin and can achieve significant compressive strength and maintain formation permeability. Research and case studies highlight the need for improved sand control methods. For instance, the Sanset process can handle formations up to 94°C and achieve a compressive strength of 200 atm. Studies have shown that gravel pack sand screens are effective in preventing erosion and ensuring higher production rates, while other methods like Standalone Sand Screens (SAS) and Expandable Sand Screens (ESS) perform less effectively in erosion resistance. 82 Table 8. Comparison among different sand control techniques Technique Resin Injection Advantages \- Leaves wellbore open. \- No necessity for screens and Disadvantages liners. \- Limited zone height. \- Longevity limited. Gravel Pack without \- Temperature sensitivity \< 250 °F. Screens \- Economical method. \- Difficult to apply evenly. \- Covers long intervals up to \- Reduces permeability by 10-60%. 500 ft. \- Low drawdown and high \- Expensive fishing job. productivity. \- Causes pressure drop. \- Excellent longevity. \- No casing or perforating expense. Screen with Open Hole Gravel Pack \- Erosion failure of slotted liner or screen. \- Plugging will eventually occur. \- Reduces production capacity. \- Difficult to exclude undesirable fluids \- Provides good sand control (water/gas) \- Difficult to perform in shale. over a long interval. \- Allows for high productivity. \- Avoids casing or perforating expenses. \- Erosion or sloughing when brine is pumped. \- Requires special fluids for drilling open hole section. CHAPTER VI Production Engineering lI PRODUCED WATER HANDLING Produced water, a significant waste stream in the oil and gas industry due to its complex tamical does a lom rehensive rever of the ev ration i re dare environy dia seam pre paring a biblio nericed creating analyze leading publications. The study, covering ate priatient, real oblomeo approach to eat e leading pubie ion a doinene our egor., 1960 10 2017, se, in at articles sieured database from 2434 documents no une iron tone goopus databases, ou fries, riles arelicaly examined. The analysis covered uped such as pubication tress, ron on produced areas, authors, keywords, journals, and at apers fudngs molicate that res importance of ongo ter and is treatment has been a critical field or siudy. underscoring the importance of ongoing research to address pollution and reduce of fration stusy, Produced water is the largest waste stream in the oil and gas industry, with about 3 to 4 barrels of water produ as 20 ach barrel of oil globally. This ratio varies widely, with some locations reporting ratios as high as 200 barrels of water per barrel of oil. Estimations suggest that between 30 1o 80 billion barrels of produced water are generated each year worldwide. Tracking produced water volumes is challenging ratios (WGR) across due to varying reporting practices and water-to-oil (WOR) or water-to-gas different regions. In the U.S., water-to-oil ratios differ significantly between states and between onshore and offshore operations. As oil fields mature and production declines, the volume of produced water typically increases, and this trend is expected to continue as new wells are developed. Produced Water Characteristics Produced water, a byproduct of oil Produced water and gas production, contains various substances that influence its handling and treatment. The composition and Organic concentration of these substances can vary significantly between different fields and production zones, typically measured in ubkc and separable Insolubic and separable milligrams per liter (mg/L) or parts per million (ppm). Key constituents of produced Anionic water include: 1\. Produced water contains dissolved solids, primarily sodium (Na+) and Carbarylk acide Phonols and orber compounds Carbonates and bicarbonstes Choride and sulfate Monovaleet and multivalenr chloride (CI) ions, along with other cations like calcium (Ca2+), Figure 52. Produced Water Characteristics magnesium (Mg2+), iron (Fe2+), and less common ions such as barium (Ba2+), potassium (K+), strontium (Sr+), aluminum (AI3+), and lithium (Li+). Anions like bicarbonate (HCO3-), carbonate (CO3-), and sulfate (SO4-) are also present. The total dissolved solids (TDS) concentration varies widely, influenced by factors such as geographical location, reservoir age, and type. Produced water from gas reservoirs usually has lower TDS, whereas water from oil reservoirs or aquifers tends to have higher TDS. 2\. Certain ions, like calcium, sulfate, and iron, can precipitate and form scales when changes in pressure, temperature, or composition occur. These scales (such as calcium carbonate, calcium sulfate, and iron sulfide) can deposit in tubing, flowlines, vessels, and water treatment equipment, causing operational issues. It is crucial to avoid mixing oxygenated water with produced water, as it can exacerbate scaling. 85 Produced water typically contains dissolved and suspended hydrocarbons, inching. Peo i saint one highly some it Penan olane, an a oxed seawater aromatic compounds like benzene, toluene,. and polycyclic aromatic hydrocarbons (PAHs), which are toxic and potentially carcinogenic. levels. High salinity can harm equipment, vegetation, and aquatic life. 5\. These solids include particulates surena santa, iony, and Other materials that can damage compment, form sludge with oil and grease, and complicate treatment processes 6\. Common metals found in produced water include iron, lead, zinc, manganese, and baquatic organisms. 7. These can form damaging oxides, wontribinide scaling, and pose toxicity risks to aquatic 8. Pormated water may contain radioacive elements, such as radium isotopes, frorn geoletical formations. NORM can cause radioactive scaling and pose environmental and health risks. Produced water may also contain biologies microorganisms, calcium carbonate, and injected treatmes like biocides and emulsifiers, which can affect the quality and complexity of its mixed \~/ u oil content Produced Water Treatment /: kaya iseparate phase separ The process starts with primary treatment, which removes suspended solids and free oil and grease (FOG). This is followed by secondary treatment to eliminate dispersed and some emulsified -oil setie oils. Finally, tertiary treatment targets the remaining small particles and dissolved hydrocarbons. above いか Additional advanced treatment may be needed ning sme assolved solutes like BTEX, salinity. over hi NORM, and toxic metals, especially for beneficial reuse or recycling in oilfield operations. Historically, \- mas mad treatment focused on primary methods and deep well injection, but increasingly, secondary and Crurface tertiary treatments are required to meet stricter discharge and reuse standards. Advanced water treatments, particularly desalination, are becoming more critical for water reuse and recycling applications. sel 0t oil p water. primary Table 9. Produced Water Treatment Technologies Table 9 outlines the key stages in produced water treatment, each targeting specific contaminants to progressively improve water quality. Primary treatment removes larger particles like sediment, debris, and free oil and grease (FOG) using methods such as AP\| separators, corrugated plate interceptors, and crosstlow separators. Secondary treatment focuses on removing dispersed - mos or emulsified oil and grease (O&G) and suspended solids (SS) through techniques like induced gas flotation, dissolved gas flotation, hydrocyclones, and centrifuges. 5\. PRODUCED WATER TREATMENT FUNDAMENTALS Primary Sediment and debris Free oil and grease (FOG) Secondary Dispersed/ emulsified O&G Tertiary Soluble hydrocarbons Suspended solids (SS) igure 5.1: Typical contaminant classes present in produced water. Primary Production Engineering lI Desalination Total dissolved solids (TDS) Metals and NORM dito sin ereparate insoluble solids Comaller particle size) API separators Corrugared plate interceptors Free water knockout CrossBow separators Dissolved oil Secondary Induced gas Rotation Dissolved gas Boatation Hydrocyclone Centrifuge Tertinry Mcdu filtration Nutshells, activated carbon, organoclays, zcolites, cic. Membrane filtration (MIF/UF) Desalination Biologic Treatment Reversc osmosis Thermal araporators lon exchange Electrodialysis Forward \- Activated sludge reactors Anaerobic digesters Membrane bioreactors Ozone + Membranc distillation Bio-GAC Aerated Lagoons Figure 53. Produced Water Treatment Fundamentals including media filtration with nutshells, Tertiary treatment addresses soluble hydrocarbons using advanced filtration methods, activated carbon, and membrane filtration (MF/UF). Desalination targets total dissolved solids (TDS), metals, and naturally occurring radioactive materials (NORM) through processes like reverse osmosis, thermal evaporation, electrodialysis, and membrane distillation. Finally, biological treatment employs activated sludge reactors, anaerobic digesters, membrane bioreactors, and aerated lagoons to break down organic contaminants. Primary Treatment Methods In petroleum operations, removing larger particles like sediment, debris, and free oil and grease (FOG) is essential, and several methods are employed to achieve this. API separators use gravity to separate oil and solids based on density differences, with 60-80% efficiency in free oil removal. They are effective in handling suspended solids and FOG, are well-established with standard designs, and have a small footprint. However, they cannot remove emulsified or soluble hydrocarbons and require regular cleaning. Coagulation and flocculation are often used as pretreatment steps. Corrugated Plate Interceptors (CP!) enhance separation by coalescing smaller oil droplets, achieving 80-95% efficiency. They are particularly effective in treating wastewater from refineries and chemical plants but require frequent maintenance and are less suitable for viscous droplets. Crossflow separators use horizontal plates to achieve 70-90% efficiency in oil-water separation. They are effective in space-constrained environments but are less efficient for emulsified oils and require careful design to avoid inefficiencies. Secondary Treatment Methods To further purify produced water and target smaller oil droplets, emulsified oil, and fine suspended particles, several secondary treatment methods are utilized. Induced Gas Flotation (IGF) injects gas bubbles into the water, lifting oil and particles for removal with 80-90% efficiency. It is effective offshore but sensitive to water chemistry changes and bubble size control. IGF handles oil and grease, volatile and non-volatile organic compounds, NOM, and hydrogen sulfide. Its advantages include proven performance and highwater recovery, but it requires energy for mechanical agitation and careful temperature management. Coagulant chemicals may be used for pretreatment. Dissolved Gas Flotation (DGF) creates small bubbles by dissolving gas into water under pressure, removing oil and solids with 85-95% efficiency. It is space-efficient and ideal for polishing 87 cod aminants as IG and offers high wale re over rate er, i requires energy for may aiso bre and sludge disposal, and works optimale recovery peratures. Coagulant chemicals may aling 7o-90e as pretreatment. Hydrocyclones ul a nur ug tera to separate oil rom water, achievin tine 90% efficiency. They are compact and stabilor ofore applications but less effective fo Fon, wrop lets and require regular maintenance. ale are effective in treating suspended solids an reduce solid the advantages of no moving parts and minimal maintenance. However, they do not re infe solids below 10 micrometers, have high pressure drops, and require energy to maintain ges separare. Pretreatment may include FWKO, AP\| separators, CPI, and coagulation. Centrandle sepulsie oil, water, and solids by high-speed rotation, orring 90-98% efficiency. They regule fine solids well but are complex and energy-intensive, requiring regular maintenance. Centrifuges are effective in treating suspended solids and FOG, with high separation efficiencies and a small footprint. The drawbacks include high capital costs, high maintenance dus 10 moving parts, and high energy demand. Chemical enhancement of the infuent may be used as pretreatment. Tertiary Treatment Methods Polishing produced water to remove finer contaminants involves several tertiary treatment methods. Media filtration uses granular materials such as sand or anthracite to capture particles ranging from 10 to 100 micrometers, effectively removing suspended solids and organic compounds. it is effective but requires frequent backwashing, which consumes energy and clean water, and demands media replacement or regeneration over time. Key contaminants treated include oil, grease, and suspended solids. Pretreatment may involve coagulation, pH adjustment, aeration, and solid separation. Nutshell filters are designed to remove particles down to 20 micrometers, excelling in oil and solid removal during the polishing stage. However, they are limited by fouling and require regular maintenance. Activated carbon is used to adsorb dissolved organics and trace hydrocarbons, handling particles down to a few micrometers. It is effective but has limited capacity and requires periodic replacement. Key contaminants include soluble hydrocarbons and organics such as BTEX and naphthenic acids. Pretreatment for activated carbon may involve gravity separators. Organoclays enhance hydrocarbon adsorption, managing particles and contaminants in the range of a few micrometers. They are effective but require periodic regeneration due to their finite capacity. Organoclays are noted for their small footprint and low energy requirements but are sensitive to temperature, pH, and salinity changes. Pretreatment involves gravity separation. Zeolites remove heavy metals and ammonium, handling particles down to about 1 micrometer. They offer high adsorption capacity but require pre-treatment to optimize their effectiveness. Zeolites are relatively inexpensive but more costly than activated carbon and also require regeneration. Pretreatment involves gravity separation. Desalination Process The process of converting seawater or brackish water into fresh water is essential in areas with limited natural freshwater resources. It is used in arid regions, on offshore platforms, and in Situations where freshwater is scarce but seawater is available. This method meets the growing demand for potable water and ensures a reliable supply. Reverse osmosis (RO) utilizes high pressure to force water through a semi-permeable membrane, filtering out salts and impurities with over 99% efficiency. It is commonly used to convert seawater or brackish water into fresh water. Despite its effectiveness, RO requires significant energy, has a high fouling propensity if pretreatment is inadequate, and generates a concentrate stream that needs disposal. Key contaminants treated include total dissolved solids (TDS). Advantages include a compact design and availability of various commercial products. Disadvantages are high energy 88 hens water proteate disposal issues, and low water recovery. Thermal eures, ha le us water to produce team which isues ond ne wo separate a and in purie and requilal substantial irasscale desalination and brine management but is energy intensive high-qually pubsuct waterastructure Key contaminanine manague us is evanages indude hi, complex system quiremen potential use of amite he Disadvantages are is energy derand lons trom\* resin, effectively ret, and maintenanast heat. on exchangese preces ions in water witable 10r ve regin salinity eye oring spectic contaminan and achieving lan purny. Ls not stead ore eno sper falias waters and requires rentant resi aedeneration, hie contaminants nergy aut and low operation archange is a management opion. Advanta s lyclude minimal entage too print. now aeratico maintenance. Disadvantages include Ade anted es scudge disposal, a largemoys, elevate recover and limitations due to dimate ae regula tactors. Electrodialysis co doyeren\' electric field to ions through selective membranes, separating them into different comtaminan, It is suitable for lower salient water bat less effective for high saitint any high T restreated include charged cations and antons, Tut Advantages are a small foremergy cogh. Pretemonal with good water recovery. Disadvantages include fouling, scaling, and high energy costs. Pretreatment involves deoiling and removal of fouling constituents. Forward os mosis uses an osmotic agent to draw water through a semi-permeable me and less concentrating contaminants. It is energy eficient and versatile but still under development and less proven at larger scales. Key contaminants treated include TDS. Advantages include high ret high-rates, minimal energy demands, and low chemical usage. Disadvantages are the lack of hire-periormance membranes, not yet established technology, a larger footprint compared to pressuRe driven membrane technologies, and the need for subsequent treatment technologies like RO. Membrane distillation uses a hydrophobic membrane to separate water vapor from contaminants through heat. It achieves high salt rejection and can utilize waste heat. Key contaminants treated include TDS, dissolved oil, and metals/NORM. Advantages include very high-quality product water and potential for high recovery rates. Disadvantages include energy requirements to maintain the temperature gradient, potential diffusion of volatile compounds into the distillate, fouling/scaling of membranes, and a larger footprint compared to other membrane technologies. Pretreatment involves cartridge filters and removal of surfactants. Biological Treatment Using microorganisms to break down organic pollutants in wastewater is a common approach in municipal and industrial settings. This treatment is crucial for reducing organic load before further processing or discharge, improving water quality, and meeting environmental standards. Activated sludge treats wastewater by aerating it with microbial cultures that degrade organic matter. It is effective for a wide range of contaminants and is commonly used, but managing the sludge and aeration processes can be challenging and costly. Anaerobic digesters break down organic waste without oxygen, producing biogas and digestate. This method is used for high-strength organic waste and energy recovery but can be slow and requires careful management of operating conditions. Membrane bioreactors combine activated sludge with membrane filtration to enhance treatment efficiency by separating solids and liquids. They offer high-quality effluent and reduced sludge production but are expensive and prone to membrane fouling. Ozone Bio GAC uses ozone to oxidize contaminants, followed by granular activated carbon for adsorption. It is effective for various pollutants and improves water quality but can be costly and requires careful management of ozone. Aerated lagoons treat wastewater in large, aerated ponds where microorganisms degrade organic matter. This method is cost-effective and simple but requires large land areas and can be less efficient in cold climates or with high-strength waste. Produced Water Management and Disposal Paradigms Produced water, once considered a mere waste product in the oil and gas industry, is now viewed through a more nuanced lens, with three primary management strategies: disposal, recycling, and reuse. Disposal typically involves injecting produced water into depleted well or specifically 89 throwin Class anjes, In onshore operations, the majority of produced wateon cont program of a nie Don wells, which ara legulated under the prodigound Injection eo to preven contamination 5gre Drinking Water At (latin une US These wes are designed tons,39% of productio water is dwater by isolan produci wateris. aquie sein ofthore operationas%o recovery. The ser is disposed of in the oran, feat water somal purer may be used for ons have intensited estringent environmental recuations an imal space on offhore planaives ake irtsporting watiny and compliance requilanens, primited consideration of altematives like transporting water to onshore facilities. ilabith ice of produced water management strategy depends on several key factors inconding the atlawat makeup water, discharge regulations the presence of disposal sir, heater ises aspects of waver treatment, and the recyclably otiones ton chemicals. As the cost of fresha tris ses andriven volumes become restricted, the emphasis shits towards reuse and recycling, This spart is dil endy economic and environmental considerations, making water management an intre all ant of oil add gas production rather than a secondary concern handled by external vendors. The oomic gas industry is undergoing a paradim shift, where the increasing scarcity of water, econuai pressures, rising oil costs, and enhanced environmental stewardship are transforming water management into a critical component of exploration and production (E&P) operations. Water is becoming a central focus in production strategies, reflecting its growing importance in the overall management and sustainability of hydrocarbon recovery. A PRODECEDWATER MINAGEMENT AND DISPOSA. OPTIONS Inketsn Figure 54. Produced Water Management and Disposal Options The figure illustrates various produced water management and disposal options, with a focus on onshore strategies. The pie chart shows that the vast majority of produced water (92%) is managed through injection, where water is reinjected into underground formations. This is the most prevalent method due to its relatively lower cost and perceived infinite capacity of disposal wells. In contrast, other methods such as NDES discharge, which accounts for 3%, involve treating and releasing water into surface waters under strict regulations. Beneficial reuse, also at 3%, involves using produced water for agricultural or industrial purposes. The least utilized method, at 2%, is evaporation, percolation, or treatment at publicly owned facities (POTWs). Re-use Recycle Disposal Freshwater is free Disposal wells have infinite capacity Disposal sites are clos to opcration Tramportation/disposal I less expensive than storage, treatment, and reube Freshwater allocation limited Disposal expensive Disposal aites are fac, and transportation costs are higher than seuse CapEx. OpEx Injection chemistry has value Stringent regulation pertaining to disposal water quality Limited millability of ficabwater Make up water expenics Mukiple use of water mandated Injection chemistry has value Figure 55. Onshore Water Management Strategies disposal, re eater management strategies can be broadly categorized inse treet types ly tree, diseuse, wed recycie, Dis at dies nated cost rective because freciate vis typical frie, disa dial wells are plentil an iose so eped conse and the costs as ciate valer, transportuable, is disposal are lower than ho close to ameration euse. Reuse of produced stere while vor specif often limited due to the high cost ef transportation and disposal, as west anger need ation specie injection chemistry that canoes expensive. Recycling is driven my spre uses regulations concerning water quality, limited freshwater availability, and mandates for multigelases of waten enthangh recycling can help offset wate expenses, it is often constrained by regulatory requirements and the complexity of treatment processes. iced Disposal blocking devica UKC well» args Figure 56. Produced Water Management Options Figure 56 outlines various methods employed by the oil and gas (O&G) sector to manage produced water. These methods include minimizing the volume of produced water, treating it to meet discharge standards, injecting it back into underground formations, treating it for reuse in industrial applications, treating it to meet standards for beneficial reuse such as irrigation, and using evaporation ponds to reduce its volume. The level of treatment required can vary significantly depending on the specific management goal and typically involves a multi-stage process. Different industries may adopt one or more of these stages based on the level of treatment needed. Produced water management practices vary by region and are influenced by local regulations, economic feasibility, watershed characteristics, and the quality of the produced water itself. Advanced treatment options offer new opportunities for discharge, recycling, and reuse. If industries can demonstrate that their treatment techniques are effective, they might be allowed to use Class V injection wells, which are used for storing water in drinking water aquifers. Given the large volumes of produced water, water reuse becomes a viable option for water resource managers, provided the economic and technical feasibility of treatment is satisfied. Successful treatment can also enable the beneficial reuse of produced water. Moreover, recycling treated produced water for agricultural and industrial applications is becoming increasingly common, especially in onshore operations. The three primary applications of recycled water in the O&G sector include use in irrigation, industrial processes, and aquifer storage. Produced water treatment begins at the extraction wellhead, where a complex fluid mixture containing dissolved gases, crude oil, solids, naturally occurring radioactive material (NORM), and water is recovered. As the fluid is de-pressurized, gases are released, and the remaining non-volatile components form what is known as produced water. Treatment involves a series of physical, chemical, or biological processes to recover crude oil and reduce contaminants, typically arranged in a \"treatment train\" that progressively improves water quality. 91