Flow Assurance Fluid sampling and analysis services
Applications ■
Phase behavior testing
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Determining the physical properties of waxes, asphaltenes, and hydrates
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Assessing the risk associated with flow-impairment phenomena
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Proactively monitoring production
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Optimizing chemical inhibition
Benefits ■
Decrease production and remediation costs
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Reduce system overdesign
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Optimize fluid flow behavior
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Determine optimized pigging frequencies and remediation strategies
Features ■
Characterization of fluids under actual reservoir and process conditions
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Laser-based solids detection system (SDS) to evaluate the changes in pressure, temperature, or composition where solids precipitate
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High-pressure microscope (HPM) to visually observe the onset and growth of organic solid precipitates
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Particle size analyzer (PSA) to determine the size and distribution of solids and immiscible liquids
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Data to determine optimized pigging frequencies and remediation strategies
Resolving flow assurance problems means different things to different people. To some, it is unclogging wells, tieback lines and jumpers, and gathering stations and risers of productionrobbing deposits of paraffin, scale, or hydrate. Others take a more proactive approach by monitoring data and feeding it into production models to enable predictions of flow problems in time to take preventive actions. Flow assurance is a multidiscipline process involving sampling, laboratory analysis, and production and facilities engineering to ensure uninterrupted optimum well productivity. Laboratory testing provides necessary data to assess the flow assurance risk because it defines phase behavior and the properties of the waxes, asphaltenes, and hydrates known to be principal causes of flow problems. Schlumberger Oilphase-DBR* fluid sampling and analysis services use proven laboratory testing procedures for each of these problematic solids. With technologies that characterize fluid samples visually and quantitatively at realistic reservoir conditions, Oilphase-DBR services provide comprehensive flow assurance studies that can help prevent or mediate flow impairment caused by deposition of organic solids. Oilphase-DBR services include reservoir fluid sampling, surface sampling, sample management, sample container service and supply, improved oil recovery studies, flow assurance studies, wellsite fluids analysis services, laboratory phase behavior (PVT) studies, and software services.
Wax behavior Paraffinic or waxy crude oils are produced globally. In environments such as subsea tiebacks, the precipitation, deposition, and gelling of solid waxes in hydrocarbon fluids constitute critical production concerns. Accurate fluid characterization is an important component of any development, production, or intervention strategy for handling waxy crude. Understanding wax behavior can help avoid high costs resulting from output reductions or stoppages, or conversely, from system overdesign. Either situation can occur when facilities or treatment regimes are designed on the basis of
incomplete or overly conservative estimates of the potential for wax-related fouling or plugging.
Live fluid analysis When assessing a waxy crude production or transport situation, relying solely on conventional dead crude wax tests, including wax content and wax appearance temperature measurements, can be misleading. Stock-tank oil tests are insufficiently representative of field situations because reservoir pressure and solution gas have a strong influence on wax solubility. Laboratory-scale tests must account for the actual thermophysical situation in the field if they are to be applicable. To facilitate the most appropriate and cost-effective planning for wax inhibition, remediation strategies, or both, Oilphase-DBR services include simulation of a variety of actual reservoir or process conditions for characterizing the waxy properties of production fluids.
Wax appearance temperature and pour point The wax appearance temperature (WAT) is the temperature below which a solid wax phase forms within a hydrocarbon fluid at a given pressure. Below the WAT, significant viscosity increases, deposition, and gelling are possible. The pour point is the temperature, at a given pressure, below which the static fluid may form a gel. For a system cooled below its pour point, restarting flow may be difficult or impossible. Oilphase-DBR services determine the WAT of production fluids using crosspolar microscopy (CPM), a visual technique enabling direct identification of the onset of precipitation and the morphology of the wax crystals. Using depressurized stock-tank oil, this test can be performed as a preliminary indication of the likelihood of wax-related production problems. If potential for wax formation is identified, high-pressure CPM tests can be carried out under simulated production pressure conditions. Pour point tests can also be performed on depressurized or live reservoir fluids. A modified American Society of Testing and Materials International D 97 technique is used to assess the temperature at which a live waxy liquid at a constant
elevated pressure, and in contact with solution gas, ceases to display fluid behavior when cooled quiescently.
Live oil pour point effect of adding solution gas.
Rheology Waxy crudes below their WAT do not exhibit simple viscous behavior. These fluids manifest shear-thinning viscosity and other complex rheological phenomena that must be properly quantified to completely optimize the design of waxycrude flowlines. For this purpose, Oilphase-DBR services use a full-featured, controlled-stress, high-pressure rheometer that operates to 41,369 kPa [6,000 psi] and 150 degC [302 degF]. Oilphase-DBR services include systematic rheometry under simulated conditions of live-fluid composition and processing pressures.
Gel strength If a well shut-in condition leads to gel formation in waxy crude, the flow cannot be restarted unless a certain minimum stress level is applied to the system. This threshold-yield stress is termed the gel strength. Gel strength measurements provide an indication of the restart requirements of gelled crude and allow for selecting the most appropriate techniques. OilphaseDBR services include a model pipeline test (MPT) that measures the factors affecting gel strength, including pressure, thermal history, system geometry, and fluid composition. The MPT is performed at well conditions.
Pour-point temperature
0
150
1,500
3,000
Saturation pressure, psi
Gel strength versus temperature.
MPT1 MPT2
Gel strength
48
58
72
86
Temperature, degF
Advanced tests Wax solubility modeling is performed by evaluating the n-paraffin distribution of a crude oil to C90+ using high-temperature gas chromatography and by quantifying wax precipitation using live-oil filtration. Specialized studies can also be carried out in wax-crystal growth kinetics, coprecipitation of waxes with asphaltenes, deposition measurement using organic solids deposition technology and modeling, and various other means of practical and research interest—including flow loop testing.
Asphaltene testing Asphaltenic crudes create exceptionally difficult flow problems. Normal production practices can cause, or
worsen, these problems. For example, asphaltene-induced flow impairment can be caused by normal pressure drop in the near-wellbore region or by crude dilution that occurs during gas lift. A suite of specialized proprietary tests that help predict and control these problems is provided by Oilphase-DBR services.
Solids detection system A laser-based SDS has been developed to define the pressure and temperature at which asphaltenes precipitate because of fluid expansion depressurization of the crude oil during production. The SDS unit attaches directly to the PVT phase
behavior cell, and the near-infrared laser beam passes through the reservoir fluid contained within the cell. By monitoring the intensity of the transmitted laser beam during the isothermal constant composition expansion depressurization process, the asphaltene precipitation onset (APO) is identified by a marked decrease in the transmitted laser beam intensity. By repeating this procedure at different temperatures, the complete APO envelope can be defined. Compositional changes, such as those that occur during gas lift, are simulated by incremental, isobaric gas-solvent injections. These procedures provide a thorough understanding of the complete range of conditions where APO occurs.
High-pressure microscopy The studies of organic solids have been greatly enhanced by development of the Oilphase-DBR HPM. The ability to directly observe the onset and growth of organic solid precipitates at pressures to 137,895 kPa [20,000 psi] and temperatures to 200 degC [392 degF] provides visual definition of the types of solids present. It is also possible to define the abundance and morphology of these solids as they grow. More importantly, it is possible to use Oilphase-DBR services to evaluate and optimize the effectiveness of various chemical programs of solids inhibition or remediation. The ongoing developments in HPM technology, including the cross-polar HPM, enable study of the phenomena of pressurized wax formation or coprecipitation of waxes and asphaltenes.
Particle size analysis Oilphase-DBR services provide a proprietary image analysis technology for PSA. The PSA process operates as a synchronous feature of the HPM, making it possible to determine the number and sizes of solid particles that are visually apparent. The system is calibrated using particle standards of various sizes and concentrations. The PSA uses proprietary image analysis software to determine the onsets, sizes, and distributions of wax, asphaltene, and immiscible hydrocarbon-liquid or water droplets that are present.
Organic solids deposition and control service The Schlumberger Oilphase-DBR organic solids deposition and control (OSDC) service is an essential flow assurance characterization tool capable of simulating the production conditions of oil and gas streams. The effect of pressure, temperature, composition, surface type, surface roughness, flow regime, and shear on the deposition behavior of waxes and asphaltenes can be evaluated. The OSDC service allows for independent variation of these test parameters to quantify their corresponding effect on
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Precipitation onset envelopes.
Wax
Hydrodynamic path
Initial reservoir pressure and temperature Critical point
Pressure
Hydrate
Asphaltene envelope
Vapor-liquid equilibrium
Temperature
deposition tendency and rate. Unlike pipe flow loops and other conventional methods used in evaluating flow assurance production system design and chemical screening, the OSDC service can test export oils (low pressure), as well as bottomhole and pressurized fluids, up to 103,420 kPa [15,000 psi]. In addition, basic OSDC testing can be completed using approximately 150 mL of reservoir fluid (per measurement point). This procedure leads to a savings in both sampling cost and sample consumption compared with the multiple-barrel sample requirements of traditional flow loop testing. By performing deposition measurements at line conditions, the OSDC service enables less conservative system design and operation when appropriate, while decreasing the risk associated with the uncertainty inherent in conventional data scaling practices. The OSDC service offers a direct laboratory measurement of organic solids deposition tendency that can be translated to the field.
Hydrate behavior The Oilphase-DBR fluid sampling and analysis services use three mercury-free system configurations, two visual and one non-visual, for the thermodynamic study of hydrate behavior.
The PVT cell configuration and the Sapphire* pressure gauge cell configuration both use proprietary visual technology. A customized Autoclave cell technique utilizes proprietary nonvisual technology. System capabilities include measuring hydrate formation conditions for fluid systems containing natural gas, CO2, H2S, gas condensate, or oil in the presence of water or brine. These systems support studying the effectiveness of various hydrate inhibitors such as methanol, glycol, and electrolyte solutions. They are also used in determining the maximum concentration of water vapor allowable, while avoiding hydrate formation at a prespecified operating temperature and pressure condition.
Innovative technologies for flow assurance studies As a leading provider of reservoir fluid sampling, wellsite analysis, sample management, and fluid phase behavior and flow assurance laboratory studies, Schlumberger offers clients the benefits of synergized technological innovations and data that meet exacting quality standards.
