THE HYDRATE PLUGGING TENDENCY OF CRUDE-OILS AS DETERMINED BY USING HIGH PRESSURE ELECTRICAL CONDUCTIVITY AND TRANSPARENT HYDRATE ROCKING CELL TESTS

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1 Proceedings of the 7th International Conference on Gas Hydrates (ICGH 11), Edinburgh, Scotland, United Kingdom, July 17-21, 11. THE HYDRATE PLUGGING TENDENCY OF CRUDE-OILS AS DETERMINED BY USING HIGH PRESSURE ELECTRICAL CONDUCTIVITY AND TRANSPARENT HYDRATE ROCKING CELL TESTS Arvind Gupta Shell Global Solutions International B.V. Shell Technology Center Amsterdam Grasweg 31, 131 HW, Amsterdam THE NETHERLANDS Daniel Crosby, James Guillory Shell International Exploration and Production Westhollow Technology Center, 3333 Highway 6 South, Houston, TX, UNITED STATES OF AMERICA ABSTRACT It is suggested that naturally occurring components in some crude oils can prevent the agglomeration of hydrate crystals into larger pipeline blocking hydrate masses. If they exist, it is likely that these components will behave similar to synthetic hydrate Anti-Agglomerants (AA) that keep hydrate particles dispersed in the oil-phase, thereby preventing hydrate plug formation. In this paper, the term HyPRO (Hydrate Plug Resistant Oil) is used instead of commonly employed terms such as Magic Oil or Non-Plugging crude oils. In 7, Shell constructed a stirred high-pressure cell to study the inversion of oil/water mixtures before, during and after the formation of hydrates via a continuous measurement of electrical conductivity. Three out of the sixteen crude oils that were studied by using this equipment, exhibited the phase inversion behavior that is expected during the formation of oil-wetting hydrates. Highpressure experiments involving transparent rocking cells were also conducted to observe the plugging tendency of the formed hydrate particles. The water-cut and salt content were systematically varied in these tests. The plugging behavior as observed in the visual tests agrees well with the high-pressure electrical conductivity data. The rocking cell data indicates that the natural agglomeration of hydrates is only prevented up to a maximum hydrate-cut (not necessarily equal to water-cut) of vol% (no salt) for one of the HyPROs identified in this work. It is inferred here that this is because a given volume of crude contains a fixed amount of natural components that can only prevent the agglomeration of a fixed maximum amount of hydrates. For HyPROs, the hydrate inhibitor rate can either be eliminated or reduced. Therefore, crude-oil plugging tendency can significantly reduce hydrate control costs. Keywords: Hydrate Plug Resistant Oil (HyPRO), Non-Plugging Crude Oil, Phase-Inversion, Natural Anti- Agglomerants, Emulsion INTRODUCTION Many facilities used for the production, transportation and processing of oil and gas (such as wells, subsea pipelines, slug-catchers and separators, etc.) operate at pressures and temperatures at which natural gas hydrates can form. To ensure continuous hydrocarbon production, it is important to prevent hydrate plug formation, both during steady-state and transient operations. Hydrate plug prevention is of crucial importance in existing and future fields. Amongst the Corresponding author: Phone: Fax Arvind.Gupta@Shell.com

2 prevention techniques available, the injection of chemicals in the production stream is commonly applied to prevent hydrate blockages. Which type of chemical is preferred depends on many variables. Examples are: a) the fluid composition, b) the amount of produced water, c) the hydratesubcooling, d) the local availability of chemicals, e) environmental regulations and f) chemical cost. Hydrate prevention methods often require significant capital and operational expenditure. Therefore, it is important to develop hydrate prevention and management strategies which minimize hydrate formation risk at reduced cost. So-called magic crudes or non-plugging oils hereafter referred to as Hydrate Plug Resistant Oils (HyPROs), have captured the interest of the oil industry at least since the 199 s. It is suggested that components that naturally occur in these crude oils prevent the agglomeration of hydrate crystals into larger hydrate masses that can block a pipeline. Typically, Thermodynamic Hydrate Inhibitors (THI), such as MEG/MeOH and Low Dosage Hydrate Inhibitors (LDHI), such as KHI/AA are injected in process facilities to prevent hydrate formation. It is envisaged that the hydrate inhibitor injection rate can either be eliminated or reduced during the production of HyPROs. Therefore, information about the crude-oil plugging tendency can reduce hydrate inhibitor cost. In addition, if we can isolate the root cause of HyPRO behavior, then we may be able to develop more cost effective anti-agglomerants to control hydrates in non-hypros. However, despite more than 1 years of active research into HyPRO sources and behaviors, not a single theory stands out as unambiguously and universally relating HyPRO composition to HyPRO behavior. From the beginning, the root cause of HyPRO behavior is thought to be caused by yet unidentified heteroatom components in black oils (there are no known gas condensate HyPROs). There are however, diverging views on whether HyPROs are the primary result of asphaltenes or species such as organic [naphthenic] acids that interact directly with formed hydrate surfaces much like a synthetic AA (the dividing line between resins, large organic acids and asphaltenes is not necessarily clear-cut). Both views are qualitatively able to explain the origins of some HyPRO oils, but not all. For example, biodegradation is a determining parameter for those who promote organic acids as the root active (also called natural inhibiting components (NIC s) in the literature) in HyPROs. There are even strong statements in the literature that all HyPROs should be biodegraded in order to form the necessary organic acids. Yet Shell has identified non-biodegraded HyPROs in the Gulf of Mexico (GoM). There are attempts to combine aspects from both camps in the open literature. Such is the inference in a paper by the University of Bergen [1], which relates HyPRO behavior to the asphaltene content and TAN value as well as biodegradation and density. Some statements and claims made regarding to or connected to HyPRO s (or emulsions) in the open literature include: HyPROs must form a stable W/O emulsion [2] Salt and alkalines (i.e. high ph) decrease the induction time, increase the hydrate growth rate and decrease HyPRO performance as compared to fresh water [3] Suggestions that cyclic lipopeptides act as NIC s [4] The possibility that phenolic species promote hydrate agglomeration [] Plugging potential of HyPRO crudes increases after removing the acidic compounds [6] The determination that stable O/W emulsions are promoted by Naphthenates (RCOO - ) whereas W/O emulsions are due to amphiphiles (asphaltenes & resins) [7] Detailed explanations on the above statements are found in the respective references. The primary objective of the present work is to develop experimental means to determine whether a crudeoil is a HyPRO or not. In the present study, no attempts are made to identify the components in HyPROs that prevent hydrate particle agglomeration. EXPERIMENTAL METHODS AND RESULTS Two types of experiments are used to determine the hydrate plugging tendency of crude-oils. These experiments are complimentary to each other. A total of 16 crude oils were tested in this study. The

3 HyPRO s are labelled from B1 to B3 and the non- HyPRO s are labelled from A1 to A13. High-Pressure Electrical Conductivity Test For a water/oil mixture, the phase-inversion point is defined as the water-cut (defined as the volume fraction of water, based on the total volume of oil and water present) at which an oil-continuous (W/O) emulsion changes either to a watercontinuous (O/W) emulsion or to an oilcontinuous emulsion (W/O) plus an underlying free water phase. The basic reasoning behind the electrical conductivity test is that the formation of hydrate particles in an oil/water mixture mostly shifts the phase inversion point [8]. In, Høiland and co-workers reported that if an oil is HyPRO, there exists a water-cut at which the live oil/water mixture changes from water-continuous to oil-continuous at the onset of hydrate formation. Vice versa, if an oil is not HyPRO, there exists a water cut at which the live oil/water mixture changes from oil-continuous to water-continuous at the onset of hydrate formation. In 7, Shell constructed a stirred high-pressure conductivity cell allowing the continuous measurement of the electrical conductivity of agitated oil/water mixtures before, during and after the formation of the first hydrates. This equipment is especially suitable for the determination of changes of the continuous phase due to the formation of hydrates. The cell pressure, conductivity and temperature are continuously measured during the entire experiment to determine whether and when a phase-inversion occurs. Testing involves determining the phase inversion point shifts for a suite of oil/water mixtures at different water cuts. For example, 118 cm 3 of a brine containing.1 wt% of salt and.6 cm 3 of A12 crude oil were transferred into the conductivity cell to achieve a 7 v% water-cut. The remaining cm 3 of the cell volume was occupied by a pressurized synthetic gas. The ratio between the gas and the oil volumes was kept constant at 2. cm 3 /cm 3 in all the conductivity experiments to ensure a similar thermodynamic driving force for hydrate formation. Figure 1 shows typical pressure, temperature and conductivity data obtained during a high-pressure conductivity test. The brine and A12 oil were transferred into the high-pressure cell at room temperature after which the cell was pressurized with the synthetic gas to 81 bar[a] at 24 o C. After pressurization, the live oil/water mixture was first continuously stirred at rpm at a constant temperature of 24 o C during to obtain a stable emulsion phase (or stable conductivity values) in the absence of hydrates. After hours, hydrate formation was induced by linearly cooling the mixture temperature to 2 o C in 2 hours. Thereafter, the bath temperature was held constant at 2 o C for 2 hours to ensure sufficient hydrate formation. Finally, the mixture temperature was linearly increased to 24 o C in 2 hours to confirm the presence of hydrates. Figure 1 shows that the live oil/water mixture was oil-continuous (conductivity value is practically zero) in the absence of hydrates. However, the conductivity became positive at the onset of hydrate formation as indicated by a transient increase of the cell temperature accompanied by a sharp decline of the (fixed-volume) cell pressure. This data suggest that the crude oil is a not a HyPRO because the presence of hydrate particles destabilize the stable W/O emulsion leading to the appearance of a water-continuous emulsion or a free water phase. pressure, [barg] / Conductivity, [us/cm] v% A12 oil with 7 %v water (.1 %w NaCl) Free water plus W/O emulsion Onset of hydrate formation W/O emulsion time, [hours] Pressure Conductivity temp cell Figure 1: Measured pressure, electrical conductivity and temperature data for the 7 v% water / A12 oil mixture. The zero and positive conductivity values correspond to oil-continuous (W/O) and free water plus oil-continuous (W/O) mixture, respectively. It is not understood at this time why the conductivity increased during the heating cycle and the live oil/water mixture did again become oil-continuous after all the hydrates had dissociated. 1 temperature, [C]

4 The experiment described above was then repeated, after dosing the mixture with a commercially available synthetic Anti- Agglomerant (AA). Figure 2 shows that the conductivity went from a positive value to zero at the onset of hydrate formation. This behavior is expected for a HyPRO. It is commonly accepted that an AA adheres to the hydrate particles and changes the hydrate surface behavior from waterwetting to oil-wetting. Most importantly, the hydrate particles increases the W/O phase inversion point in the presence of synthetic AA. This data suggests that a HyPRO will behave similarly if it contains some natural AA type components. Pressure, [barg] / Conductivity, [us/cm] v% A12 oil with 7 %v water (.1 %w NaCl) and. %w AA Free water plus W/O emulsion Onset of hydrate formation time, [hours] Pressure Conductivity Temp. W/O emulsion Figure 2: Measured pressure, electrical conductivity and temperature data for the 7 v% water / A12 oil mixture in the presence of. w% synthetic AA. The zero and positive conductivity values correspond to oil-continuous (W/O) and free water plus oil - continuous mixture (W/O), respectively. Figure 3 shows a experiment where the conductivity went from a positive value to zero at the onset of hydrate formation for a HyPRO crude oil labeled as B3. The conductivity behavior is similar to Figure 2 in which a synthetic AA was added to the A12 crude. This suggests that crude oil B3 contains components that cause the hydrate particles to be oil-wetting, similar to a synthetic AA. Table 1 shows an overview of the continuous phases at different water-cuts for the crude-oils A12 and B3. The presence of hydrate particles decrease the W/O phase-inversion point for crudeoil A12 and increase the W/O phase-inversion point for crude-oil B Temperature, [C] Pressure, [barg] / Conductivity, [ms/cm] Free water + W/O emulsion %v HyPRO oil with 8 %v salt water (.1 %w NaCl) Onsetof hydrate formation time, [hours] W/O emulsion pressure conductivity temperature Figure 3: Measured pressure, electrical conductivity and temperature data for the 8 v% water / B3 oil mixture. The zero and positive conductivity values correspond to oil-continuous (W/O) and dispersed water plus oil-continuous (W/O) mixture, respectively. Similar data were collected for the other crude oils and in total three out of the sixteen crude-oils assessed were identified as HyPRO based on the phase-inversion data. Water/ Oil Ratio (v/v) Crude-Oil A12 (Non- HyPRO) Crude-Oil A12 + AA Crude-Oil B3 (HyPRO) Before After Before After Before After / O O 6/4 O O O O 6/3 O W O O O O 7/3 O W W O 8/ W W O O 8/ W W W O 9/1 W O Table 1: Results of the phase-inversion experiments conducted with crude-oil A12, A12 plus a synthetic AA and crude-oil B3. The table lists the continuous phase of the emulsions (O=oilcontinuous means W/O emulsion, W=watercontinuous means either an O/W emulsion or a W/O emulsion plus a free water phase) before and after hydrates were formed. Transparent Rocking Cell Testing The goal of transparent rocking cell (TRC) experiments is to visually observe whether the hydrates created in the cell form agglomerates. Such rocking cells are routinely used to test the anti-plug performance of synthetic AA s. In this study, the plugging behaviour of crude oils as observed in a TRC is compared with the results 1 Temperature, [C]

5 with the high-pressure electrical conductivity measurements. TRC tests are also used to determine the maximum water-cut at which a HyPRO does not form a plug. All TRC testing is performed in duplicate and rated as pass, marginal and fail according to the following criteria: Pass: In both tests: a) the ball is not frozen stuck by hydrates, b) no hydrate agglomerates are observed in the bulk fluids, c) no hydrates are sticking to the glass and d) no water is held back in the auxiliary tubing. Marginal: In both tests: a) the ball is not frozen stuck by hydrates, b) some loose smaller hydrate agglomerates are observed in the bulk fluids, but these are taken up in the oil phase during agitation, c) no hydrates are sticking to the glass and d) no water is held back in the auxiliary tubing. Fail: In both tests: a) the ball is frozen stuck by hydrates and/or, b) hydrate agglomerates that do not re-disperse in the bulk fluids during agitation are observed and/or, c) hydrates stick persistently to the glass and/or d) water is held back in the auxiliary tubing. Testing is either dynamic or static. Dynamic testing means that the cells are rocked while being cooled to 4 o C. The cells are then held stagnant in a horizontal position for 12 or more hours. Dynamic testing is used as a first screening for HyPRO behavior because it is inevitably quicker that static testing. Static testing means that the test cells are held stagnant in a horizontal position during the cool-down period and for at least 24 hours thereafter. All test gases were blends of methane, ethane, propane, carbon dioxide and nitrogen. These gas blends are composed to mimic the live fluids produced from different Shell GoM assets and create Structure II hydrates under the designed test conditions as determined by Multiflash 3.6. The HyPROs that were identified from the phaseinversion tests were tested in the transparent rocking cells and the results confirmed that the crude oils that were identified as HYPRO s in the conductivity tests did not form hydrate plugs in the rocking cells. Additional rocking cell experiments were carried out with some non-hypro crudes. In this study, the HyPRO crude B3 was subjected to the most extensive test program and is thus the focus of this paper. This is because Shell intends to field implement HyPRO concept in the GoM asset that produces the B3 crude in the near future. Other tested Shell HyPROs display HyPRO relationships similar to B3. During the course of this study, the HyPRO behavior of oil B3 was tested in combination with 3 different gas blends, different brine compositions, 6 different water cuts, 1 different Gas Oil Ratios (GOR), 3 different gas pressures and at sub-coolings ranging from 7 to 16 o C. The dynamic test results for oil B3 are presented in Figure 4 below. The data suggest a linear or nearly linear relationship between the gmoles of Standard Tank Oil (STO) and gmoles of hydrate-able water as calculated by Multiflash 3.6. For B3, a fitted linear line passes nearly through the origin as demonstrated in Figure 4. It is our expectation that different HyPROs display different linear slopes and offsets. gmoles Hydrate-able water Pass boundary gmoles STO Fail (Plugs) Marginal Pass (Non-Plugging) Figure 4: The hydrate plugging tendency behaviour of HyPRO crude B3 expressed in gmoles of hydrate-able water and gmoles of Standard Tank Oil (STO). Of special interest are the three data points at. gmoles on the STO axis in Figure 4 (highlighted in the oval). The tests associated with these three data points were specially designed to bracket the fitted line as a proof of concept in Figure. The data indicates that the agglomeration of hydrates is only prevented up to maximal hydrate cuts of vol% (no salt). The water cut is equal to the hydrate cut for a no salt case when all the water converts into hydrate (here ignoring the density difference between hydrate and water). Due to the

6 salt-inhibiting effect, the 1 % water conversion into hydrates is not possible in a constant volume system. Therefore, the maximal water-cut at which agglomeration of hydrates is prevented will increase with salinity because of the decrease in water conversion to hydrates in a constant volume system. Figure shows that the water-cut increases up to 34 vol % in the presence of 14 wt% salt even though the hydrate cut remain constant at vol%. It is inferred here that this is because a given volume of crude-oil contains only enough natural components to prevent the agglomeration of a fixed amount of hydrates. From a practical point of view, the most important aspect of the linear relationship in Figure 4 is the ability to use the fitted curve to model a relationship between brine concentration and the maximum allowable water-cut in the field. This means that, beyond just establishing whether oil exhibits HyPRO properties, we can now quantify the serviceable water cut limitations of producing a HyPRO in the field before the need to intervene. Such an application is demonstrated in Figure. The curve in Figure is intended for use by field engineers who manage the production of HyPRO B3. Water-Cut HyPRO crude B3 water-cut and hydrate-cut 7 bara, 4 o C and Constant Gas-Oil Ratio System Does Not Plug Brine Salinity wt% (w/v) Calculated Water-cut Limit System Plugs Calculated hydrate-cut limit Figure : The water-cut boundary as a function of salinity up to which crude B3 shows HyPRO behaviour. The hydrate-cut remains constant with salinity for crude B3. Table 2 shows a good agreement between the phase inversion (conductivity) test and the rolling ball tests except for oil A8. The discrepancy between the two experimental methods is not understood Hydrate-Cut Is an oil HyPRO (Non-Plugging)? Number Label Conductivity test Visual Cell test 1 A1 No No 2 B1 Yes Yes 3 A2 No No 4 A3 No No data A4 No No data 6 A No No data 7 A6 No No data 8 B2 Yes Yes 9 A7 No No 1 B3 Yes Yes 11 A8 No Yes 12 A9 No No data 13 A1 No No data 14 A11 No No data A12 No No 16 A13 No No Not HyPRO (Plugging oil) HyPRO (Non-Plugging oil) Table 2: Comparison between the high-pressure conductivity and the transparent rocking cell tests In addition, we have established a simple relationship between the calculated moles of hydrate-able water and moles of STO. Once the hydrate - STO relationship is established, it is thought possible to model a field operation guide without having to retest whenever there is a production change. In addition, the given relationship strongly suggests that HyPRO behavior is related to a component or group of components in the oil itself. This correlates well with different existing theories regarding the source of HyPRO behavior. The work described in this paper is a start, but not the end of applying HyPROs in the field. Current and future work includes the impact of: Cooling rate Different salt components Different oil field additives including AAs Low salinity systems (< 3. wt% (w/v)) Different subsea temperatures CONCLUSIONS The main goal of the present work was to develop the experimental means to determine whether an oil is a HyPRO or not. Two complementary experimental methods are used to determine the plugging tendency of crude oils. The high-pressure conductivity measurement test set-up was

7 specially designed for the determination of changes in the continuous phase of oil/water emulsions due to the formation of hydrates. The data show that (amongst the limited group of oils tested) a crude oil for which the phase-inversion point increases due to the presence of hydrate particles also creates oil-wetting hydrate particles as determined in a rocking cell experiment. The reverse was not always true: crude A8 creates oilwetting hydrate particles in a rocking cell but these hydrates do not increase the phase inversion point. The plugging behavior as observed in the highpressure conductivity tests was in good agreement with the transparent rocking cell tests. Three out of the studied sixteen crude oils using this equipment, exhibited the phase inversion behavior expected during the formation of oil-wetting hydrates. The rocking cell data indicate that the agglomeration of hydrates is only prevented up to a maximum hydrate cut (not necessarily equal to water-cut) of v% (no salt) for one of the HyPROs tested in this work. The maximum watercut limit increases with increasing salinity in a constant volume system. It is inferred here that this is because a given volume of crude contains only enough natural components to prevent the agglomeration of a fixed amount of hydrates and that therefore the HyPRO becomes plugging at higher water-cuts. Additional flow-loop testing at field-conditions (i.e. hydrate subcooling, salinity, GOR, etc.) are planned for the HyPRO s identified in the present work. The goal of these flow-loop tests will be to assess the plugging behavior of the HyPRO s during steady-state, shut-in and restart situations. [2] Palermo, T., Mussumeci A., Leporcher E., Could Hydrate Plugging Be Avoided Because of Surfactant Properties of the Crude and Appropriate Flow Conditions? Proceedings of the Offshore Technical Conference, 4, TX, Houston, OTC [3] Sinquin A., Arla D., Prioux C., Peytavy JL., Glenat P., Dicharry C., Gas Hydrate Formation and Transport in an Acidic Crude Oil: Influence of Salt and ph, Energy & Fuels, 8, 22, [4] Borgund AE., Høiland S., Bart T., Fotland P., Askvik KM., Molecular analysis of petroleum derived compounds that adsorb onto gas hydrates, Applied Geochemistry, 9, 24 (), [] Borgund AE., Erstad K., Barth T., Fractionation of Crude Oil Acids by HPLC and Characterization of Their Properties and Effects on Gas Hydrate Surfaces, Energy & Fuels, 7, 21, [6] Hemmingsen P., Li X., Peytavy JL., Sϳӧblom J., Hydrate Plugging Potential of Original and Modified Crude Oils, Journal of Dispersion Science and Technology, 7, 28 (3), [7] Arla D., Sinquin A., Palermo T., Hurtevent C., Graciaa A., Dicharry C., Influence of ph and Water Content on the Type and Stability of Acidic Crude Oil Emulsions, Energy & Fuels, 7, 21(3), [8] Høiland S., Askvik KM., Fotland P., Alagic E., Barth T. and Fadnes F., Wettability of Freon Hydrates in crude oil/ brine emulsions. Journal of Colloid and Interface Science ; 287: ACKNOWLEDGEMENT The authors really appreciated the input received from Dr. Ulfert Klomp and Dr. Greg Hatton. Thanks to Bill Nisbet for sponsoring this project and to Rien Oskam for carrying-out the experiments. REFERENCES [1] Aspens G., Høiland S., Borgund, AE., Barth, T., Wettability of Petroleum Pipelines: Influence of Crude Oil and Pipeline Material in Relation to Hydrate Deposition, Energy & Fuels, 1, 24,