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Collaborating Authors
Drilling Fluids and Materials
Lab and Pilot-Scale Evaluation of Stable Foam for Drilling in High Temperature Environment
Griffith, Christopher (Chevron) | Linnemeyer, Harry (Chevron) | Kim, Do Hoon (Chevron) | Hahn, Ruth (Chevron) | Zhou, Jimin (Chevron) | Upchurch, Eric (Chevron) | Malik, Taimur (Chevron) | Wileman, Angel (Southwest Research Institute) | Beck, Griffin (Southwest Research Institute) | Bhagwat, Swanand (Southwest Research Institute) | Gutierrez, Luis (Southwest Research Institute)
Abstract Using foams to drill in low pore pressure reservoirs is attractive because of their low density, high viscosity, and ability to transport cuttings. However, in high temperature reservoirs (240 °F) with H2S gas present, there are concerns with the long-term stability of a foam drilling fluid. In this work, we highlight a lab program to develop a stable drilling foam for drilling in a low pore pressure, high temperature reservoir. The work also includes pilot-scale experiments to evaluate foam performance. Aqueous nitrogen-in-water foams were stabilized with a preferred foaming surfactant formulation, and the rheology and stability of the foams were measured at representative drilling conditions (temperature and pressure) at the lab and pilot-scale. The foams were also evaluated for their compatibility with current drilling fluids used on site and for stability in the presence of H2S gas (at 1900 psi and 140 °F). The drilling foam was also evaluated using a pilot-scale flow loop comprised of a rheology flow loop and a model drilling wellbore. The experiments included measuring the foam rheology, foam stability in the model wellbore, and gas migration tests to understand how the foam suppresses upwardly migrating gas bubbles. We successfully developed a surfactant stabilized foam designed for a high-temperature reservoir with H2S gas present. We found that H2S can negatively impact foam stability if proper surfactants are not selected. Our foam showed less than 10% liquid drainage after 12 hours at 240 °F and showed no significant degradation upon contact with 17 mol% H2S gas. Additionally, the foam was compatible with all drilling fluids (both water-based and oil-based) currently used at the drill site and demonstrated good stability in a model pilot-scale drilling wellbore. Interestingly, when the wellbore was angled at 30 degrees from vertical with the eccentric drill pipe rotating at 100 RPM, the foams were susceptible to degradation compared to an equivalent scenario of a vertical wellbore with concentric rotating drill pipe. The gas migration tests at the pilot-scale showed the foam was capable of significantly slowing down an upwardly moving gas bubble with and without pipe rotation.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management (1.00)
- Well Drilling > Drillstring Design (1.00)
- (4 more...)
Abstract The potential application of surface modified silica nanomaterials to boost the stability of oil in water emulsions created by alkali-polymer flooding has been investigated. Long-term phase behavior experiments and interfacial tension measurements are performed. We evaluate the effects of particle size and surface modification, as well the influence of the alkali type and concentration on the emulsion stability. The workflow helps understanding the fluid-fluid interactions and facilitates the selection of materials for further core-flood evaluations. Three types of nanomaterials allowed investigating the effect of particle size (60 and 100 nm) and two different surface modifications, which differ slightly in hydrophilicity and zeta-potential. Phase-experiments were performed at 1:1 water/oil ratio using a high TAN crude-oil. Emulsion volume was recorded over 100 days and aqueous-phase composition was varied to study the effect of alkali concentration (1000−15000 ppm), particle type/concentration (0.05−5 wt.%), alkali (Na2CO3 versus K2CO3), and polymer (0 and 2000 ppm). Overall, ∼100 different combinations with triplicates were tested. IFT experiments were performed using a spinning-drop tensiometer, and results were compared at 300 min of observation. Phase experiments revealed that surface modified nanomaterials have the ability to stabilize oil-in-water emulsions that were formed due to reaction of alkaline brine with crude-oil, supported by a low IFT in the alkali/particle system. Combination of 0.1 wt% silica particles and 3000ppm alkali produces very-long lived emulsions and outperforms the control experiments by a factor of four in terms of emulsion volume (at 100 days). The type of surface modification of the nanomaterial had a negligible effect on the volume of the stabilized emulsion. However, density and viscosity of the emulsion were influenced, which will affect fluid flow in the reservoir. A synergistic effect of smaller size (higher effective concentration of particles) and more neutral surface charge of the modified particles resulted in emulsification of crude-oil with silica particles alone, which did not occur for the samples with larger particle size and lower zeta potential. Too high concentrations of alkali and particles resulted in destabilization of the emulsions, which may be due to charge reversal of particles and exceedance of the critical coagulation concentration. Since the viscosity of an emulsion is larger than that of the continuous phase, polymer could be required to flood the emulsion out of the reservoir. In our experiments, the addition of polymer reduced emulsion stability in the alkali-only experiments, but adding nanomaterial boosted the emulsion stability. Nano-EOR is an embryonic technology and to the best knowledge of the authors, literature data is scarce on how nanomaterials emulsify crude-oil, since most studies have been done with simple hydrocarbons such as decane. The majority of the existing literature addresses the stabilizing effect of nanoparticles on emulsions created due to the mixing of surfactants with hydrocarbons, whereas in this study we use alkali as an economically more attractive saponifying agent.
- Europe > Austria (0.68)
- North America (0.68)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Austria > Lower Austria > Vienna Basin (0.99)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
Performance of Conformance Gels Under Harsh Conditions
Unomah, Michael (Chevron Energy Technology Company) | Thach, Sophany (Chevron Energy Technology Company) | Shong, Robert (Chevron Energy Technology Company) | App, Jeff (Chevron Energy Technology Company) | Zhang, Tiantian (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Permeability reduction provided by conventional polymer gels is affected by harsh reservoir conditions. Harsh conditions are defined by high temperature (> 75°C), high salinity, high divalent ions and the presence of H2S. Polymer gels undergo syneresis when exposed to high salinity and hardness reservoir brines. We evaluated conventional polyacrylamide-based polymer (HPAM)-gels and other modified HPAM-gels with molecular weights between 2-20MM Daltons for gelation time and long-term gel stability under harsh conditions. In addition to polymer degradation, the cross-linkers are also sensitive to harsh reservoir conditions. Specifically, H2S can consume cross-linkers and inhibit gelation. The cross-linkers tested were Chromium (III) Acetate and Chevron Unogel formulation consisting of a combination of hexamethylenetetramine (HMTA) and hydroquinone (HQ). High performing gels were tested for sensitivity to high salinity brines and H2S in a limited number of experiments. The gels were observed for gel strength, and syneresis with time. The goal of our work was to identify a combination of polymer and cross-linker that would provide effective conformance under harsh conditions. Sulfonated polyacrylamide (ATBS) polymers were found to provide better resistance to high salinity/hardness brines than partially hydrolyzed polyacrylamides in high temperature conditions. The addition of hydrophobic groups to the sulfonated-acrylamide backbone does not increase the hardness tolerance of the polymer. Higher concentration, low molecular weight sulfonated polymers are recommended for use at high temperature and salinity. Polymer gels made with 2MM Dalton polymer show less syneresis with time compared to higher molecular weight polymer at the same polymer concentration. HMTA/HQ ATBS polymer gels are preferable to chromium (III) ATBS polymer gel for high temperature and salinity conditions. Chromium (III) ATBS polymer gels show more susceptibility to syneresis compared to organic crosslinked gels at same polymer concentration. HMTA/HQ crosslinker is ineffective in the presence of hydrogen sulfide. Gelants consisting of HMTA/HQ do not mature into rigid gels after 14 days of exposure to sour gas. Preformed HMTA/HQ gels lose strength upon exposure to sour crude. This is mostly due to HMTA ability as a sour gas/crude sweetener. Chromium (III) gels form weak gels in the presence of sour gas. Chromium competes with sulfide ions to produce insoluble chromium sulfide leading to consumption of crosslinker and poor gelation. Malonate and tartrate are effective gel retardants for chromium (III) polymer gels. Malonate is better at extending onset of gelation for longer periods of time. Tartrate is more effective for shorter gelation time at lower concentrations.
- Geology > Mineral (0.91)
- Geology > Geological Subdiscipline (0.75)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)
An Experimental Investigation of Polymer Mechanical Degradation at cm and m Scale
Åsen, Siv Marie (UiS, IRIS and The National IOR Centre of Norway) | Stavland, Arne (IRIS and The National IOR Centre of Norway) | Strand, Daniel (IRIS and The National IOR Centre of Norway) | Hiorth, Aksel (UiS, IRIS and The National IOR Centre of Norway)
Abstract In this work, we challenge the common understanding that mechanical degradation takes place at the rock surface or within the first few mm. The effect of core length on mechanical degradation of synthetic EOR polymers was investigated. We constructed a novel experimental set-up for studying mechanical degradation at different flow rates as a function of distances travelled. The set-up enabled us to evaluate degradation in serial mounted core segments of 3, 5, 8 and 13 cm individually or combined. By recycling we could also evaluate degradation at effective distances up to 20 m. By low rate reinjecting of polymers previously degraded at higher rates, we simulated the effect of radial flow on degradation. Experiments were performed with two different polymers (high molecular weight HPAM and low molecular weight ATBS) in two different brines (0.5% NaCl and synthetic seawater). In linear flow at high shear rates, we observed a decline in degradation rate with distance travelled, but a plateau was not observed. Even after 20 m there was still some degradation taking place. The molecular weight (MW) of the degraded polymer could be matched with a power law dependency, MWD ~L, where x for the HPAM was 0.07 and x for ATBS was 0.03. We conclude that in linear flow, the mechanical degradation depends on the core length. However, in radial flow where the velocity decreases by length, the mechanical degradation reaches equilibrium with no further degradation deeper into the formation. For the experiments where we evaluated degradation over large distances at high shear rates, we observed a decline in degradation rate with distance travelled, but we could not conclude that we reached a plateau. Even after 20 m there is still some degradation taking place. It is important to consider this knowledge when interpreting core scale experiments. However, the observed degradation is associated with high-pressure gradients, in the order of 100 bar/meter, which at field scale is not realistic. We confirmed previous findings; degradation depends on salinity and molecular weight. Results show that in all experiments with significant degradation, most of the degradation takes place in the first core segment. Moreover, the higher the shear rate and degradation, the higher is the fraction of degradation that occurs in the first core segment.
- Europe (1.00)
- North America > United States (0.46)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)