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Collaborating Authors
Production Chemistry, Metallurgy and Biology
Abstract Scale formation during waterfloods can damage reservoirs far beyond the wellbore region. A comprehensive analysis with geochemical modeling can improve waterflood design in the selection and/ or mixing of source waters and thus, mitigate formation damage arising from injecting incompatible fluids. This method can also predict the types of scales and their severity at various production stages. This will help optimize treatment schedules and thus reduce operation costs. In the case study of Zone 4, Prudhoe Bay Unit (North Slope, Alaska), the geochemical model was validated with the laboratory analyses of Zone 4 produced water samples. Then it was used to evaluate the impact of mixing formation brine and seawater on rock-fluid interactions and scale formation. The prediction is consistent with the observation of calcite formation in early production at Prudhoe Bay. The model also indicates the precipitation of iron carbonate and iron sulfide scales as the waterflood matures.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Well Drilling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract The generation of stable emulsions at reservoir temperature was investigated as a possible mechanism of formation damage in the near well-bore area, Typically, emulsions have been considered a top-side process problem. Furthermore, experimentation is often based on a set of single events and a traditional conclusion would be that emulsions are of little concern in plugging mechanisms. However, in nature single event mechanisms are scarce. Under actual reservoir conditions both generation of scale and mobilization offines together with formation of emulsions might be simultaneous events. Thus, a combination of such mechanisms may lead to the plugging. In the present investigation a set of 11 different well parameters were tested in a factorial screening design for potentials in emulsion formation. The results from this screening design show that combinatorial effects are key events in fines stabilized emulsions. Two different North Sea degassed crudes gave emulsions under various combination of variable settings at reservoir temperature. The present paper gives a survey on the influence of these variables on the stability and viscosity of the generated emulsions. Generation of emulsions and increase of flow viscosity might have great influence on well productivity. Introduction Production related formation damage has been estimated to reduce the income by more than 1 million NOK a day in some of the North Sea fields. Although scale formation is touted as the most plausible damage mechanism it cannot explain the reduced productivity in many wells. For about 40% of these cases the exact mechanism of the formation damage is not known. In this respect combinatorial effects were sought as a possible explanation in an overall plugging mechanism. The process of emulsification, that is, dispersion of liquids in liquids, is governed by surface forces.
- Europe > United Kingdom > North Sea (0.54)
- Europe > Norway > North Sea (0.54)
- Europe > Netherlands > North Sea (0.45)
- (2 more...)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Greater Beatrice Area > Block 11/30b > Beatrice Field (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- (9 more...)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
The Correct Selection and Application Methods for Adsorption and Precipitation Scale Inhibitors for Squeeze Treatments in North Sea Oilfields
Jordan, M.M. (Heriot-Watt University) | Sorbie, K.S. (Heriot-Watt University) | Graham, G.M. (Heriot-Watt University) | Taylor, K. (Shell Exploration and Production (Aberdeen)) | Hourston, K.E. (Total Oil Marine (Aberdeen)) | Hennessey, S. (LASMO North Sea (Aberdeen).)
SPE 31125 The Correct Selection and Application Methods for Adsorption and Precipitation Scale Inhibitors for Squeeze Treatments in North Sea Oilfields M.M. Jordan, SPE, K.S. Sorbie, SPE, G.M. Graham, SPE, Department of Petroleum Engineering, Heriot-Watt University, Edinburgh, U.K., K. Taylor, Shell Exploration and Production (Aberdeen), K.E. Hourston, SPE, Total Oil Marine (Aberdeen), and S. Hennessey, LASMO North Sea (Aberdeen). Copyright 1996, Society of Petroleum Engineers, Inc. Abstract Over the past three years, the Oilfield Scale Research Group at Heriot-Watt has conducted a number field studies to evaluated scale inhibitors for both downhole squeeze application and topside continuous injection for a number of North Sea operating companies. This paper presents an approach for screening commercial sulphate and carbonate scale inhibitors for field application. The screening results, which include data from static/dynamic inhibitor efficiency. static adsorption, compatibility and thermal stability are used to rank the performance of commercial scale inhibitors. From this short list, a small number (1 to 3) candidate products are taken on to reservoir condition coreflooding. In the screening of topside scale inhibitors, no adsorption tests are conducted. Results from adsorption and precipitation type corefloods will be compared for polymer and phosphonate chemistries selected using these screening procedures. Such corefloods serve both to evaluate the squeeze lifetime performance and to assess the levels of formation damage caused by the scale inhibitor package. The strategy of deriving a dynamic isotherm which can be utilised in computer modelling of the coreflood data to produce a "Field Squeeze Strategy" will be outlined. This systematic approach provides a set of effective and economical methods for the chemical screening of scale inhibitors. This results in an improved field application strategy with longer squeeze lifetimes, while minimising formation damage potential. Introduction The downhole and topside formation of both sulphate and carbonate inorganic scales can be a serious problem in oilfield production operations. One of the most common and efficient methods for preventing the formation of such deposits is through the use of chemical scale inhibitor "squeeze" treatments. Two main types of inhibitor squeeze treatment can be carried out where the intention is either (a) to adsorb the inhibitor on the rock substrate by a physical-chemical process using a phosphonate or a polymeric material; or (b) to extend the squeeze lifetime of poorly adsorbing scale inhibitors by precipitation (or phase separation) which is commonly achieved by adjusting the solution chemistry ([Ca2+], pH, temperature) of a polymeric inhibitor such as poly phosphino carboxylic acid (PPCA). The central factor governing the dynamics of the inhibitor return curve in adsorption/desorption treatments is the inhibitor/rock interaction as described by the adsorption isotherm, (C). This is a function of the inhibitor type, molecular weight, pH, temperature, mineral substrate and the brine strength and composition. The precise form of (C) determines the squeeze lifetime, as has been described in detail in a number of previous papers. The "precipitation squeeze" process is based on the formation of a gel-like calcium salt, usually of poly phosphinocarboxylic acid scale inhibitor, within the formation. "Precipitation" (or phase separation) is controlled either by temperature and/or pH although it will generally involve a coupled adsorption process. In this paper, our objective is to present a general methodology for the screening of chemical scale inhibitors for both downhole and topside applications. This is illustrated by results generated for application in four North Sea fields, although the Oilfield Scale Research Group have actually applied these methods to over 20 fields. P. 523
- Europe > United Kingdom > North Sea (1.00)
- Europe > Norway > North Sea (1.00)
- Europe > North Sea (1.00)
- (3 more...)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Mississippi > Improve Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Brae Formation (0.99)
- Europe > Norway > North Sea > Tarbert Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract Scale dissolvers have successfully been used to restore well productivity in two Statfjord Field wells suffering from scale induced formation damage. Combined with scale inhibitor treatment further production loss has been avoided. The dissolver efficiency towards BaSO4, and SrSO4, is strongly depending on high pH (pH> 9–10) in the treatment slug. Two different scale dissolvers have been tested, and are found to have equally good performance regarding dissolution capasities and effect on production. Well case histories and details about job design and production data before and after the treatments are documented. Combined scale dissolver and scale inhibitor squeeze treatment is implemented as the current scale treatment strategy for the Statfjord Field. Introduction The Upper and Lower Brent reservoirs in the Statfjord Field are developed with a row of sea water injectors, completed below the oil/water contact, to displace oil up structure to the east toward a row of oil producers near the crest of the structure. Key information about the Statfjord Field is listed in table 1.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea > Northern North Sea (1.00)
- Europe > Norway > North Sea > Northern North Sea (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Statfjord Group (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Cook Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Brent Group (0.99)
- (3 more...)
Abstract Formation damage, tubing plugging and plugged production equipment caused by the deposition of organic deposits and sludge are inherent in many workover and stimulation operations around the world. This paper describes the methodology followed to improve production through adequate stimulation treatments and control of the organic and sludge deposition existing in the south-east of Mexico. In fact, this is a recurring problem that has existed for many years severely affecting oil production. Evaluation of the results and conclusions derived at different stages of the analysis are discussed. The benefits of emulsifying the acid with an aromatic(external phase), are also presented including the key factor of the iron reducing agent in a ferric iron environment in addition to the required iron sequestering agent. Results of stimulations performed in the area are discussed including well performance months after treatments. Introduction Organic deposits and sludge problems are increasing in the petroleum industry. Their precipitation is a problem that has existed for many years in the south east of Mexico, severely affecting oil production. Oil production in the south east of Mexico is distributed between the tertiary sands, the Cretaceous and Jurassic dolomitic limestone's. These last two are found in the 5,000 to 6,200 meters (m) range with temperatures in the 125–155°C. The reservoir considered in this paper is characterized by natural fractures with a 35° API sludge tendency crude containing asphaltenes in the 10–15% range, paraffin in the 15–20% (High Molecular Weight) and 2-5% (Low Molecular Weight) causing routine deposition in the production equipment, tubing and formation. Until recently, the main approach for resolving the severe deposition of these organics has been remedial; i.e., routine injection of appropriate chemicals to dissolve the deposits. In fact, a good portion of the wells have a0.95 cm capillary tubing which is run with the production tubing for continuous injection of both asphaltene and paraffin dispersants to alleviate the problem. However, the persisting asphaltene-sludge precipitation problem was in need for another approach.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
Abstract Nonionic surfactants are commonly used during well stimulation for several reasons. They reduce interfacial tension between the acid and oil phases, thus improving acid/rock interaction. They are also used to form a stable foam which improves the sweep efficiency during acidizing. However, these surfactants should be employed at temperatures below their cloud point (defined as the temperature at which the surfactant solution becomes cloudy). This temperature signifies the onset of the surfactant salting out, which will reduce the efficiency of the stimulation and may damage the formation. An experimental study was conducted to assess the effect of various acids and stimulation additives on the cloud point of nonionic surfactants. The influences of acids (inorganic and organic), mutual solvents, friction reducers, hydrogen sulfide scavengers, sequestering agents, short chain alcohols, simple salts, scale inhibitors, anionic surfactants on the cloud point of several nonionic surfactants were examined over a wide range of parameters. The results indicated that the cloud point monotonically increased with the acid concentration. However, the rate of increase depended on the acid type and the number of ethylene oxide groups of the surfactant. Salts depressed the cloud point of nonionic surfactants at all hydrochloric acid concentrations examined. Alcohols, methanol and isopropanol enhanced the cloud point of nonionic surfactants. The effect of mutual solvents was found to be a function of the number of ethylene oxide groups of the surfactant, acid and mutual solvent concentrations. Anionic surfactants depressed the cloud point of nonionic surfactants at all sodium chloride concentrations examined. Clay stabilizers (cationic polymers) and hydrogen sulfide scavengers depressed the cloud point whereas scale inhibitor and phosphonic acid did not affect the cloud point significantly. It is extremely important to measure the cloud point of nonionic surfactants before performing a stimulation job. It is also recommended to use the acid formulation and mixing waters that will be used in the field. Introduction Well stimulation is a process aimed at the removal of near-wellbore impairment due to deposition of particulate solids during drilling, workover or production operations. In this process an acid or mixture of acids is injected into the well to dissolve and remove this damage. Apart from removing deposited material, the acid can react with the rock matrix and enlarge pore sizes. This will allow insoluble fines to be flushed out when oil production is resumed (producing well) or during backflow (injection well). Enlarging pore sizes will improve the permeability in the wellbore area, hence the productivity or injectivity of the well will improve.
- Asia > Middle East > Saudi Arabia (0.46)
- North America > United States > Louisiana (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.35)
- Research Report > Experimental Study (0.35)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology (1.00)
Abstract Solids characterisation forms an integral part of many studies related to petroleum engineering, e.g., coreflood evaluation assessment of fines migration and characterisation of precipitates; and is often completed using routine analytical methods such as Scanning Electron Microscopy (SEM) and X-Ray Diffraction (XRD). These methods, however, cannot provide sub-micron detail of morphology and chemistry of solids and cannot be applied readily to characterise non-crystalline solids or solids present in low quantities. In this study, ATEM has been applied to examine solids isolated from produced fluids from an oilfield. The method has the potential to give early indication of production problems like sands production and scaling. It has also been used effectively to characterise scale inhibitor precipitates, which are non-crystalline, from corefloods and 'batch' experiments. Although ATEM cannot be viewed as a routine method since it requires specialised equipment and expertise, it can provide critical information. Introduction SEM and XRD are conventional routine solids characterisation techniques applied in many studies related to petroleum engineering, including reservoir evaluation, coreflood experimentation and applied research. Formation damaging solids or precipitates range in size from millimetres to nanometers and can be both crystalline and/or non-crystalline in nature. Both SEM and XRD have limitations in providing comprehensive characterisation. The main limitation of SEM is its inability to characterise very fine solids (<1.0 m) or provide chemical analysis of sub-micron particles. XRD will only aid in the identification of crystalline solids. Solids which are amorphous (non crystalline precipitates/colloidal solids) will remain undetected, as will components present in minor amounts. Analytical Transmission Electron Microscopy (ATEM) is a high resolution technique which can characterise in detail, both crystalline and non-crystalline solids in the size range from nanometers to microns. It has the capability to provide quantitative chemical, morphologic and crystallographic analysis of isolated sub-micron sized solids. Solids Studied In this study ATEM has been applied to determine morphology and chemistry of a variety of solids from produced fluids, evaluation corefloods and experimental studies. Filters from produced fluid samples taken from separate producing wells of a North Sea oilfield have been examined. These formed part of a comprehensive analysis programme of both fluids and solids being undertaken on a new field prior to water injection. Corefloods are often undertaken to evaluate the most effective application of scale inhibitor for a particular oilfield. Routine experimental procedures include fluid analysis of effluent and whole rock XRD. In this study, effluents were filtered through <0.02 m filters as the coreflood progressed and resulting 'trapped' solids examined by ATEM. Scale inhibitor squeeze treatments are routinely undertaken by adsorption methods which applies a thin monolayer of inhibitor onto exposed mineral substrates. An alternative approach, by the emplacement of inhibitor precipitate within the rock porosity, has been evaluated by coreflood and 'batch' experimentation for application in a North Sea oilfield.
- Europe > United Kingdom > North Sea (0.49)
- Europe > Norway > North Sea (0.49)
- Europe > North Sea (0.49)
- (3 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
ABSTRACT ONLY - COMPLETE MANUSCRIPT IS NOT AVAILABLE. We conducted an experimental investigation of the formation damage caused by the interaction of common scale inhibitor chemistries with reservoir clays. It is important to minimize permeability loss during scale inhibitor squeeze treatments because this process involves injecting a high concentration inhibitor solution into the near well bore region of a producer. One motivation for this study was to explain the formation damage observed after some squeeze treatments in a California field. Two types of sandstones were studied: unfired Berea (1 00-200 md, has nonswelling, kaolinite clay) and a San Joaquin Valley reservoir rock (1-1 0 md, has swelling, smectite clays). We performed a series of corefloods to examine the tendency of these scale inhibitor solutions to reduce permeability via clay deflocculation, swelling, or dispersion over a wide range of NaCI salinities. Two scale inhibitors were tested: diethylenetriaminepenta (methylene phosphonic acid) (DETPMP) and a phosphinopolycarboxylic acid (PPCA). Neutral pH solutions were used in all coreflood experiments to prevent mineral dissolution and other complicating effects. Some floods included a preflush with a clay stabilizer (dimethylamine-epichlorohydrin copolymer -DEC). The experimental program included X-ray diffraction (XRD) studies to verify inhibitor/clay damage mechanisms indicated by the coreflood results. Results and Conclusions are:The minimum salinity required to prevent damage (critical salt concentration - CSC) is roughly twice as high in the California sandstone versus Berea sandstone, with or without inhibitor present (Figure 1 and 2). At any given sodium salinity, brines containing either type of scale inhibitor caused more damage to both sandstones than NaCI brines (no scale inhibitor). See Figures 1 and 2. Clay-related permeability loss can be avoided by using a makeup brine with a salinity that is greater than the CSC for that scale inhibitor solution/rock combination. In Berea sandstone, a DEC clay stabilizer preflush eliminated formation damage caused by injection of DETPMP (even in distilled makeup water). However, severe damage occurred in Berea cores where the DEC preflush was followed by the PPCA, due to an incompatibility between DEC and PPCA. For the California sandstone, a DEC preflush reduced, but did not eliminate formation damage for both inhibitor types (Figure 3). In this case there was no apparent DEC/PPCA incompatibility. XRD studies indicate that the stabilizer was adsorbed into the interlayers of the smectite structure, thereby reducing the interaction with the inhibitor. Formation damage associated with scale inhibitor squeezes in this California field were the result of in-situ emulsions, not clay swelling or migration.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
ABSTRACT Modifications of flow properties may be observed when injected brine replaces formation water, especially when the salinity of the injected brine is lower than the resident one. This is generally attributed to detrimental physico-chemical rock/fluid interactions such as ion exchanges. This paper concers ion exchange mechanisms related to permeability damage. A laboratory study conducted in batch and flow conditions relates the permeability reduction to the physico-chemical rock interaction. Batch experiments aim to determine the Critical Salt Concentration (CSC) for clay deflocculation. Flow experiments show the effect of pH and water composition on the permeability reduction in a transient region resulting from ion exchanges. These experiments are represented by a flow model involving ion exchange, CSC and permeability reduction. The modeling of the physico-chemical interaction in flow conditions compares very well with experimental results in a wide range of situations. A 3D chemical model including two phase flow and physico-chemical equilibria is presented for extrapolating laboratory data to reservoir scale. The numerical study evaluates the effect of the composition of both the resident brine and the injected solution on the resulting properties of the reservoir. The conclusions obtained from the simulations enabled us to deduce different strategies for optimizing well treatment or water injection. It is shown that detrimental permeability effects can be avoided by adjusting the water compositions. INTRODUCTION Formation clays respond to inadequate salinity waters by swelling or deflocculating. Both mechanisms cause clay particle release, entrainment and then particle entrapment thus reducing the permeability of the formation. Two important parameters have been widely studied:salinity and nature of the salt. Previous studies have evidenced the existence of a Critical Salt Concentration below which a drastic decrease of permeability occurs. On the other hand, it is well-known that divalent cations are generally more effective than monovalent cations in flocculating clay. However, among the monovalent cations, potassium has a particular status and is considered to have properties equivalent to those attributed to calcium. It follows, in order to explain permeability damage, that both factors, total salinity and nature of salts, must be considered together, and consequently simple rules are difficult to establish to predict rock/fluid compatibility with petroleum brines containing cations with opposite effects.
- Well Drilling > Formation Damage (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology (1.00)
ABSTRACT ONLY - COMPLETE MANUSCRIPT IS NOT AVAILABLE. Asphaltene deposit accumulations, either in surface facilities or within the producing interval of the formation, can seriously decrease productivity up to the point where remedial work is required to remove the deposit and restore production. Focusing on the problem of asphaltene accumulation within the formation, the most common treatment is based on washing the reservoir in the near well-bore region with aromatic solvents either pure or doped with solvent-enhancing additives. These remedial treatments are often unsuccessful owing to incomplete removal of the deposit. In our opinion, underestimation of the specific asphaltene/formation rock interactions within the problem formation may be an important factor in determining the failure rate. This paper describes a new experimental approach for selecting or defining the best suited solvent or solvent/additive system for a given asphaltene/formation rock combination, so that more effective removal of the asphaltene deposits can be achieved. INTRODUCTION Asphaltene deposits within the producing formation are constituted by two different types: the asphaltenes adsorbed onto the formation rock and bulk asphaltenes. Bulk asphaltenes are defined as asphaltenes aggregated from the oil medium and deposited onto the adsorbed asphaltenes. Because these two types of asphaltenes are characterized by interaction forces that are substantially different both in quality and intensity, they might be expected to present quite a different degree of removability with respect to a chosen solvent or chemical. In fact, considering those asphaltenes obtained by n-heptane precipitation from stock tank oil (i.e., the "softest" form of such material), toluene, as a typical solvent, shows a very high up-take (several tens of a %, w/w) when the asphaltenes are in the bulk state; on the contrary, the asphaltene up-take by toluene is very low (10–20 %, w/w) when the same material is adsorbed on a rock surface (clays, dolomia, quartz, etc.). In spite of this evidence, the most common remedial approach, based on solvent washing, refers only to bulk asphaltenes. Moreover, the activity of solvent enhancing additives, which range from aliphatic amines to alkyl benzene sulphonic acid (1,2), are still defined with respect to bulk asphaltenes. In our opinion, underestimation of the specific asphaltene/formation rock interactions within the problem formation may be an important factor in determining the failure rate. In fact, reports indicate only limited success with such solvent treatments, owing to incomplete removal of the deposits (3).
- Europe > Norway > Norwegian Sea (0.24)
- North America > United States > Louisiana (0.15)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)