Aromatic-based solvents, including benzene, toluene, xylene (BTX) and their derivatives have been successfully applied for asphaltene removal from downhole and surface facilities. These solvents are considered non-environmentally friendly due to their associated health and safety concerns including high toxicity, low biodegradability and low flash point. Currently, more attention has been given in the oil industry to develop environmentally friendly asphaltene solvents.
This paper examines several environmentally friendly solvents derived from natural precursors to dissolve asphaltene, wax and combined asphaltene/paraffin organic deposit. A group of plant-derived and terpene-based asphaltene solvents with flash points ranging from 50.5 to 136 °C was examined in this study. Extracted asphaltene from a crude oil and wax obtained from distillation were used to assess solvency power of these solvents. Solubility of organic deposits containing more 42 wt% asphaltene with associated paraffin was evaluated in these solvents. The performance of these solvents was examined as a function of soaking time and temperature. These environmentally friendly solvents showed comparable solvency power to toluene. The lowest flash point solvent exhibited the highest solvency power for asphaltene while the opposite relation was observed for the wax sample. The lowest flash point (50.5 °C) solvent was able to dissolve 91 wt% of the asphaltene sample after soaking for 2 hours at ambient temperature compared with the highest flash point solvent (136 °C), which dissolved only 7.4 wt% at the same conditions. For wax, the solvent with the second highest flash point (132 °C) was able to dissolve 97 wt% of the wax while the solvent with a flash point of 50.5 °C was able to dissolve 85.5 wt% at ambient temperature and after 2 hours. Some of the examined environmentally friendly solvents showed very high dissolution power to organic deposits composed of asphaltene and paraffin where a solubility of 96 wt% was obtained at 80 °C and after a soaking time of 6 hours. The paper will discuss these results in detail.
Romero Quishpe, Adriana (YPF Tecnología S.A.) | Silva Alonso, Katherine (YPF S.A.) | Alvarez Claramunt, Juan Ignacio (YPF S.A.) | Barros, Jose Luis (YPF S.A.) | Bizzotto, Pablo (YPF S.A.) | Ferrigno, Eugenio (YPF S.A.) | Martinez, Gustavo (YPF S.A.)
A well is in natural flowing state when its bottom-hole pressure is enough to produce to the surface. Natural flowing well’s production is regulated by using surface restrictions to regulate the production rate in such a way that the overall well performance is a function of several variables. Examples of these variables are tubing size, choke size, wellhead pressure, flow line size, and perforation density. This implies that changing any of these variables will modify well performance. One of the techniques for the analysis of production performsnce is studying the wellhead pressure declination, since, in critical flow conditions, flow is a function of wellhead pressure. From wellhead pressure trends you can identify the behavior of each well and determine some issues, such as: choke erosion due to sand production, choke o tubing paraffin plugging or choke obstruction. In order to achieve an effective real-time monitoring of this type of wells, and in this way reduce the production losses, the challenge was to create online tools that could detect those mentioned issues.
The present work performs the analysis of wellhead pressure curves using data science, with the purpose of predicting real time anomalies that could occur for timely correction. The data correspond to 130 flowing wells from the Loma Campana Field. The study began with a filtering process of the pressure curve, with two specific objectives: first, eliminate atypical values from the time series, and second, smooth the curve in such a way that future predictions can be performed. Next, the Prophet methodology was applied with the purpose of predicting values of the curve. This is based on historicsl values of the time series to predict future values; the trend characteristic of the curve was used to apply this methodology. Then, to identify the anomaly a model was designed based on the declination of the curve. The pressure declination curve is a descending exponential function, so the first and second derivatives indicate the trend (ascending - descending) and curvature (concave or convex) of it. Once these values are available, they are classified according to the anomaly: paraffin, encrustation or obstruction. Finally, the model is being tested in the Loma Campana control room, delivering a probability of occurrence of any anomalies every hour.
Feustel, Michael (Clariant) | Goncharov, Victor (Clariant) | Kaiser, Anton (Clariant) | Smith, Rashod (Clariant) | Sahl, Mike (Clariant) | Kayser, Christoph (Clariant) | Wylde, Jonathan (Clariant) | Chapa, Amanda (Clariant)
Transportation of waxy crude oils and mitigation of wax deposition are major challenges especially in regions with cold climate. A viable solution for minimizing organic precipitation and fouling in pipelines or storage tanks is the use of inhibitors and dispersants, however, often those pour point depressants (PPDs) have their own challenges due to their own high product pour points. To overcome these issues a series of high active winterized polymer micro-dispersions were developed. Composition and physical properties of several light to heavy waxy crudes were fully explored based on SARA analysis, wax content and paraffin carbon chain distribution. Performance of candidate chemistries from four major classes of polymeric paraffin inhibitors were studied using industry standard methods. Selected high performing chemistries were processed into micro-dispersions using solvents and surfactants under high shear/ high pressure blending. The new polymer micro-dispersions (MDs) were characterized by their pumpability and stability at cold climates. Series of pour point measurements, rheology profiles and wax deposition tests were carried out for performance comparison of MDs to standard polymers in solution. Processes developed here were versatile to convert polymers from all classes of chemistries into micro-dispersion. Binary and ternary polymeric dispersions were also created showing synergistic effects on the pour point reduction and inhibition of wax deposition of the selected challenging crude oils. The performance of the new polymer micro-dispersions was found comparable to superior with standard polymers in solution. Hence, it was possible to create pumpable inhibitors for extreme cold climates without compromising on performance. The systematic approach used here allowed development of more customized solution based on crude characteristics and desired performance. Micro-dispersions were found stable for long term storage in temperatures ranging from -50°C to +50°C. Multiple global field trials are on-going with very positive results demonstrating early success in lab-to-field deployment. Based on lab and field data, this paper demonstrates that highly active micro-dispersed polymers can perform at significantly lower dosage rate when compared to winterized polymers in solution. Cold storage stability and pumpability eliminated the needs for heated tanks and lines reducing operation and capital expenditures.
As operators rely on longer subsea tiebacks, an upward trend in the number of plugs caused by paraffins and hydrates has been seen. New prevention and remediation methods are discussed to help solve these challenges. A former technical manager with Petrobras discusses the development of the company’s flow assurance philosophies and strategies.
Cold finger tests are a standard method for testing paraffin inhibitors, but there is no standard testing protocol, and sometimes different labs can see inconsistent results. Shell and BHGE studied the root causes of these issues. As operators rely on longer subsea tiebacks, an upward trend in the number of plugs caused by paraffins and hydrates has been seen. New prevention and remediation methods are discussed to help solve these challenges. A test method is being developed to screen paraffin chemistries in the presence of brine, closer resembling dynamic field conditions.
An oil/gas separator is a pressure vessel used for separating a well stream into gaseous and liquid components. They are installed either in an onshore processing station or on an offshore platform. Based on the vessel configurations, the oil/gas separators can be divided into horizontal, vertical, or spherical separators. In teams of fluids to be separated, the oil/gas separators can be grouped into gas/liquid two-phase separator or oil/gas/water three-phase separator. Based on separation function, the oil/gas separators can also classified into primary phase separator, test separator, high-pressure separator, low-pressure separator, deliquilizer, degasser, etc. To meet process requirements, the oil/gas separators are normally designed in stages, in which the first stage separator is used for priliminary phase separation, while the second and third stage separator are applied for further treatment of each individual phase (gas, oil and water). Depending on a specific application, oil/gas separators are also called deliquilizer or degasser.
While downhole pumps and sucker rods are the chief components of a sucker-rod lift type artificial lift system, a number of other components are also used in the subsurface portion of the system. These include tubing, tubing anchor-catchers, tubing rotators, sinker bars, rod centralizers, and paraffin scrapers. Tubing provides detailed information on the design, selection, and use of tubing for production wells.
It is evident that, to quantify formation damage and to study its impact on hydrocarbon production, one must have reasonable estimates of the flow efficiency or skin factor. Several methods have been proposed to evaluate these quantities for oil and gas wells. The most common methods are multirate tests, isochronal gas-well tests, and transient well tests (pressure-buildup analysis). Multirate tests can be conducted on both oil and gas wells. In these tests, several stabilized flow rates, qi, are achieved at corresponding stabilized flowing bottomhole pressures, pwf. The simplest analysis considers two different stabilized rates and pressures.
Perhaps the most common formation damage problem reported in the mature oil-producing regions of the world is organic deposits forming both in and around the wellbore. These deposits can occur in tubing, or in the pores of the reservoir rock. Both effectively choke the flow of hydrocarbons. Table 1 shows the gross composition of crude oils, tars, and bitumens obtained from various sources. More degraded crudes, including tars and bitumens, contain substantially larger proportions of resins and asphaltenes.
Crude oil characterization has long been an area of concern in refining; however, the need to identify the chemical nature of crude has gained importance in upstream operations. Traditionally, this has been done by simply stating the crude oil gravity, but more information is required to understand the oil well enough to estimate the volume in the reservoir and its recoverability. During the last 60 years, several correlations have been proposed for determining pressure-volume-temperature (PVT) properties. The most widely used correlations treat the oil and gas phases as a two-component system. Only the pressure, temperature, specific gravity, and relative amount of each component are used to characterize the oil's PVT properties.