Prevention Of Formation Damage Research Articles

An innovative fracture plugging evaluation method for drill-in fluid loss control and formation damage prevention in deep fractured tight reservoirs

Lost circulation, resulting from the undesired loss of drilling fluid into formation fractures, stands as a significant technical obstacle in the exploration and production of oil, gas, and geothermal reservoirs. Effective mitigation of this challenge requires the development and application of robust experimental evaluation methods to assess the effectiveness of fracture plugging. The traditional approach to fracture plugging evaluation relies on a uniform evaluation index and experimental parameters for various lost circulation types. Unfortunately, this practice frequently results in inconsistent performance of loss control formulas during laboratory experiments and field tests. To address this issue, this paper introduces an innovative evaluation method that accounts for the specific characteristics of the three major lost circulation types. By adopting this approach, a more scientifically rigorous design and optimization of loss control formulas can be achieved, ensuring their effectiveness in managing lost circulation challenges. The development of the new method involves a systematic five-step establishment process: lost circulation type determination, evaluation index weight calculation, fitness degree analysis between laboratory experiment and field test, experimental parameters optimization, and quantitative scoring of loss control formula. Analytic hierarchy process is adopted to calculate the evaluation index weight. Quantitative scoring model is proposed to finally determine the integrated formula score for the quantitative evaluation and scientific optimization of loss control formula. To bridge the gap between laboratory and field applications, laboratory evaluation tests are developed to address different types of lost circulation scenarios. The experimental results demonstrate significant improvements achieved through the optimized formula. Specifically, the maximum plugging pressure increased from 5 MPa to 20.8 MPa, while the initial and cumulative loss volumes witnessed reductions of 30.3 ml and 121.2 ml, respectively. Moreover, the evaluation method proposed in this paper exhibits a fitting degree of over 90 % when compared to the actual control effect on drilling fluid loss. These findings substantiate the successful establishment of a connection between laboratory evaluations and field performance, providing valuable insights for future applications. Finally, a novel evaluation method for assessing the fracture plugging effect is established, accounting for various lost circulation types in deep fractured tight reservoirs. The reliability of this proposed evaluation method is validated by field test. Building upon this method, a high-score formula is designed and effectively deployed in a deep fractured tight reservoir in Tarim Basin, China. The successful application highlights the practical value and robustness of the developed evaluation method, offering promising prospects for future operations in similar reservoir settings.

Technology Focus: Formation Damage (March 2023)

Identification, prevention, and remediation of formation damage during the life cycle of oil and gas wells are key for our industry to allow wells to perform to their full potential. Increased awareness of potential damage mechanisms along with improvements in laboratory testing equipment and methodologies have proven to be instrumental in efficient prevention and remediation of formation damage in production and injection wells in conventional reservoirs. While the ongoing technical studies and technology developments in the area of formation damage are heavily focused on key damage-mechanism scenarios during drilling and production, such as drilling-fluid-induced damage, scaling, clay swelling, fines migration, and incompatibility of fluid/fluid and fluid/rock in conventional sandstone and carbonate reservoirs, there are new research activities and increased applications of learnings in low-permeability unconventional reservoirs and carbon capture and storage (CCS). In low-permeability unconventional reservoirs, hydraulic fracturing has proven instrumental for economic and successful development. Injection of a large volume of fracturing fluid water is necessary to place the required quantity of proppant to generate and maintain fracture conductivity, thereby increasing the risk of fracturing-fluid-induced formation damage. New laboratory studies and field trials to select suitable preventive additives in fracturing fluid and optimize flowback processes are being deployed to prevent formation damage not only from gelling materials, friction-reducer chemicals, and water blockage but also from scaling and paraffin during production. Identification and prevention of formation-damage mechanisms affecting injectivity during CO2 injection in subsurface for CCS and CO2 enhanced oil recovery are critical. Enjoy the papers chosen this year, some of which highlight my comments and the innovation and successes achieved by our industry in identification, prevention, and remediation of formation damage in conventional reservoirs, which is expected to bring success in area of unconventional-reservoir development and carbon reduction. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 22543 Formation Damage in the Hollín Sandstone: Diagnosis, Evaluation, and Stimulation Practices From Laboratory to Field Implementation, Sacha Field, Ecuador by Alvaro Izurieta, Halliburton, et al. SPE 208852 Understanding Fluid Exchange as Screens Are Run in Hole—Mitigation of Formation and Completion Damage Risks by Michael Byrne, Axis, et al. SPE 210763 Near-Wellbore Damage Associated With Formation Dry-Out and Fines Migration During CO2 Injection by Liam Alchin, The University of Adelaide, et al.

Experimental study on the controlling factors of frictional coefficient for lost circulation control and formation damage prevention in deep fractured tight reservoir

Working fluids loss is a major contributor to low productivity during production process of fractured tight reservoirs. Lost circulation control effect directly related to the tribological behavior between fracture surface and lost circulation materials (LCMs). In this study, the friction coefficient (FC) was investigated using typical clastic rocks and LCMs by considering multiple effect factors divided into external condition and internal condition. The results show that normal load had a relatively high effect on sliding model. A positive correlation was observed between FC and asperities heights. FC decreased induced by particle size degradation of rigid LCMs. Elastic LCMs manifested higher FC compared with rigid LCMs. Under the lubrication condition by working fluid, FC of rigid LCMs was mainly controlled by their surface wettability. FC of organic LCMs is more sensitive to high temperature aging than inorganic LCMs. Fracture plugging experiments show that LCMs optimized based on the research results can effectively improve the efficiency and strength of fracture plugging. • Friction coefficient tests between the fracture surface and LCMs. • The influence of multiple effect factors on the friction behavior between the fracture surface and LCMs. • The optimization of loss control formula based on laboratory experiments.

The particular foamed cement formulation by acid for oil/gas wells cementing jobs: an experimental approach

Foamed cements are coarse dispersions of a base cement slurry, a gas (usually air or nitrogen), a foaming surfactant and other materials A new foamed cement, designed for oil/gas well liners and casing cementing jobs, was formulated. Ultra-lightweight cement pastes (such as foamed cements) are appropriate for formation damage prevention in fractured and depleted reservoirs. In this work, foamed cements were prepared at high shear rates using a foaming agent primarily composed of sodium lauryl ether sulfate, boric acid and a retarder (JR120). This formulation was called FBJ. The samples were subjected to tests for density, rheology, free water, settling, thickening time, compressive strength (CS), fluid loss, porosity and permeability, along with microscopic photography and computed tomography scanning. Compared with other drilling cements, the FBJ was found to have one of the lowest densities (1200 kg/m3), a CS of 8963 kPa and a thickening time of about 3 h. The rheology of the FBJ improved under high-pressure and high-temperature conditions. Examinations of the set FBJ also showed that the pores were not interconnected, the porosity of the FBJ was greater than 73% and 28% of the FBJ was matrix. Moreover, cement permeameter tests indicated that the permeability of the FBJ was just 0.0109 mD (1 mD ≈ 1 × 10−12 cm2). All of these results show that the formulated FBJ has acceptable properties for oil/gas wells cementing applications.

Diagenesis and reservoir quality of Oligocene Barail Group of Upper Assam Shelf, Assam and Assam Arakan basin, India

The Oligocene Barail deltaic sandstones are the main oil reservoirs in Upper Assam Basin. Nonetheless, the diagenetic alterations and their impact on reservoir quality on Barail sandstones are virtually unknown. The present study aims to know the ways diagenesis plays the role for the invariable hydrocarbon production from these clastic reservoirs within the Barail Group. Samples representing the lower unit of Barail Group known as Barail Main Sand (BMS) and the upper unit known as Barail Coal Shale (BCS) were studied using a combination of petrographic, scanning electron microscopy (SEM), X-ray diffraction (XRD) of clay and wireline log techniques. The average framework composition of BMS is Q49.42F4.18R14.75 while the BCS are composed of Q51.33 F3.89 R14.04. The BMS are moderately hard, fine to medium grained, sub angular to sub rounded, moderately well sorted, dominantly of lithic arenite type and porosity value ranges from 10 to 22.01%. The sandstones of BCS Unit are moderately hard, light grey, fine to very fine grained and usually have low porosity except the channel sands. Both the BMS and BCS have undergone various diagenetic alterations which are observed as mechanical compaction, authigenesis of cements and clays, dissolution and alteration of unstable clastic grains. The identified clay minerals are kaolinite, illite and chlorite. Smectite is occasionally observed as mixed layered smectite-illite clay. The diagenetic alterations along with the clay minerals occupying as pore-filling and lining cements have critically influenced the reservoir quality of both BMS and BCS units of Barail Group. Proper treatment of these clay minerals could aid in the prevention of formation damage to a large extent.

TEST OF FORMATION WATER AND CHEMICAL COMPATIBILITY FOR REMOVAL OF MUDCAKE IN WELLBORE

Laboratory and field studies indicate that almost every operation in the field, such as drilling, completion, workover, production and stimulation are potential source of damage to well productivity. Formation damage has long been recognized as a source of serious productivity reduction in many oil and gas reservoirs. The mud cake is a damage that occurs in formation caused by drilling process. Prevention of formation damage has the following advantages : a) To reduce ultimate completion costs; b) To preserve barriers; c) To improve sweep efficiency. Potassium chloride (KCI) and breaker are chemical materials used in mud clean up system to remove the mud cake formed in drilling process. In relation to this, it is very important to know whether the formation water and KCI solution, then the formation water and breaker, are compatible or not. This paper is written based on our experience in formation damage laboratory tests. Therefore, the main topic of this paper is "Test of Formation Water and Chemical Compatibility for Removal of Mudcake in Wellbore ". Hopefully, the laboratory test results presented in this paper are valuable, not only for LEMIGAS as Research and Development Centre For Oil and Gas Technology, but also for oil companies as the user which will apply the chemical material in oil fields (cost efficiency), chemical material supplier (particularly in design of breaker).

Dynamic fracture width prediction for lost circulation control and formation damage prevention in ultra-deep fractured tight reservoir

Dynamic fracture width prediction is of great importance to the control of lost circulation, which often leads to safety, environmental and economic issues and results in severe formation damage during the development of ultra-deep fractured tight reservoir. However, the connected fault boundary and nonlinear deformation behavior are rarely considered for the fracture width prediction. In the current paper, the fracture deformation equation is determined by fitting the stress sensitivity experiments data. The prediction model for dynamic fracture width is developed based on the non-Newtonian fluid loss dynamics theory, accounting for the power-law fluid, fracture index deformation equation and fault boundary. Parametrical analysis is conducted to investigate the effects of pressure difference, consistency coefficient, flow pattern index and fault boundary distance on the dynamic fracture width. Control strategy is proposed for drilling fluid loss in fractures with connected fault in ultra-deep fractured reservoir. The developed dynamic fracture width prediction model is validated by field data and successfully applied to the SHB ultra-deep fractured tight reservoir in Tarim Basin, China.

Principles for Controlling the Shape Recovery and Degradation Behavior of Biodegradable Shape-Memory Polymers in Biomedical Applications.

Polymers with the shape memory effect possess tremendous potential for application in diverse fields, including aerospace, textiles, robotics, and biomedicine, because of their mechanical properties (softness and flexibility) and chemical tunability. Biodegradable shape memory polymers (BSMPs) have unique benefits of long-term biocompatibility and formation of zero-waste byproducts as the final degradable products are resorbed or absorbed via metabolism or enzyme digestion processes. In addition to their application toward the prevention of biofilm formation or internal tissue damage caused by permanent implant materials and the subsequent need for secondary surgery, which causes secondary infections and complications, BSMPs have been highlighted for minimally invasive medical applications. The properties of BSMPs, including high tunability, thermomechanical properties, shape memory performance, and degradation rate, can be achieved by controlling the combination and content of the comonomer and crystallinity. In addition, the biodegradable chemistry and kinetics of BSMPs, which can be controlled by combining several biodegradable polymers with different hydrolysis chemistry products, such as anhydrides, esters, and carbonates, strongly affect the hydrolytic activity and erosion property. A wide range of applications including self-expending stents, wound closure, drug release systems, and tissue repair, suggests that the BSMPs can be applied as actuators on the basis of their shape recovery and degradation ability.

A novel material evaluation method for lost circulation control and formation damage prevention in deep fractured tight reservoir

Lost circulation induced by working fluid loss into formation fractures often leads to safety, environmental and economic issues, which has hindered the exploitation of oil, gas and geothermal resources for years. Fracture plugging with loss control materials is the most commonly used method for lost circulation control. However, traditional material selection is mainly guided by trial-and-error method. This paper proposes a novel material evaluation method for the systematic and scientific selection of loss control material. The new method consists of four steps: key material parameters determination, parameter weight calculation, parameter experimental evaluation, and material quantitative scoring. Fracture plugging strength model is analyzed to determine the key material parameters accounting for fracture plugging strength and the requirement of plugging removal before production. Analytic hierarchy process is adopted to calculate the material parameter weight. Experiments are designed to evaluate the material parameter levels. Quantitative scoring model is proposed to finally determine the material integrated score for the quantitative evaluation and scientific selection of loss control material. The reliability of the proposed evaluation method is validated by fracture plugging experiments. High-score materials are selected to form loss control formula based on the proposed evaluation method and successfully applied to gas field in Tarim Basin, China.

Disaggregation and discretization methods for formation damage estimation in oil and gas fields: an overview

Formation damage could potentially impede production and injection operations. Hence, characterization and discretization processes of formation damage should be connected to quantification and disaggregation techniques, relying on characterization fundamentals that consider chemical and physical changes in the fluid and rock system through the field productive life. This document presents a review of different disaggregation, quantification and discretization methods for the formation damage estimation in oil and gas fields. This review is mainly divided into three main sections, namely: i) Formation damage diagnosis, ii) Formation damage quantification, and iii) Formationdamage disaggregation. This document will aid in the alignment of the academic and industrial sectors to incentivize the prevention and inhibition of formation damage, as well as the optimal design of remediation mechanisms.

Development of a Highly Elastic Composite Gel through Novel Intercalated Crosslinking Method for Wellbore Temporary Plugging in High-Temperature Reservoirs

Summary Effective mitigation of fluid loss and prevention of formation damage are substantial concerns during well completion and workover in low-pressure, high-permeability, and/or fractured reservoirs, especially with high temperature (HT). In this paper, a highly elastic composite gel is developed on the basis of the solution blending for “intercalated crosslinking.” The mechanism is the intercalation of polymer and crosslinker into layered silicate material (LSM) using a specific procedure. The gel is composed of HT resistant copolymer, crosslinker polyethyleneimine (PEI), LSM, and antioxidant in freshwater. The effects of main variables on the gelation performance are investigated. The mature composite gel strength is noticeably improved with increasing temperature. The elastic modulus (G′) of the mature composite gel prepared at 160°C can reach up to 15 000 Pa, while only a value of 6000 Pa is obtained for the gel at 130°C. The composite gel remains robust after aging 10 days at 160°C. The pressure-bearing capacity and rigidity of the mature composite gel are noticeably improved with increasing layered silicate concentration. This unique feature can benefit stress buffering when the sealing operation is conducted under high differential pressure such as the case with a long hydrostatic column. Scanning electron microscope (SEM) is used to further reveal the intercalated crosslinking mechanism of the composite gel. A temporary plugging experiment for a fractured limestone core also supports the gel's high-pressure (HP) resistance and low adsorption and retention to alleviate formation damage. The composite gel is promising for fluid loss mitigation that could be extended to other related near-wellbore operations in HT wells.

α-Ionone Protects Against UVB-Induced Photoaging in Human Dermal Fibroblasts.

Ultraviolet (UV) light-induced wrinkle formation is a major dermatological problem and is associated with alteration in collagen. Here, we investigated the potential of α-ionone, a naturally occurring aromatic compound, in regulation of UVB-induced photoaging in human Hs68 dermal fibroblasts and identified the mechanisms involved. We found that in human dermal fibroblasts, α-ionone inhibited UVB-induced loss of collagen. α-Ionone upregulated the molecules participating in the TGF-β–SMAD pathway (TGF-β1, phospho-SMAD2/3, Col1A1, and Col1A2), but downregulated the molecules involved in the MAPK–AP-1 signaling pathway (phospho-p38, phospho-JNK, phospho-ERK, phospho-c-Fos, phospho-c-Jun, MMP1, MMP3, and MMP9), in human dermal fibroblasts. α-Ionone treatment also increased hyaluronic acid contents, and this effect was accompanied by an upregulation of mRNA expression of genes (HAS1 and HAS2) involved in hyaluronic acid synthesis. Thus, α-ionone is effective in the prevention of UVB-induced decrease of collagen and hyaluronic acid in human dermal fibroblasts. We propose that α-ionone may prove beneficial for the prevention of UV-induced wrinkle formation and skin damage.

Formation damage prevention using microemulsion in tight sandstone gas reservoir

Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet. This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.

Stochastic modelling of particulate suspension transport for formation damage prediction in fractured tight reservoir

Developed fractures are beneficial for the efficient development of tight reservoir. But they also lead to formation damage induced by particle capture in fractures during drill-in fluid loss. Effective modelling of particle transport and capture behavior is critical to the prediction and prevention of formation damage. However, the behaviors of particulate suspension transport in fractured media are still incompletely understood and quantified. This paper develops stochastic microscale model for size-exclusion particulate-suspension transport in fractured media. The proposed model accounts for the fracture network connectivity and its subsequent evolution due to particle capture by the introduction of percolation theory. It accounts for the particle capture probability and accessible flux in the expression for particle capture and fracture plugging dynamics. The micro-stochastic model allows for upscaling and numerical solution is obtained for the macroscale equation system to predict the rate and range of formation damage induced by drill-in fluid loss. Laboratory experiments are conducted for the model validation. Modelling results exhibit preferential plugging of fractures with size equal to or below the suspended particle size. The fractures with width equal to the particle diameter decrease fastest. The captured particle concentration decreases with the improvement of the network connectivity. Higher network connectivity leads to smaller decrease of fracture concentration and network permeability during the transport and capture of the same size of suspended particles. The proposed model shows a good agreement with laboratory data.

High-Performance Brine Viscosifiers for High Temperatures

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183964, “High-Performance Brine Viscosifiers for High Temperatures,” by Peter J. Boul, Suhaib Abdulquddos, and Carl J. Thaemlitz, Saudi Aramco, prepared for the 2017 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 6–9 March. The paper has not been peer reviewed. Many viscosifiers currently used in high-density solids-free reservoir drilling fluids (RDFs) and completion fluids (CFs) are incompatible with high-density brines or require the use of prohibitively expensive brines to achieve target densities. There is substantial commercial benefit to developing a brine viscosifier with a higher temperature tolerance than is currently offered. A supramolecular viscosifier package has been developed that uses noncovalent associations between additives to enhance the thermal resilience of divalent brine fluids. Static aging-test data indicate that the supramolecular viscosifier outperforms high-performance, commercially available starch/xanthan brine viscosifier. Background The exploitation of oil and gas reservoirs found at increasing depths and the development of horizontal and slimhole drilling have increased the demand for high-density solids-free RDFs, CFs, and workover fluids (WFs). The use of divalent brine-based drilling fluids and CFs in well sections with temperatures exceeding 260°F is limited because of degradation of the polymers used to viscosify the fluid and suspend drill cuttings. Effective drilling fluids have numerous functions in well construction. They must have the physical properties required to carry cuttings from beneath the drill bit up the annulus of the well for separation at the surface. They must also provide cooling for the bit and be able to reduce-friction between the drillstring and the formation being drilled. This must be accomplished without damaging the formation. The inflow of fluids or solids from the drilling mud can cause formation damage, which can reduce the rate of penetration during drilling and can also decrease the rate of hydrocarbon production from a producing well. RDFs, CFs, and WFs must be density-adjusted to provide the hydrostatic head to preserve the integrity of the wellbore walls and to prevent blowouts. Although drilling through much of the well can be accomplished with oil- or water-based fluids weighted by solid particles of such minerals as barite, the reservoir sections offer a different challenge because of the concern that these solids could plug pores in the formation and reduce hydrocarbon-flow rates. It is for this reason that operators look to brines to provide density in RDFs. Recently, research in nanomaterials has revealed the potential of low-solids nanofluids for the prevention of formation damage.

Analytical model of plugging zone strength for drill-in fluid loss control and formation damage prevention in fractured tight reservoir

Developed fractures are beneficial for the efficient development of tight reservoir. They also lead to drill-in fluid loss and induce severe formation damage. Fracture plugging with loss control material (LCM) is the most common way to control drill-in fluid loss in fractured formation. Fracture plugging effect largely depends on the strength of fracture plugging zone, because in most cases plugging failure is caused by the strength failure of plugging zone. However, the effects of LCM mechanical and geometric parameters on plugging zone strength are still unclear. Moreover, traditional LCM selection is mainly performed by trial-and-error method, due to the lack of mathematical models. This paper develops an analytical model for plugging zone strength accounting for the frictional failure and shear failure of fracture plugging zone. Effects of LCM mechanical and geometric properties on plugging zone strength are analyzed. The proposed model is validated by laboratory data. Application procedure of the proposed model to drill-in fluid loss control is developed and successfully applied to the field case study in Sichuan basin, China. The modelling results show that particle-particle friction angle, particle-fiber friction angle, fiber tensile strength, D90 degradation rate, and friction angle between plugging zone and fracture surface are main mechanical parameters affecting the plugging zone strength. Particle size distribution, aspect ratio and initial angle of fiber, and plugging zone porosity are main geometric parameters during loss control. Single LCM parameters are applied to the selection of LCM type. Plugging zone parameters are used for the determination of optimal LCM concentration. Reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect to optimize the plugging zone strength and loss control effect.

Fracture plugging optimization for drill-in fluid loss control and formation damage prevention in fractured tight reservoir

Well-developed natural fractures are beneficial for the economic and efficient development of tight reservoirs. However, they also lead to drill-in fluid loss and induced severe formation damage. Fracture plugging with loss control material (LCM) is the most common way to control lost circulation. Fracture plugging effect largely depends on the fracture propagation pressure, because plugging failure is mainly caused by fracture propagation in fractured formation. Nevertheless, the effects of the plugging parameters on the fracture propagation pressure are still unclear. The current paper develops a mathematical model for fracture propagation pressure accounting for fracture plugging. Key indexes are proposed for fracture plugging optimization based on parameter analysis. Laboratory experiments are conducted to select reasonable LCM type and concentration. The application procedure of the proposed model to drill-in fluid loss control is presented and successfully applied to field case study. The modelling results show that the plugging zone length, width and permeability are the major plugging parameters that affect the fracture propagation pressure. The larger the plugging zone width and the smaller the plugging zone length and permeability, the higher the fracture propagation pressure. Maximum plugging pressure, total loss volume before sealing and D90 degradation rate are proposed as the three indexes for LCM selection. Experimental results show that the combination of rigid granule, fiber and elastic particle can create a synergistic effect to optimize the fracture plugging effect. For the 500 μm width fracture, the optimal concentrations for rigid granule, fiber and elastic particle are 5.0%, 1.5% and 2.5%, respectively.

Time-Resolved Fluorescence for Real-Time Monitoring of Scale and Corrosion Inhibitors

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 179867, “Time-Resolved Fluorescence for Real-Time Monitoring of Scale and Corrosion Inhibitors: A Game-Changing Technique,” by A. Marais, M. Martini, F. Lepoivre, M. Ould-Metidji, A. Collet, and O. Tillement, Université de Lyon, and C. Hurtevent and S. Baraka-Lokmane, SPE, Total, prepared for the 2016 SPE International Oilfield Scale Conference and Exhibition, Aberdeen, 11–12 May. The paper has not been peer reviewed. Inhibitors have been widely used to reduce steel corrosion and scale deposition in critical offshore sites. However, the large use of such additives has not been followed by the development of any efficient technique of dosage that considers the strict requirements of an offshore platform. This paper describes a novel method of chemical dosage based on time-resolved fluorescence (TRF) that allows a simple, accurate, and efficient quantification of chemicals below parts-per-million ranges, even for double (scale/scale, scale/ corrosion) quantification. Why TRF Should Be Considered a Game-Changing Technique The prevention of scale formation and corrosion damage in petroleum pipelines and facilities remains an important challenge (Fig. 1). Several interconnected factors, such as the composition of seawater used for secondary- and enhanced-recovery waterflooding operations, the composition of the formation water, and the gradients of temperature and pressure within pipelines, are the origin of pipeline damage and decrease in extraction efficiency. The current techniques used for chemicals management often display some limitations (e.g., setup and running costs, size, and real-time monitoring). Some of them also require laborious pretreatment/ purification stages for the separation of inhibitor chemicals from the interfering brine salts. Here, the TRF method may represent a break from past technologies not only because it displays sub-parts-per-million accuracy and multidetection (scale or corrosion chemicals), but also because it can be set up at offshore sites.

Novel Dispersant for Formation Damage Prevention in CO2: A Molecular Dynamics Study

The injection of supercritical carbon dioxide (sc-CO2) into depleted or overproduced oil reservoirs has become a popular practice for enhancing oil recovery over the last several decades, because of the favorable mobility characteristics of miscible CO2 floods. Unfortunately, dissolved CO2 often causes mass precipitation of heavy-end hydrocarbon fractions such as asphaltenes, leading to formation damage. The prevention of formation damage ensuing from asphaltene deposition in porous rocks often requires the use of chemical additives such as solvents or inhibitors. Effective additives are able to disperse asphaltene aggregates by curbing their growth in the bulk phase. In particular, CO2-soluble polymers represent a promising type of asphaltene dispersants, since they can eliminate the need for large amounts of hydrocarbon solvent additives to injection mixtures. However, most of these polymers have been relatively untested and their interactions with asphaltenes in sc-CO2 are still unclear. In this study,...

Development of a Population Balance Model to Describe the Influence of Shear and Nanoparticles on the Aggregation and Fragmentation of Asphaltene Aggregates

The precipitation and deposition of asphaltenes is a primary problem related to the processing, transportation, and production of oil. Flocculation of asphaltene aggregates is likely to occur during the production and processing of crude oil. Recently, it has been shown that nanotechnology in the form of nanoparticles is useful for the inhibition or prevention of asphaltene formation damage. Although it is well-known that the adsorption of asphaltenes on the nanoparticle surface would reduce the capacity of these asphaltic compounds to interact with each other, limited studies have been performed regarding the processes and the mechanisms associated with the effect of nanoparticles on the inhibition of the formation damage due to asphaltenes. To better understand this phenomenon from a mathematical approach, a population balance model (PBM) is proposed to describe the kinetics of asphaltene flocculation-fragmentation in the presence of nanoparticles. The model assumes that asphaltenes in the presence of a...