Natural Resources Research, Vol. 26, No. 1, January 2017 ( 2016) DOI: 10.1007/s11053-016-9302-7
Risk of Wax Precipitation in Oil Well I. A. Struchkov1,2 and M. K. Rogachev1 Received 20 February 2016; accepted 21 June 2016 Published online: 4 July 2016
The objective of this research is to simulate the impact of well operation conditions on wax precipitation in an oil sample, and to predict the wax-free well flowrate. Laboratory studies help producers to protect oil wells from potential problems. The maximum rise of simulated well operation conditions to in situ oil recovery leads to oilfield practice. The methods used for testing of oil sample were microscopy under high pressure with grain size analysis and light-scattering technique, which were conducted using laboratory equipment suited for investigations of reservoir fluids in conditions close to oilfield conditions. Experiments with modeling of temperature and pressure drop rates, flow velocity, and flow through time from downhole to wellhead were carried out. These experiments resulted in modeling of the relationship between functional pressure and wax appearance temperature (WAT), which is properly consistent with the Clapeyron–Clausius equation in a range of well operation conditions. Experimental simulation of well thermobaric operation conditions also resulted in definition of potential wax formation area in the tubing. Research data showed that WAT declines with increase in flow velocity and temperature, and pressure drop rates. Calculations demonstrated that an increase in flow velocity by 0.04 m/sec (equivalent to a well flowrate of 20 m3 per day) leads to a decrease in wax formation depth of up to approximately 200 meters. Guidelines for slowdown of asphaltene–resin–paraffin particles formation in the well by chemical treatment are made. KEY WORDS: Wax, Wax appearance temperature, Wax precipitation, Live oil sample, Production conditions.
During oil recovery, the fluid produced changes in composition, physical, and chemical properties. Such changes also cause irreversible phase changes in an oil disperse system. Therefore, oil production is constantly attended by organic deposition on the surface of downhole equipment, and in the transportation and processing systems (Mansoori 1997; Goual 2012; Idris and Okoro 2013). Organic deposition is primarily related to paraffin crystallization, forming a continuous three-dimensional macromolecular structure, which is stabilized by molecules of asphaltenes and resins. However, just the presence of asphaltenes in oil, resins, and wax does not mean that paraffin crystallization will be complicated by organic depositions on the surface of downhole equipment because depth and intensity of a solid phase build-up depends on water cut, flow-
INTRODUCTION The modern stage of the Russian petroleum industry growth is characterized by rise in asphaltenes, resins, and wax content of oil as a result of development of problematic oils. When designing any oil field exploration, operators must analyze the most possible dangers that will appear during its exploitation. Petroleum engineers carry out a comprehensive review of production risks and develop methods for their prevention and remediation. 1
Development and Exploitation of Oil and Gas Fields Department, Saint-Petersburg Mining University, Saint Petersburg, The Russian Federation, 21st Line, St Petersburg 199106, Russia. 2 To whom correspondence should be addressed; e-mail:
[email protected]
67 1520-7439/17/0100-0067/0 2016 International Association for Mathematical Geosciences
68 rate, gas-oil ratio, oil composition, its physical and chemical properties, pressure, mechanical impurities, etc. In most cases, the formation of an organic solid phase is caused by reduction in oil solvating power for paraffin molecules due to temperature drop during oil upflow and compositional changes when solution gas liberates from the oil. Wax buildup reduces well flowrates, causes expenditures for sediment removal and preventive actions, raising cost of crude oil. Wax accumulation depth and intensity of solid organic phase deposition on the surface of downhole equipment depend on well operation conditions and some other factors (Weingarten and Euchner 1988). Laboratory studies of live oil samples primarily focus on modeling hydrodynamic conditions due to the ultimate rise in well operation conditions. Laboratory simulations of borehole conditions represent the first stage of solving the problems under consideration. To predict paraffin deposition, many studies have used various models (e.g., Bern et al. 1980; Brown et al. 1993; Singh et al. 2000) based on ultimate mechanisms such as molecular diffusion, shear dispersion, and data of experimental studies such as oil viscosity, density, wax appearance temperature (WAT), wax disappearance temperature, obtained at thermobaric conditions. The reliability of such models depends on the accuracy of determination of oil properties, as well as the influence of various external factors on these properties such as mechanical impurities, water cut, content of paraffin, resins, asphaltenes, gas. Many studies have been conducted on oil and paraffin solutions on this subject (e.g., Pedersen et al. 1991; Wu et al. 2002). Brown et al. (1994) have shown that WAT for live oil increases with increase in pressure, for a constant composition. Li and Gong (2010) have shown, using viscometry under high pressure, that WAT of waxy degassed crude oil linearly increases with increase in pressure. Therefore, in experimental studies of solid organic precipitation increasing conditions in reservoir oils are simulated. Depth determination of early organic deposition allows a reasonable choice of down-the-hole treatment technology for the most appropriate method to control the problems mentioned above. Nowadays, the most producible methods of controlling any clogging problems in tubing are well handling and chemical treatments (Cimino et al. 1995; Machado et al. 2001; Pedersen and Rønningsen 2003; Wang et al. 2003). The objective of this research is depth determination of wax precipitation in the well via simu-
I. A. Struchkov and M. K. Rogachev lation of thermobaric operation conditions depending on the well operating practices. This research is conducted based on the light-scattering method and microscopy under high pressure with particle-size analysis. The results obtained can give useful data for revision and improvement of the paraffin deposition models.
LABORATORY APPARATUS, FLUID SAMPLE, AND MEASUREMENT PROCEDURES Laboratory Apparatus Experiments were conducted via laboratory setup intended for studying the formation of solid organic particles in reservoir fluid with modeling of thermobaric conditions as close as possible to borehole. Figure 1 shows the connection of the experiment devices. The setup consists of the following main components:
Figure 1. Schematic diagram of the experimental system. P pump, V valve, A, B, C connection points of the external equipment.
Wax Precipitation in Oil Well 1. The PVT (pressure, volume, temperature) cell of a solid detection system (SDS) – a cell of the laser solid detection system, which contained a light transmitter, a detector, and a magnetic stirrer for agitating the test fluid to accelerate the equilibrium process. The operation temperature range of the PVT cell was between 293 and 473 K and the maximum operation pressure was 69 MPa. The minimum volume of the studied oil sample (using only SDS PVT cell) was 30 ml, while the maximum (using both cells) was 60 ml. 2. The high-pressure microscope (HPM) cell – a cell with two sapphire glasses between which the test fluid circulated. Visualization of the appearance of solid particles was carried out by way of the HPM. 3. Pumps—these include a main pump (P1) that was used to remove the oil sample from a sampler to the SDS PVT cell and to operating pressure maintenance inside the cell, pump (P3) that was used to set pressure maintenance inside the sampler, and a recirculating pump (P2) that was used to the test fluid pumping-over the system. The recirculating pump (P2) with bulk volume of 500 ml provided flowing circulation of oil sample on close-loop (from PVT cell to HMP to PVT) with required flow velocity through 1/8¢¢ tubes. Flow velocity changes during laboratory experiments were performed with a set of estimated values of the pump delivery rate (P2), which took values from 7 to 2 ml/min for modeling of flow velocity in the oil well with 2 3/8¢¢ tubing, corresponding to 60–20 m3 per day, accordingly. The working temperature of the experimental system was maintained by the air bath placed inside all the devices. All measured data (pressure, volume, temperature, micrographs, light transmittance power) were followed by computer-based recording. There are many modern research methods used to measure WAT of oil (Kok et al. 1996; Elsharkawy et al. 2000; Karan et al. 2000; Jiang et al. 2001; Paso et al. 2009; Jiang et al. 2014), among which are the light-scattering method (in near infrared region) and microscopy under high pressure with particle-size analysis, allowing direct visual observations of phase changes in the test fluid. These methods, which are
69 becoming industrial standards, allow carrying out investigations without live oil property changes. The above-mentioned techniques were used in this study. The combination of the two independent methods allows obtaining qualitative and quantitative information on size and amount of solid particles, to define conditions of wax precipitation in the oil sample. The advantages of the above-mentioned methods are (a) small duration of the experiment; (b) small monophase reservoir fluid amount is required for the experiment; and (c) visual observations of the deposition process.
Sample Properties Gas-bearing oil sampled in the well with downhole sampler and delivered to laboratory at controlled pressure and temperature of sampling depth was used in all experiments. The live oil sample has an API (American Petroleum Institute) gravity of 38.2, a wax content of 4.9 %, gas/oil ratio of about 38.7 m3/m3, and saturation pressure of 3.9 MPa. The influences of asphaltenes on precipitation process have been considered by Struchkov and Rogachev (2014) by carrying out an experiment under isothermal pressure depletion from reservoir pressure to wellhead pressure and reservoir temperature. This experiment showed that asphaltene precipitation in the oil sample began under a pressure of 3.9 MPa. In this present study, heavy organic composition of oil was measured by SARA (saturates, aromatics, resins, asphaltenes) analysis. This method divides degassed crude oil components according to their polarity. The basic oil properties are given in Table 1.
Measurement Procedures The sampler with the live oil sample was heated by a heating jacket to temperature of 353 K at constant reservoir pressure maintained by the pump P3. Zero flow of the pump P3 indicated that thermal expansion of oil in the sampler stopped. Then, the oil sample was kept at reservoir temperature for 6 h. The oil sample was constantly agitated by the ball mounted inside the sampler. The laboratory equipment was vacuumed and heated to reservoir temperature. Then, nitrogen was injected into all lines of the unit and pressure of the working chambers was
I. A. Struchkov and M. K. Rogachev
70 Table 1. Properties of the live oil sample Gravity (API) SARA test results Wax content (wt%) Asphaltene content (wt%) Resin content (wt%) Gas/oil ratio (m3/m3) Bubble point pressure (MPa) The freezing point in normal pressure (K) Other properties Reservoir temperature (K) Reservoir pressure (MPa) Sampling depth (m) Water cut (wt%)
Table 2. Conditions of carrying out experiment at simulated flow velocity for flowrate of 60 m3 per day 38.2 4.9 1.5 4.7 38.7 3.9 264 320.5 18.4 1800 0
increased to reservoir pressure with the use of gas booster. Approximately, 50 ml of oil was injected into the SDS PVT cell at reservoir conditions by P1 and P3 pumps. Then, nitrogen and 20 ml of the oil sample were bled slowly with the valve V6 while pressure of the unit was maintained at reservoir pressure. The magnetic stirrer and the recirculating pump were activated. The homogenization process of the test fluid was performed for 12 h. Then, the experiment was carried out. Flow velocity and rate of pressure and temperature drop were simulated for each well operation conditions. After each experiment, the unit was cleaned with solvent and bled with compressed dry air.
RESULTS AND DISCUSSION Cloud Point of the Live Oil at Simulated Flow Velocity for Flowrate of 60 m3 per day Calculation of thermobaric well operation conditions was performed for a range of flowrates of 20– 60 m3 per day (flowrates at which paraffin precipitates out of oil in the well) according to which laboratory studies were made. The Poettmann– Carpenter method (Szilas 2010) and the equations describing wellbore heat transmission (Hagoort 2004) were used for computations. Based on data about tubing diameter and well flowrates, the average flow velocity in the well and flow through time from downhole to wellhead were calculated. The obtained data were accepted at laboratory modeling as flow velocity (recirculation speed) and duration of the experiment, respectively. Taking into account well depth and well flowrates, temperature and
Cooling rate (K/min) Pressure drop rate (MPa/min) Flow velocity (m/s)
0.18 0.11 0.23
pressure drop rates in the well for each simulated operation conditions were determined. These parameters were also considered in laboratory modeling. Conditions of carrying out this experiment are presented in Table 2. The software of the experimental system, which carried out the grain size analysis based on the recorded micrographs, allowed to determine the sizes and quantity of solid organic particles formed in oil. Calculation of the particles quantity was performed for definition of an initial stage of the solid paraffin formation in the oil sample representing the snowballing process similar to domino effect. The test results, presented in Figure 2, clearly show that the two independent methods (the light-scattering method and microscopy under high pressure) demonstrate similar results. The graphs show dependencies of quantity of solid organic particles in an oil sample (HPM data) and light transmittance power (SDS data) on temperature. Figure 3 shows dependencies of the average size of solid organic particles in an oil sample and light transmittance power on temperature. The obtained data demonstrate that quantity and size growth of solid paraffin particles in the live oil sample (produced by microscopy under high pressure) were observed at pressure of 4.8 MPa and temperature of 309.1 K, which correspond to depth of 700 meters (according to well operation conditions). The data conform to visual appearance of the first solid paraffin particles and slow reduction of light transmittance power (produced by the lightscattering technique) through the sample (Figs. 1, 2) as a result of light dispersion by the particles surface. However, when the operating temperature was reduced to 308 K (below cloud point), the light transmittance decreased sharply, indicating that wax precipitation has occurred during this test. The micrograph obtained by microscopy under high pressure (Fig. 4) shows liberation of the first bubbles from the oil sample at pressure of 3.9 MPa. This suggests that the solid phase formed in the oil at above the bubble point pressure introduced by wax. Small particle count detected by the particle-size analysis at temperature above the cloud point is
Wax Precipitation in Oil Well SDS
6.0E-04
1300 1200
5.0E-04
1100 1000
4.0E-04
900 800
3.0E-04
700 600
2.0E-04 306
311
316 Temperature, K
321
Average particle size (um²)
235 6.0E-04
230 225
5.0E-04
220 4.0E-04
215 210
3.0E-04
205 200
Light transmittance power (mW)
SDS 7.0E-04
2.0E-04 311
316 Temperature, K
y = 958,95ln(x) - 5492,9 R² = 0,946 6
4 309.0
309.5 0.23 m/sec
240
306
8
326
Figure 2. Light transmittance power and particle count versus temperature.
HPM
10 Pressure, MPa
1400
Particle count
12
7.0E-04 Light transmittance power (mW)
HPM
1500
71
321
326
Figure 3. Light transmittance power and average particle size versus temperature.
310.0 310.5 Temperature, K 0.19 m/sec
0.15 m/sec
311.0 0.11 m/sec
311.5 0.07 m/sec
Figure 5. Pressure versus WAT of the live oil sample according to simulated flow velocities.
Cloud Point of the Live Oil at Different Operation Conditions Thermobaric well operation conditions data were calculated for five simulated flow velocities, according to which studies of solid paraffin particles formation conditions in the live oil sample were carried out. The experimental results are illustrated in Figure 5. Figure 5 shows the relationship between pressure and WAT of the live oil sample according to simulated flow velocities. From Figure 5, it can be seen that as pressure decreases the WAT of oil decreases, with increasing flow velocity. In Paso et al. (2009), WAT decreases with increasing cooling rate; this phenomenon was attributed to the different kinetics of paraffin nucleation and crystallization. In this present experimental study, the data obtained are completely supported by the Clapeyron–Clausius equation, describing first-order phase transitions (Sharma 2001) to which paraffin crystallization in oil belongs dP DH ; ¼ dT T V20 V10
Figure 4. Micrograph of the oil sample at thermobaric conditions (temperature 308 K, pressure 3.9 MPa).
related to the presence of water droplets and any mechanical impurities in the oil. Further pressure decrease below 3.9 MPa and temperature decrease below 308 K lead to the formation of complex asphaltene–resin–paraffin particles, compounding the base of a gel pattern.
where DH is enthalpy of paraffin crystallization, V20 and V10 are specific volumes of liquid and solid phases, respectively. During paraffin crystallization in oil, the volume of the studied system decreases so that dP [0;i.e., pressure increase induces increase in dT paraffin saturation point showing agreement with data from our experiments. In the assembled equation of the first and second laws of thermodynamics, the difference of Gibbs energy (DG) at paraffin crystallization in oil will take the following form:
I. A. Struchkov and M. K. Rogachev
72 DG ¼ DH TDS: The driving force (DG) of the paraffin crystallization in oil linearly increases with increase in pressure (by analogy with crystallization of metal fusion), which demonstrates the creation of more favorable thermodynamic conditions for initiation of the solid phase formation. Thus, early crystallization of paraffin (at higher temperature) with pressure rise is related to increase in regularity of system, i.e., reduction in its entropy, increase in density of packing of paraffin molecules in oil, and decrease in length of their free path that amplifies influence of the diffusive process defining the crystallization mechanism.
CALCULATION OF WAX FORMATION DEPTH AT DIFFERENT OPERATION CONDITIONS The conditions of solid paraffin particles formation (from Fig. 5) caused by the laboratory experiments were recalculated to well depth. For the individual well operation conditions, certain values of pressure and temperature correspond to each well point. Knowing tubing diameter and flow velocity, it is possible to correlate pressure and temperature to well depth on the basis of the Poetman–Carpenter method and the equations describing wellbore heat transmission. Figure 6 illustrates data for the relationship between solid paraffin particles formation depth and WAT according to simulated flow velocities. It is apparent that the formation depth of solid paraffin particles moves in a direction to the wellhead with increasing flow velocity.
309.0 700
309.5
Temperature, K 310.0 310.5
311.0
311.5
750 Depth, m
800 850 900
y = 195,8x - 59800 R² = 0,983
950
Simulation of the potential well operation conditions has shown the inevitable formation of solid paraffin particles in the tubing. One of the most common and producible methods of organic deposition control in a well is chemical treatment. It has been demonstrated in previous studies that the produced nonionic surfactant, which is the reaction product of unsaturated fatty acids and complex ethyleneamines, hydroxyl amines (an active base) in an organic solvent, has an inhibiting effect on the organic compounds of the live oil sample in downhole conditions. Continuous injection of the mentioned surfactant or its analog to the analyzed well in the depth range from 1150 to 1200 m, where formation of asphaltene–resin–paraffin particles has not been observed yet, is implied by the results of the laboratory investigations. The chosen injection method causes smaller surfactant consumption in comparison with conventional dosing in well annulus. Based on the results obtained, it is possible to assume that an increase in well flowrate within the considered range of operating conditions will lead to a decrease in paraffin saturation point in the well and will bring closer a probable interval of solid organic particle formation in tubing to the wellhead.
CONCLUSIONS The impact of cooling rate and pressure drop upon paraffin saturation point in the range of oil well flowrates was defined in this study. By a combination of experimental studies and calculations, it was determined that the depth of formation of solid paraffin particles decreases, on average 200 meters, with increase in flowrates by 20 m3 per day (equivalent to a flow velocity of 0.04 m/s). Increase in paraffin saturation point with increase in pressure is noticed. This phenomenon is due to change in macrocondition of the system, consolidation of paraffin hydrocarbons packing in oil. The derived correlation can be applied to the prediction of solid paraffin particles build-up during oil production. The results of this study will be useful for planning actions to prevent or remediate organic deposits in wells.
1000 1050 1100 1150
ACKNOWLEDGMENTS 0.23 m/sec
0.19 m/sec
0.15 m/sec
0.11 m/sec
0.07 m/sec
Figure 6. Formation depth of solid paraffin particles versus WAT according to simulated flow velocities.
We acknowledge Dr. A.V. Petukhov for his assistance during the experiments. Finally, we would
Wax Precipitation in Oil Well like to thank Saint-Petersburg Mining University (Saint Petersburg, the Russian Federation) for providing laboratory equipment support and samples for this research.
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