Article Cite This: Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX
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Constitutionally Dynamic Oil Well Construction Fluids−Metalloaminal Chemistry Peter J. Boul,* Diana Rasner, and Carl J. Thaemlitz
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Aramco Research Center, Houston, Texas 77084, United States ABSTRACT: Completion fluids which are designed to build viscosity or form reversible gels suffer from performance limitations due to thermal degradation of the fluids at the high temperature conditions of many oil and gas wells. The hemiaminal/aminal metallogel system reported in this paper demonstrates the possibility of performance without degradation at temperatures up to 150 °C and pressures up to 60 MPa. The chemical system is also demonstrated to be reversible under stimulated well conditions whereby the thermodynamically favored metallogel can be broken within a sandstone core sample pressurized at 3.4 MPa and held at 70 °C. These findings demonstrate the suitability of this reversibly covalent chemical system as a highperformance completion fluid for such operations as perforations and workovers.
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fluids can be channeled to the surface of the well. One of the difficulties in perforations is that because perforation operations require the use of high energy jets from explosive charges to penetrate the casing, the surrounding cement and the reservoir rock formation can be substantially fractured. Fine and coarse debris particles are often produced from the shattered cement and rock formation of the reservoir. This debris is known to erode downhole well equipment and can ultimately plug and shut off fluid flow. Fluids used when perforating are designed to prevent debris from degrading well equipment and limiting production. These fluids are usually brines which are weighted by the concentration of salt within the aqueous fluid. The salts range from potassium formate and calcium bromide to cesium formate depending on the fluid density sought as well as economic considerations. During the perforation event, the brines can often leak into the formation along with debris and sand if the hydrostatic head of the fluid is greater than the pore pressure of the reservoir rock (a situation referred to as “overbalanced”). The density of the brines is often chosen to be overbalanced to prevent pore fluids from entering the wellbore during well construction operations. Since this situation can lead to losses of fluid into the formation, a secondary fluid typically referred to as a fluid-loss control pill, or kill pill, is often placed across the perforated interval to seal the perforations against further losses which incur blockages through particle plugging and reaction with clays when present in the formation. This prevents the desired passage of oil and gas from the formation.7 In other well-bore cleaning
INTRODUCTION The precise control of fluid rheologies and liquid−solid phase transitions underlie the chemical foundation for safe and effective oil well construction, production, cleaning, and remediation. Constitutionally dynamic materials (CDMs) in wellbore operations offer the possibility to broaden the performance window of many upstream chemical processes in the oil and gas industry including oil well completions where the remote control of material phase behavior is of particular value. Materials that are constitutionally dynamic utilize reversible covalent and/or noncovalent bonding such that the material may undergo changes to its constitution through the dissociation and reassociation of its constituent building blocks.1 These attributes unlock a wide variety of possibilities for instructing chemical transformations through controlled triggered additive release,2 reversible gelling fluids,3 and selfhealing polymer composites.4 Materials with these features show promise in the oil field where smart materials and the possibility of remotely controlled chemical transformations are of substantial benefit. In this Article we use the dynamic chemistry reported by Boul et al.5 to demonstrate phase change under simulated well conditions of high pressure and temperature. The technology is currently targeted for use in oil well completion operations. Well completion refers to the operations after drilling operations but before production. This stage in operations involves well construction and preparation of the well for oil/ gas production.6 It includes some chemically intensive procedures as well cleaning (workover fluids) and the use of completion fluids to control fine and coarse particle migration from cement and formation. Wells are perforated to provide a passageway through the liner casing for oil and/or gas to flow from the reservoir into the production tubing. After perforation, the crude produced © XXXX American Chemical Society
Received: Revised: Accepted: Published: A
August 21, 2018 November 20, 2018 November 21, 2018 November 21, 2018 DOI: 10.1021/acs.iecr.8b04019 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX
Article
Industrial & Engineering Chemistry Research applications, kill pills can be used in situations where oil production is stopped to clean selected well zones from debris and particles limiting production. These treatments are always temporary, and all fluids and gels must be removed after cleanup operations are completed. A reversible gelling system is sought for these purposes. The use of reversible gelling systems to achieve these ends as reversible plugging agents have been realized with several different kinds of chemistries. They can be either aqueous based or organic/oil-based.8 Some reversible viscosifying systems are simply a combination of a viscosifying agent, such as xanthan gum, modified starch, and water with a weighting salt, and laden with calcium carbonate particles of tuned diameter distributions to reversibly plug pores in a formation. When appropriately formulated in potassium formate brines, these formulations have been found to be stable at up to 165 °C.9 However, it is known that the use of calcium carbonate particles to plug formations can lead to irreversible formation damage, limiting production efficiency. Furthermore, it is known that xanthan gum itself causes formation damage by filling pore space in the formation and degrading, albeit very slowly. The use of other polysaccharides is found to be more limiting in terms of thermal stability. The use of guar gum in these kinds of fluids is stable to only about 90 °C and contains solid contaminants (bean shell form solids) which plug formations. Viscoelastic surfactants (VES), such as betaines, have been tested as gelling agents; however, they have a maximum temperature stability of 150 °C.10 It is therefore more desirable to use a material that produces a stronger gel and that breaks cleanly after the introduction of a breaker or through preprogrammed self-destruction. Cross-linking organic materials with transition metals such as zirconium, chromium, or titanium has been sought for these purposes; however, these fluids/gels also are limited to applications below 150 °C.11 Supramolecular gels based on low-molecular-weight-gelators (LMWGs) have been suggested for use for oil spill remediation.12 Supramolecular polymer gelators have been suggested including cyclodextrin-based supramolecular gels with a gel point temperature of 90 °C and a reversal temperature of 110 °C.13 The difficulty with these materials is inherent to their design. They cannot be used in well sections exceeding 90 °C. Higher temperature gelators are sought for the broader demand of oil wells across different fields. Exploration in the red sea has opened a multitude of opportunities in well construction for reservoirs exceeding 140 °C. Cross-linked polyacrylamide and poly(vinyl alcohol) systems have been reported to produce gels stable at up to 180 and 200 °C, respectively; however, these gel systems are not designed to be reversible.14 They can therefore only be used as permanent modifications to oil wells such as for abandonment of perforated sections in wells or for water shutoff/conformance control. In this paper, the hemiaminal/aminal metallogel system reported previously5 (Scheme 1) is further examined for gelation times under simulated wellbore conditions at elevated pressure and temperature. The reversion of the thermodynamically favored metallogels is described under elevated pressure and temperature, through a core flooding procedure with high permeability sandstone cores. The metallogels are transformed into liquid through the addition of an organophosphine, tris(2carboxyethyl)phosphine (TCEP). The phase transformation, or “breaking” of the gels, is demonstrated herein with specialized core-flood equipment used in oil field testing. It
Scheme 1. Condensation of a Functionalized Amine Where the R-NH2 Group Corresponds to an Alkylene Glycol Triaminea
a
The different products are denoted by letters A, B, C, and D and correspond to different chemical structures and material phases.
is also demonstrated that these materials can be weighted with salt to match density requirements of fluids within the well.
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EXPERIMENTAL SECTION Instrument Description. Shear modulus rheological measurements were performed on a Grace M5600 HPHT rheometer with a circulating oil bath heater and pressurized with nitrogen to 3.4 MPa. Rotational rheological measurements were performed on a Fann i-X77 rheometer, pressurized with Fann hydraulic fluid to a variable testing pressure range between 20 and 60 MPa. A stable temperature of 70 °C is maintained via an electric resistance heater inside the heating well where the sample cell is placed during testing. Gel permeability tests were performed using a Grace M9100 HPHT Automatic Core Flow Tester with built-in heaters. Flow and pressurization of tested fluids were controlled with a Teledyne ISCO D-Series pump. Hemiaminal (Kinetic) Gel Preparation Procedure. NMethylpyrrolidone (NMP) and paraformaldehyde (in the proportions described in Table 1) are mixed together at 70 °C in an oil bath on a heated stir plate for 30 min. A polyoxypropylene triamine with a molecular weight of 5 kDa (Jeffamine T-5000 from Huntsman Corporation) was then added to the mixture and allowed to continue to stir at 70 °C for another 30 min. The pH of the product of this reaction was B
DOI: 10.1021/acs.iecr.8b04019 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX
Article
Industrial & Engineering Chemistry Research Table 1. Gel and Liquid Formulations with NMP material
weight
molar ratio
moles
N-methyl-2-pyrrolidone (NMP) paraformaldehyde Jeffamine T-5000 aluminum chloride hexahydrate
41.2 g 1.04 g 32.0 g 1.85
64.9 5.4 1 1.2
0.416 0.0346 0.0064 0.0077
Scheme 2. Core-Flood Setup for Demonstrating the Ability for TCEP To Serve as a Gel Breaker for the 65-5 Thermodynamic Gel
measured at pH 7−8. The mixture was then removed from the oil bath and allowed to cool to room temperature where a gel would form, referred to in this paper as ‘65-5 kinetic gel’ (referencing the 65:5 molar ratio of NMP to paraformaldehyde). Transformation of the Hemiaminal (Kinetic) Gel to Liquid Phase. The gel from above is cut into smaller pieces and placed into a jar with a magnetic stir rod. Aluminum chloride hexahydrate in the amount indicated in Table 1 is added into the jar with the pieces of gel and allowed to stir for 24 h where breakdown of the gel into a liquid would occur, referred to in this paper as ’65-5 liquid.’ The pH of the liquid was measured at pH 6. Rheology Experiments. The 65-5 liquid (from the ratio of NMP to paraformaldehyde where the ratio of paraformaldehyde to Jeffamine T-5000 is 5.4:1), made as described above, is tested in a Grace M5600 HPHT rheometer to study the temperature effects on gelation time at 3.4 MPa. The rheometer uses an oscillatory test where the sample is subjected to a steady 1 Hz frequency and 100% amplitude oscillatory strain, and the resulting stress is measured and recorded as an elastic and viscous modulus (G′ and G′′, respectively). Gel time is interpreted as when G′ crosses over G′′. The system is tested at 70, 100, and 150 °C. Liquid phase gel made as described above is tested in a Fann i-X77 HPHT rheometer to study the effect of varying pressure on gelation time while holding the sample at a constant 70 °C. A rotational sweep program is used to simulate oilfield testing conditions and to establish a gel time under 20, 35, and 60 MPa. Core-Flood Experiment. Core-flood testing was done in a Grace 9100 Core Flow apparatus. To prepare the core for the gel breaking study, an Idaho Gray sandstone core (6 in. in length, 1 in. in diameter) was vacuum pumped for 2 h in the 65-5 liquid from above to saturate the pores in the core. The core was removed from the vacuum pump apparatus, fully submerged with excess 65-5 liquid, and placed into an oven at 70 °C overnight where the liquid would then revert into a gel. After allowing to cool to room temperature, excess solidified gel was removed from the exterior of the core, and a fully saturated core was left for testing. The accumulator in Scheme 2 holds either neat NMP or a saturated solution of 50 g of TCEP dissolved in 500 mL of NMP, depending on the experiment. Gel Weighting Procedure. Zinc bromide is added to NMP stirring at room temperature until a fully saturated solution of ZnBr2 in NMP is achieved. The proportions are described in Table 2. The density of the fully saturated solution is about 1.35 g/cm3 as measured by a pycnometer. The ZnBr2 saturated NMP and paraformaldehyde are mixed together at 70 °C in an oil bath on a heated stir plate for 30 min. Jeffamine T-5000 was then added to the mixture and allowed to continue to stir at 70 °C for another 30 min. The mixture was then removed from the oil bath and allowed to cool to room temperature where a gel would form.
Table 2. Weighted Sample Formulations material
weight
molar ratio
moles
NMP saturated with ZnBr2 paraformaldehyde Jeffamine T-5000 aluminum chloride hexahydrate
41.2 g 1.04 g 32.0 g 1.85
64.9 5.4 1 1.2
0.416 0.0346 0.0064 0.0077
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RESULTS AND DISCUSSION A schematic for the chemical transformations in the dynamic covalent system studied is presented in Scheme 1. This chemical system involves the condensation of a polypropylene glycol triamine with formaldehyde in the polar aprotic solvent, N-methylpyrrolidone (NMP). The initial condensation involves a number of intermediates in the process of the formation of B, abbreviated in Scheme 1. The dynamics of the condensation are modified through the addition of a trivalent metal salt (M(III)), such as aluminum chloride. The addition of the trivalent metal has the effect of reversing the initial kinetic hemiaminal gel to a liquid such that the earlier products in the condensation pathway are favored over the final products at room temperature. The resulting organometallic liquid with the trivalent metal can be transformed by into a more thermodynamically stable gel with heating. This gel can in-turn revert to liquid with the addition of TCEP in NMP.5 Demonstrating that the hemiaminal chemistry can be weighted with salts commonly used in the oil field, we have demonstrated that zinc bromide works as a good density modifying agent. Weights of up to 1.35 g/cm3 are possible with the liquids loaded in this way. When the 65-5 liquid (B in Scheme 1) is heated to 70 °C and pressurized to 20, 35, and 60 MPa, there is a pressure effect on the gelation kinetics which is observed. The gelation time displays a pressure dependence such that an increase in pressure decreases the gel time. At 20, 35, and 60 MPa the corresponding gel times observed are 390, 270, and 140 min, respectively. Figure 1 displays the results from the test in rotational rheology. These measurements indicate that the pressure accelerates the formation of the species toward the end of the condensation pathway wherein formaldehyde and the trifunctional amine Jeffamine T-5000 condense increasingly branch hemiaminal and aminal condensation products. C
DOI: 10.1021/acs.iecr.8b04019 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX
Article
Industrial & Engineering Chemistry Research
piston in the accumulator up, creating a flow of the NMP solution through the green lines. The ISCO pump also controls the flow rate/set pressure of the NMP solution as it builds up on the bottom of the core and reads out as Bottom Pressure. The gel saturated core has 6.8 MPa confining pressure applied in the core holder. The yellow line indicates the flow of breakthrough from the experiment with NMP or the experiment containing NMP and TCEP. When the Top Pressure reading matches the Bottom Pressure reading, we assume full breakthrough has occurred. Figure 3 shows the output of the top pressure on the sample. The top pressure indicated in Scheme 2 is measured as a
Figure 1. 65-5 liquid (described in the Experimental Section) is heated to three different temperatures (70, 100, and 150 °C) at 3.4 MPa, simulating three different wellbore environments. The data clearly show a decrease in gel time with increasing temperature.
When the pressure is held constant and the temperature is varied, there is a similar correspondence observed as was previously observed under atmospheric pressure conditions. A rise in temperature leads to a faster rate of gelation. Specifically, when the 65-5 liquid is maintained at 3.4 MPa and heated to 70, 100, and 150 °C, the corresponding gel times, measured from the elastic and viscous modulus crossover, are 340, 190, and 40 min, respectively. This corresponds with what has been previously observed and reported under atmospheric pressure.5 That the transformation occurs at temperatures up to 150 °C indicates, in part, the suitability for this chemical system under higher temperature wellbore situations. The temperature dependence of the gelation time at 3.4 MPa is displayed in Figure 2. The data presented in Figure 2 are from small amplitude oscillatory shear experiments where G′ is the elastic modulus of the materials tested and G′′ is the viscous modulus. Core flooding designs illustrated in Scheme 2 show the pathway for NMP and NMP/TCEP solutions to break the thermodynamic 65-5 gel formed and plug an Idaho sandstone core. NMP or NMP/TCEP is poured into the top reservoir of the accumulator. The ISCO pump uses DI water to push the
Figure 3. Testing of the gel breaking ability of TCEP in a Grace 9100 Core Flow apparatus.
function of time with the bottom pressure being ramped to the point of breakthrough. The experiment design is depicted in Scheme 2. This demonstrates that the TCEP does degrade the gel in the core to allow for the return of free passage with no damage to the core sample observed, suggesting no formation damage from the use of these materials. The breakdown to the gel with TCEP occurs through the nucleophilic attack of phosphine at the methylene carbon on the aminal functional groups of the gels. A manuscript describing this mechanism in detail is in preparation.
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CONCLUSIONS The hemiaminal/aminal metallogel system has been demonstrated to perform under pressures up to 60 MPa and temperatures up to 150 °C. This extends the performance window of the system to many conditions in oil and gas wells where high performance completion fluids show significant limitations in operability. Increasing either the temperature or the pressure in this system increases the reaction rate and drives the formation of the thermodynamically favored gel. Weighting of the gel with zinc bromide is also demonstrated for situations where matching the pore pressure within the rock formation with the fluids hydrostatic pressure is desired. The reversibility inherent in the hemiaminal/aminal metallogel can be used to break the gel within a core sample under pressure in a standard core-flood apparatus. Tris(2carboxyethyl)phosphine has been shown to effectively break the gel within a highly permeable sandstone core sample. The breaking of the gel does not show remaining residue on the core and is thus anticipated not to impart formation damage in
Figure 2. 65:5 liquid (described in the Experimental Section) is heated to 70 °C at three different pressures, simulating three different wellbore environments. D
DOI: 10.1021/acs.iecr.8b04019 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX
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Industrial & Engineering Chemistry Research rock formations where the completion fluid system is deployed.
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(11) Chang, F. F.; Thomas, R. L.; Fu, D. K. A New Material and Novel Technique for Matrix Stimulation in High-Water-Cut Oil Wells. SPE International Symposium on Formation Damage Control, 1998, 1, DOI: 10.2118/39592-MS. (12) Ohsedo, Y. Low Molecular Weight Organogelators as Functional Materials for Oil Spill Remediation. Polym. Adv. Technol. 2016, 27, 704. (13) (a) Du, G.; Peng, Y.; Pei, Y.; Zhao, L.; Wen, Z.; Hu, Z. Thermo-Responsive Temporary Plugging Agent Based on Multiple Phase Transition Supramolecular Gel. Energy Fuels 2017, 31, 9283. (b) Zhao, L.; Pei, Y.; Du, G.; Wen, Z.; Luo, Z.; Du, J. ThermoResponsive Temporary Plugging Agent Based on Multiphase Transitional Supramolecular Gel. Pet. Chem. 2018, 58, 94. (14) Moradi-Araghi, A. A Review of Thermally Stable Gels for Fluid Diversion in Petroleum Production. J. Pet. Sci. Eng. 2000, 26, 1.
AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. ORCID
Peter J. Boul: 0000-0002-7082-086X Author Contributions
The manuscript was written through contributions of all authors. All authors have given approval to the final version of the manuscript. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The authors would like to thank Mr. Kenneth Johnson and Mr. Roland Martinez with their assistance with the Grace 9100 Core Flow apparatus. This contribution was identified by Dr. Hayley Brown of Dow Chemical as the Best Presentation in the “Industrial Innovations in Polymer Chemistry” session of the 2018 ACS Spring National Meeting in New Orleans.
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ABBREVIATIONS MPa = MegaPascals Pa = Pascals HPHT = High Temperature High Pressure TCEP = tris(2-carboxyethyl)phosphine NMP = N-methylpyrrolidone
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REFERENCES
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DOI: 10.1021/acs.iecr.8b04019 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX
