Monitoring and Mitigating Asphaltene Issues in a Deepwater Production System
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An asphaltene threat was identified in production wells located in a Gulf of Mexico deepwater field. During reservoir-fluids characterization, asphaltenes were identified as a key risk factor for successful field development. This paper presents an integrated approach to evaluate the key elements of asphaltene risk for deepwater projects, the strategy to manage the issues during production implementation, and aspects to be considered in the mitigation of asphaltene in the field-development plan.
Asphaltene precipitation and deposition can occur at different stages during petroleum production, causing reservoir formation damage and plugging of pipelines and production equipment.
Remediation of asphaltene deposits requires solvent-soaking operations, followed by removal through exposure to turbulent flow. These intensive operations require high amounts of chemical solvents with potential effects on health, safety, and environment, along with production deferrals because of operations downtime.
The focus of this study is to understand the effects of asphaltene precipitation in a Gulf of Mexico deepwater field. The approach is based on reservoir-fluid characterization and monitoring tools. Being able to predict the presence and type of trouble zones along the production system from downhole to production facilities is becoming progressively more important as water depths increase.
Acquisition of Downhole Fluid Samples
High-quality pressurized bottomhole samples were collected for asphaltene-onset-pressure (AOP) and wax-appearance-temperature (WAT) measurements in pressure-compensated chambers. Because the samples tend to cool to below reservoir temperatures as they are retrieved from the well, the samples were maintained at pressures above reservoir condition at all times to reduce the possibility of irreversible asphaltene precipitation resulting in non-representative samples.
The de Boer Plot. The de Boer plot is a method to screen crude oils for their tendency to precipitate asphaltenes. It essentially evaluates the loss of asphaltene solubility as a reservoir-fluid sample is depressurized. This pressure/volume/temperature screen is a crossplot of in-situ density and the degree of undersaturation with respect to gas (the difference between reservoir pressure and saturation pressure). Because this screening assumes that the fluid is saturated with respect to asphaltene at reservoir conditions, it is extremely conservative.
The Resin-to-Asphaltene (RTA) Ratio Plot. The RTA ratio indicates asphaltene stability because of the presence of resins. The statistics-based rules for the RTA ratio required to keep the asphaltenes stable are
- RTA ratio<1.5—Asphaltenes expected to be unstable during expansion of oil
- RTA Ratio>2.5—Asphaltenes expected to be stable during expansion of oil
- RTA Ratio 1.5–2.5—Transition region
While gathering fluid data, the boundary of the stable region was increased to 3.5 to be conservative in the field. The experimental data demonstrated that this method was not effective in the field.
Experimental Techniques To Determine AOP and WAT
During pressure depletion at constant temperature, asphaltene aggregate formation is observed within a range above and below the bubblepoint. As pressure drops from the reservoir pressure during production, asphaltene precipitation can appear because of changes in density that produce changes in the solubility of asphaltene in crude oil. The maximum asphaltene precipitation occurs at or near the bubblepoint pressure.
The AOP test is performed in a high-pressure visual cell. The depressurization experiment is performed with the simultaneous measurement of light-transmittance power. The solid-deposition-system (SDS) technique includes a fixed-wavelength laser-light source and a detector. While directing a light source through the reservoir fluid, changes in the absorbance of the beam are monitored. The transmitted power of the near-infrared light-scattering signal is recorded during the depressurization process. Before the onset, the transmitted light signal is inversely proportional to the fluid density. During depressurization, the signal power increases. If particles appear, then the signal power decreases.
The high-pressure microscope (HPM) is a microscope connected to a commercially available camera; it is used in conjunction with a lens to observe the sample visually. The camera is connected to a computer to obtain photographs and monitor real-time changes in the fluid. The HPM can detect asphaltene particles larger than 1 μm, and it can measure asphaltene-particle growth quantitatively.
Cross-polar-microscope (CPM) technology is used to determine the appearance and disappearance temperatures of the wax solids visually. The CPM works on the principle of the polarization of light. A polarizer is placed below the sample plate; therefore, the light is polarized as it passes through the sample. Above the sample, before the visual detector, there is another polarizer oriented at a 90° offset. This will block out all the polarized light passing through the fluid sample; therefore, the visual images will be black and the light power meter will have a low reading. As the wax crystals start to precipitate, they will depolarize the light, allowing some light to pass by the top polarizer. In turn, the wax particles will appear to be glowing against the dark black background. At this point, the WAT is determined.
WAT for live fluids is determined in a high-pressure/high-temperature cell by slowly reducing the fluid’s temperature while holding the live fluid at constant pressure in the SDS cell. This technique allows studying the ability of the dissolved-gas content to hold the wax in the liquid phase. While directing a light source through the reservoir fluid, changes in the absorbance of the beam are monitored. WAT, therefore, can be obtained by plotting the transmitted power while cooling.
Fluid A is located in the shallow layer of the field. The reservoir pressure is approximately 12,000 psia at temperatures between 175 and 190°F. Asphaltene issues while producing Fluid A are expected to occur in the reservoir and the near-wellbore region. The fluid properties indicate a high tendency to precipitate asphaltene from the early stages of production.
Asphaltene issues while producing Fluid B are expected to occur in the tubing above the wellbore region. Issues are also expected along the downhole equipment and below the wellhead. These fluids have low asphaltene content (approximately 1 wt%), and no significant amount of deposition has been observed.
Similarly, asphaltene issues while producing Fluid C are expected to occur in the tubing above the wellbore region. However, the asphaltene content in Fluid C is much higher (2–3 wt%). A significant amount of returns has been collected from these fluids after pigging.
Fig. 1 above shows the phase behavior of the heaviest fluids in the field located in the deepest layers.
The asphaltene content in Fluid D is relatively high (up to 4 wt%); however, because of their low gas/oil ratio (approximately 500 scf/bbl), these fluids are considered more stable from an asphaltene point of view. Asphaltene issues while producing Fluid D are expected to occur in the pipeline, riser, and facilities.
The wax-appearance measurements for Fluids A through D indicate that the precipitation and deposition of waxes will not be an issue during normal production of these fluids.
Asphaltene-Inhibitor (AI) Effect on AOP
The SDS technique was used to evaluate the performance of AI. The test measures the ability of the chemical to reduce the AOP and, therefore, mitigate the asphaltene-deposition tendency. AIs are commonly dispersants that reduce the asphaltene aggregate particle size, potentially reducing the onset of asphaltene precipitation. The effectiveness of the chemical to mitigate asphaltene deposition is evaluated by its capability to disperse precipitated asphaltene particles.
The SDS test is performed at reservoir conditions using live reservoir fluid. The asphaltene-deposition mechanism, however, is not completely understood, and some schools of thought argue that stronger deposits are formed whenever smaller particles are precipitating.
In the laboratory, the AOP of some of the reservoir fluids was measured after injecting 700 ppm of two AIs. The chemicals were injected directly into the pressurized cell at reservoir pressure. No obvious benefit on the AOP of Fluid C was observed. The chemicals change the AOP between 200 and 400 psi, which is within the experimental error.
In the field, multiple rates of AI chemical have been introduced, which have had varying effect on the deposition rate seen in the flowline. The different rates and chemicals have also led to variances in deposition volumes collected during pigging operations. The results of this test suggested that AI chemical can affect the deposition rate adversely by increasing it above the baseline rate (no AI chemical present), thus showing that an overtreatment mechanism can be seen as well as an undertreatment mechanism.
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