Yudhowijoyo, Azis (University of Aberdeen) | Rafati, Roozbeh (University of Aberdeen) | Sharifi Haddad, Amin (University of Aberdeen) | Pokrajac, Dubravka (University of Aberdeen) | Manzari, Mehrdad (University of Aberdeen)
Crosslinked polymer gels have been widely used to overcome water and gas coning problem in the petroleum industry. Recently, nanoparticles are identified to have a potential of reinforcing the polymer gel systems by improving physical bonding and heat transfer properties in the gel structure. In this study, silicon dioxide and aluminium oxide nanoparticles were introduced to xanthan gum polymers that were crosslinked by chromium (III) acetate, to create polymeric nanocomposite gels with higher shear strengths. The gelation time and gel strength have been selected as main parameters to evaluate the effect of nanoparticle types and concentrations on the nanocomposite gels performance. The gelation time is measured until the onset of gelation or the moment when apparent viscosity starts to increase at 60°C. The gel strength is represented by the storage modulus (G’) after 24 hours of gelation at 60°C. Both parameters were measured by a rheometer, through constant shear rate and oscillatory tests respectively.
The addition of 1000 and 10000 ppm of silicon dioxide (SiO2) nanoparticles into a solution of 6000 ppm xanthan gum polymers that are crosslinked with 50000 ppm chromium (III) acetate caused insignificant changes in gelation time. Similar result was also reported when 1000 and 10000 ppm of aluminium oxide (Al2O3) nanoparticles was introduced into the polymer system. This suggests that when SiO2 and Al2O3 nanoparticles are introduced to xanthan/chromium (III) Acetate system for field application, no additives would be required to prolong or shorten gelation time to counter the nanoparticles addition. To analyse the gel strengths, the results from the oscillatory test were averaged throughout the frequency range, and it was shown that the addition of SiO2 nanoparticles decreases the average storage modulus from 75.1 Pa without nanoparticles, to 72.3 Pa at the nanoparticles concentration of 1000 ppm. However, the average storage modulus increased to 83.0 Pa and 94.7 Pa at higher nanoparticles SiO2 concentrations of 5000 ppm and 10000 ppm. The same trend was observed for the nanocomposite gels that were produced by Al2O3 nanoparticles. Similarly, the storage modulus decreased initially to 70.8 Pa at the concentration of 1000 ppm, then it increased to 89.9 Pa and 109.4 Pa at nanoparticles concentrations of 5000 pm and 10000 ppm, respectively. Hence, the nanoparticle-enhanced biopolymer gels showed insignificant changes of gelation time, and at the same time, they demonstrated up to 45% improvements in the gel strength properties when the nanoparticles concentration is higher than 5000 ppm.
In conclusion, the nanocomposite gels demonstrated reinforced bonding properties and showed higher gel strengths that can make them good candidates for leakage prevention from gas wells and blocking of water encroachments from aquifers into the wells.
This page focuses on important formula parameters and on temperature effects as they relate to gelation rate and gel strength of conformance treatment polymer gels. Figs. 1 through 4 relate to gel formula parameters and the effect of temperature for a specific CC/AP gel formula. Other oilfield polymer-gel technologies tend to follow similar relationships. The gel formula of Figs. 1 through 5 is a fracture-problem fluid-shutoff gel that has a rigid and soft Buna rubbery consistency. The gel was formulated in fresh water and contained 2.0 wt% active polyacrylamide (PAM) polymer possessing 11 million MW and 2% hydrolysis.
They assist oil/water/gas separation, aid in fluid transport, protect treating equipment, and improve the quality of the gas, oil, and water. A wide range of chemicals is available for water treating. A chemical-injection package enables various types of chemicals to be dosed into the water stream to optimize the treatment process. Storage-tank capacity is designed to allow the plant to run for several days between refills. General dosing rates and injection points for the main chemical classes are listed in Table 1. These rates provide guidelines for sizing injection pumps and chemical-storage tanks. Water-clarification chemicals aid in coagulating and flocculating the oil and solid particles into larger ones to enhance their separation from water.
Produced water typically enters the water-treatment system from a two- or three-phase separator, free-water knockout, gun barrel, heater treater, or other primary-separation-unit process. This water contains small concentrations (100 to 2000 mg/L) of dispersed hydrocarbons in the form of oil droplets. Because the water flows from this equipment through dump valves, control valves, chokes, or pumps, the oil-particle diameters will be very small ( 100 μm). Treatment equipment to remove dispersed oil from water relies on one or more of the following principles: gravity separation (often with the addition of coalescing devices), gas flotation, cyclonic separation, filtration, and centrifuge separation. In applying these concepts, one must keep in mind the dispersion of large oil droplets to smaller ones and the coalescence of small droplets into larger ones, which takes place if energy is added to the system. The amount of energy added per unit time and the way in which it is added will determine whether dispersion or coalescence will take place. Stokes' law, shown in Eq. 4.1, is valid for the buoyant rise velocity of an oil droplet in a water-continuous phase. Several immediate conclusions can be drawn from this equation. The third conclusion requires further elaboration. Heat is the primary mechanism in oil-treating equipment to remove small water droplets from oil. The addition of heat significantly reduces oil viscosity, which prompts more rapid settling, and heat destabilizes water-in-oil emulsions. Heat is not commonly used in water treating because the percentage change in viscosity per degree of temperature change is much less in water than in oil. Water-in-oil emulsions tend to have a higher percentage of the dispersed phase than the oil-in-water emulsions; the dispersed phase tends to have larger-diameter droplets stabilized by heat-sensitive emulsifiers, and it takes twice as much heat input to raise a barrel of water as it takes to raise a barrel of oil to the same temperature. Small oil droplets contained in the water-continuous phase are subject to the competing forces of dispersion and coalescence.
Hydrocarbons are trapped at great depths with pressure and temperature higher than surface conditions which would vary depending on reservoir properties. When the well is set on production, these hydrocarbons travel through the wellbore over reducing geothermal and formation pressure gradients. Hence, at shallower depths the temperature drops below the cloud point and sometimes, below pour point of crude thus creating an ambient temperature for the formation of wax and deposition of paraffin on the inner side of production tubing.
It has been observed that when hot fluid passes through a pipe which is covered by a continuously circulating hot water bath, the temperature difference of the fluid at surface outlet and sub-surface reservoir is reduced to a minimal value. This paper therefore proposes a practical application of such heat transfer within a wellbore for passively solving major industrial issues of paraffin depositions. The idea lies in minimizing the heat losses, which can be effectively done by insulating the inner side of the casing so that the annulus and fluid flowing within the tubing is isolated from exterior losses. According to the First law of Thermodynamics the fluid flowing within the tubing will experience reduction in thermal gradient. These loses can be compensated by injecting hotter brine through a pipe at the bottom of the annulus, which is isolated, using production packer. Further, circulating hot fluid in the annulus would result in isothermal heating of the fluid flowing through the tube which would minimize the heat loss across tubing, causing an increase in temperature of fluid at the surface above pour point. Several researchers have put forth heat transfer equations across the tubing's, annulus, insulator, casing, cement and the formation which can be used to calculate the overall heat transfer coefficient and thus, the amount of heat losses. Quartz sensors placed at the bottom of a wellbore would detect bottom borehole temperature based on which the injection temperature of fluid can be manipulated. The entire process can be automated by applying an artificial intelligent system which would monitor, control and respond. This method would increase the capex but would decrease the operating cost thus leading to an increase in the life of the well.
Wei, Bing (Southwest Petroleum University) | Wang, Yuanyuan (Southwest Petroleum University) | Chen, Shengen (Southwest Petroleum University) | Mao, Runxue (Southwest Petroleum University) | Ning, Jian (Southwest Petroleum University) | Wang, Wanlu (Southwest Petroleum University)
Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.
Tavassoli, Shayan (The University of Texas at Austin) | Shafiei, Mohammadreza (The University of Texas at Austin) | Minnig, Christian (swisstopo) | Gisiger, Jocelyn (Solexperts) | Rösli, Ursula (Solexperts) | Patterson, James (ETHZ) | Theurillat, Thierry (swisstopo) | Mejia, Lucas (The University of Texas at Austin) | Goodman, Harvey (Chevron ETC) | Espie, Tony (BP) | Balhoff, Matthew (The University of Texas at Austin)
Wellbore integrity is a critical subject in oil and gas production, and CO2 storage. Successful subsurface deposition of various fluids, such as CO2, depends on the integrity of the storage site. In a storage site, injection wells and pre-existing wells might leak due to over-pressurization, mechanical/chemical degradation, and/or a poor cement job, thus reducing the sealing capacity of the site. Wells that leak due to microannuli or cement fractures on the order of microns are difficult to seal with typical workover techniques. We tested a novel polymer gelant, originally developed for near borehole isolation, in a pilot experiment at Mont Terri, Switzerland to evaluate its performance in the aforementioned scenario.
The polymer gel sealant was injected to seal a leaky wellbore drilled in the Opalinus Clay as a pilot test. The success of the pH-triggered polymer gel (sealant) in sealing cement fractures was previously demonstrated in laboratory coreflood experiments (
The novel sealant was successfully deployed to seal the small aperture pathways of the borehole at the pilot test. We conducted performance tests using formation brine and CO2 gas to put differential pressure on the polymer gel seal. Pressure and flow rate at the specific interval were monitored during and after injection of brine and CO2. Results of performance tests after polymer injection were compared against those in the absence of the sealant.
Several short-term (4 min) constant-pressure tests at different pressure levels were performed using formation brine, and no significant injection flow rate (rates were below 0.3 ml/min) was observed. The result shows more than a ten-fold drop in the injection rate compared to the case without the sealant. The polymer gel showed compressible behavior at the beginning of the short-term performance tests. Our long-term (1-week) test shows even less injectivity (~0.15 ml/min) after polymer gelation. The CO2 performance test shows only 3 bar pressure dissipation overnight after injection compared to abrupt loss of CO2 pressure in the absence of polymer gel. Sealant shows good performance even in the presence of CO2 gas with high diffusivity and acidity.
Pilot test of our novel sealant proves its competency to mitigate wellbore leakage through fractured cement or debonded microannuli, where other remedy techniques are seldom effective. The effectiveness of the sealing process was successfully tested in the high-alkaline wellbore environment of formation brine in contact with cement. The results to date are encouraging and will be further analyzed once over-coring of the wellbore containing the cemented annulus occurs. The results are useful to understand the complexities of cement/wellbore interface and adjust the sealant/process to sustain the dynamic geochemical environment of the wellbore.
Investing in new wells during a period of volatile oil prices is not the best option for E&P companies. During hard economic environments such companies make plans to produce or enhance hydrocarbon recovery from existing wells for continuous cash flow and to maximize rate of return on investors’ expectations. In several regions, it may take years to produce the hydrocarbons from the drilled well. These wells were drilled and completed successfully, but they were idle, waiting for the production commencement date. This delay depends on various factors including reservoir conditions, market conditions and geopolitical situations. Due to these delays, wells undergo severe formation damage that either minimizes hydrocarbon production or halts hydrocarbon flow completely.
A solution was identified to increase production from a damaged well or bring a non-producing well back into production. This solution is based on microemulsion chemistry. Microemulsions consist of mixtures of oil and water, along with surfactants and other components. These fluids are optically transparent, thermodynamically stable, possess extremely low interfacial tension, and require minimum or zero energy to form. Microemulsions are transparent because of an extremely small droplet size. These are naturally occurring and have less risk involved in deploying and executing the job when compared to conventional solvent treatments. Cleaning efficiency and reaction time of microemulsions depend on many parameters including reservoir conditions, salinity, temperature and type of hydrocarbon used during the drilling or completion phase. These microemulsion fluids were pumped using an inflatable straddle packer (ISP) designed to isolate and divert into the required small area of exposure. The system consists of two inflatable packers with variable spaceout possibilities, enabling adequate positioning over the selective formation area. This tool was deployed using coiled tubing and real-time depth correlation to estimate the correct treatment zones.
A customized fluid was designed using specialized surfactants, brine and an acid. These individual components were mixed on the surface and pumped down hole. This blend works by solubilizing oil and emulsifiers from the oil-based filter cake and forming a microemulsion.
This paper discusses an openhole completion well that was drilled and then completed with ICD screens. Oil-based mud was left in the hole, causing severe damage that prevented bringing the well back to production. The designed surfactant package was pumped through an ISP tool that was suitable for the reservoir conditions. The ISP tool elastomers were designed after performing detailed lab tests that included the filter-cake destruction test, a wettability test and elastomer compatibility tests. Surfactant was pumped into the reservoir with an engineering approach, and successful results were achieved with good production results.
Applications of oil-in-water emulsion (O/W) emulsification technology in enhanced recovery and pipeline transportation of heavy oil can be limited by several factors including salinity of the reservoir or process water, process temperature, and water cut. In this investigation, laminar flow of O/W was simulated in a pipeline to investigate the effect of salinity of aqueous phase (NaCl) and water cut on flow characteristics of the fluid. The case was simplified by considering the O/W as a stable, pseudo-homogeneous, single-phase fluid within the conditions operated. Pertinent to the objective of the study, at flow reference temperature, Tref 30oC, the pressure drop at 30% water cut was 931Pa compared to 84.6 Pa at water cut of 50% (reference working fluid without NaCl). In contrast, the pressure drop was 239Pa, 142Pa, 124Pa, and 82.9Pa at 70000ppm, 40000ppm, 20000ppm, and 10000ppm salinity in the aqueous phase, respectively. In addition, the maximum dynamic viscosity imposed by the fluid, was 81000cP at 30% water cut compared to 14000cP from the reference fluid. The dynamic viscosity obtained from 70000ppm salinity content was 34000cP. Moreover, the results confirm facile application of emulsification technology for pipeline transportation of bitumen from large reduction in pressure drop (99%) regardless of the water cut and salinity.
Zhu, Daoyi (China University of Petroleum, Beijing) | Hou, Jirui (China University of Petroleum, Beijing) | Wei, Qi (China University of Petroleum, Beijing) | Chen, Yuguang (China University of Petroleum, Beijing)
The PG Reservoir in Jidong Oil Field is at a depth of approximately 4500 m with an extremely high temperature of approximately 150°C. The average water cut has reached nearly 80%, but the oil recovery is less than 10% after only 2 years of waterflooding process. It is of great importance to develop a high-temperature-resistant plugging system to improve the reservoir conformance and control water production. An in-situ polymer-gel system formed by the terpolymer and a new crosslinker system was developed, and its properties were systematically studied under the condition of extremely high temperature (150°C). Suitable gelation time and favorable gel strength were obtained by adjusting the concentration of the terpolymer (0.4 to 1.0%) and the crosslinker system (0.4 to 0.7%). An increase of polymer and crosslinker concentration would decrease the gelation time and increase the gel strength. The gelant could form continuous 3D network structures and thus have an excellent long-term thermal stability. The syneresis of this gel system was minor, even after being heated for 5 months at the temperature of 150°C. The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. Core-flow experiments showed that the gel system could have great potential to improve the conformance in Jidong Oil Field.