Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Screening of Topside Challenges Related to Polymer Presence in the Back Produced Fluids – Casabe Case Study
Mouret, Aurélie (IFP Energies Nouvelles) | Blazquez-Egea, Christian (IFP Energies Nouvelles) | Hénaut, Isabelle (IFP Energies Nouvelles) | Jermann, Cyril (IFP Energies Nouvelles) | Salaün, Mathieu (Solvay) | Quintero, Henderson (Ecopetrol) | Gutierrez, Mauricio (Ecopetrol) | Acosta, Tito (Ecopetrol) | Jimenez, Robinson (Ecopetrol) | Vargas, Nadine (Ecopetrol)
Abstract Polymer enhanced oil recovery (EOR) pilots were implemented in various mature oilfield reservoirs in Colombia with encouraging results. That chemical EOR technology is often considered as a promising process to faster recover oil. To increase the chance of success of such an industrial project it is important not to neglect the potential impact of residual polymer in back produced effluents. The objective of this work is to highlight the impact of back-produced EOR polymer at the laboratory scale on various topside equipment before deploying the polymer injection at wider scale in a heavy oil field (18° API). A topside facility review was first performed to collect operational conditions and parameters, to identify applied treatment technologies and to define relevant sampling locations for the laboratory study. The impact of the residual acrylamide/ATBS ter-polymer selected for the future polymer implementation was then explored in a set of experiments as part of a dedicated laboratory workflow representing the whole surface treatment chain. The scope of the study has covered primary separation, static gravity water clarifying, deep-bed filtration and heater fouling. Large residual polymer concentration and water cut ranges were investigated to anticipate some produced fluid composition change over time. In the case studied, the selected polymer does not stabilize tight water-in-oil emulsions, but it has a negative impact on the water quality. Some compatibility issues are observed with incumbent demulsifiers, which seems to be sensitive to both polymer concentration and water cut. The fouling risk of heat exchanger is very low in the testing conditions. In the water de-oiling side, filtration and gravity settling performance are reduced but the right chemical and equipment combination enables to obtain a better water quality and to meet injection specifications targets. Novel/Additive Information: This work illustrates that management of produced fluid containing EOR polymer has to be considered as early as possible in the project implementation. It also points out that laboratory experiments are useful to better appraise and mitigate the potential operational issues. All the results obtained in such a study are valuable guideline and input data for treatment facilities upgrade studies. In polymer flooding roadmap implementation, it is key to bond operational conditions and laboratory parameters in order to be as close as possible to the field conditions as each case is unique.
- South America > Colombia (0.67)
- North America > United States (0.46)
- Asia > India (0.46)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.48)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Colombia > Santander Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Colombia > Bolivar Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Colombia > Antioquia Department > Middle Magdalena Basin > Casabe Field (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Slickwater Friction Reducer Performance Evaluation and Application
Matovic, Gojko (Chevron Corporation) | Theriot, Timothy (Chevron Corporation) | Linnemeyer, Harold (Chevron Corporation) | Solano, Marlon (Chevron Corporation) | Fuller, Michael (Chevron Corporation) | Han, Seung (Chevron Corporation) | Kim, Amos (Chevron Corporation) | Nizamidin, Nabijan (Chevron Corporation) | Kim, Do Hoon (Chevron Corporation) | Malik, Taimur (Chevron Corporation) | Dwarakanath, Varadarajan (Chevron Corporation)
Abstract Friction reducers (FRs) are a vital component of slickwater fracturing fluids used in hydraulic fracturing operations. FRs, which are typically made up of high molecular weight polyacrylamide-based polymers, help decrease frictional pressure losses and improve the effectiveness of fracturing operations by allowing for higher fracturing (frac) injection rates at the same or lower surface pressures. By optimizing FR selection for field application, cost savings can be realized through reduction in chemical costs, reduction in equipment maintenance frequency, and rental savings. Furthermore, operations could be modified to use more produced water. Evaluating FR performance in the laboratory typically consists of running flow-loop experiments to measure pressure reduction in tubing or pipe over time. However, there is no industry-standard method for evaluating FR performance and different labs have developed their unique protocols and loop designs. To mitigate this deficiency, the project team designed and installed a FR evaluation flow loop and developed a protocol that effectively evaluates FR performance. The team compared performance of various FRs from selected FR suppliers focusing on three attributes: hydration time, maximum pressure reduction, and sustainability of pressure reduction over time. For a given test water, all candidate FRs were tested in the same conditions to allow direct comparison of FR performance. This work showed that pipe size, Reynolds number, and shear rate all affect friction reduction performance; but if testing is done under the same conditions, performance can be compared and ranked directly. Based on comprehensive testing to identify the best performing FRs for brackish, produced, and mixed water blends, a field test with the recommended candidates was conducted in support of a frac-chemical unbundling effort. FRs used in the field test were qualified using the in-house FR evaluation flow loop. Friction reducer performance in the field trial confirmed the FR lab evaluation protocol correctly ranks FR performance and enables scaling to field operation. There were no accepted methods to scale-up lab FR performance to predict field conditions and as accurate models continue to be developed, the main method for evaluating FR performance continues to rely on qualifying FRs based on lab-scale experiments. To bridge the gap, the project team developed an empirically based tool to improve FR selection using a comprehensive test matrix considering FR dosage, water salinity and water hardness. Development of this tool used constant test conditions so that consistent recommendations can be made.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (27 more...)
Confirmation of Polymer Viscosity Retention at the Captain Field Through Wellhead Sampling
Johnson, Geoffrey (Ithaca Energy) | Hesampour, Mehrdad (Kemira Oyj) | Toivonen, Susanna (Kemira Oyj) | Hanski, Sirkku (Kemira Oyj) | Sihvonen, Stina (Kemira Oyj) | Lugo, Nancy (Ithaca Energy) | McCallum, Jennifer (Ithaca Energy) | Pope, Michael (Ithaca Energy)
Abstract The Ithaca-operated Captain field is located in Block 13/22a in the U.K. sector of the North Sea, 130 km northeast of Aberdeen, in a water depth of 360 ft. The Captain Field has an adverse mobility ratio across all the producing reservoirs and so has undergone improved oil recovery by polymer flooding since 2011 using Anionic polyacrylamide (HPAM) in liquid form. This paper presents recent offshore wellhead sampling from the Captain facility that confirms high polymer solution viscosity retention from a producing well, even after significant mechanical degradation through the Electrical Submersible Pumps (ESP), which is used for artificial lift. The continuing commercial success of the Captain Field polymer flood is underpinned by maintaining polymer viscosity throughout the system. High polymer returns, combined with declining oil rates, may result in the continued operation of these wells to be unattractive. This paper summarises the data used to shut-in mature wells that are producing polymer to the surface, to enable the polymer flood to continue displacing oil to offset production wells. Samples were collected from the wellhead in oxygen free conditions into pressurized cylinders. The measurements in laboratory were taken inside a glove box to avoid oxygen ingress. The absence of oxygen was confirmed through measurements of dissolved oxygen and redox potential. Viscosity of the solutions have been measured with Brookfield viscometer inside the glove box and the results were compared to the expected viscosity from fresh non-degraded polymer solution. The expected viscosity was determined using a concentration – viscosity curve of a fresh polymer in synthetic Captain brine. Polymer solution concentration is measured on-site using KemConnect™ EOR, a time resolved fluorescence method, the collected samples were subsequently confirmed with size exclusion chromatography (SEC) in the laboratory. The polymer concentrations measured from these wellhead samples with KemConnect™ EOR were in the region of 700-900 ppm. Previously collected downhole viscosity samples confirmed >70% viscosity retention prior to being produced through the ESP, while 50-80% of the original viscosity was found to be retained after production through the ESP to the surface facilities under anaerobic conditions for the range of concentrations sampled. These findings demonstrate the resilience of the polymer product to degradation in a real-world operational setting. It also provides data that may be used to estimate the expected downhole polymer solution viscosity from wellhead samples for defined operating conditions. The ability to estimate polymer solution downhole viscosity retention from wellhead samples provides a simpler and less expensive method of estimating viscosity retention than downhole sampling, which is especially useful for wells that do not have downhole access for sample collection.
Abstract In the past decade, the number of polymer injection projects has greatly increased worldwide, with more and more full field implementations. More recently, the focus has shifted toward the deployment of such technologies offshore which presents very specific constraints in terms of facilities, logistics and produced water treatment. One restraint is related to the surface facilities and the footprint available to install the required equipment. This can have a great impact on the choice of the chemical form; two forms are usually considered (powder or emulsion) which dictate the type of equipment necessary and the complexity of the injection process. Other factors come into play when choosing the product form, including weather conditions, available storage, logistics and the existing infrastructure. Many projects are being constrained by the presence of subsea chokes, which can degrade the polymer solution and compromise the economics if not dealt with adequately. In this paper we will review the existing projects and discuss the offshore deployment philosophies for polymer injection. Then, the focus will be on brown fields and the differences between polymer emulsion and powder forms and how both can be processed in the field. Specific highlights will be on polymer design and selection, equipment and logistics for a real field case. Recent developments will be presented in relation to viscosity preservation during injection even in the presence of subsea chokes. Different approaches will be proposed including the deployment of non-degrading chokes or the use of Delayed Viscosity Polymer.
- North America > United States (1.00)
- Asia (1.00)
- Europe > United Kingdom > North Sea (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.54)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- (4 more...)
Scleroglucan Polymer Stability: Thermal, Chemical, and Microbial
Kozlowicz, Briana (Cargill, Inc.) | Jensen, Tryg (Cargill, Inc.) | Khambete, Malhar (Cargill, Inc.) | Kadhum, Mohannad J. (Cargill, Inc.) | Garshol, Frøydis Kirsti (Aquateam COWI) | Vik, Eilen Arctander (Aquateam COWI) | Tomczak-Wandzel, Renata (Aquateam COWI) | Wever, Diego A. (Shell Global Solutions International BV) | Lomans, Bart P. (Shell Global Solutions International BV) | Ray, Charles (Cargill, Inc.)
Abstract Polymers for enhanced oil recovery (EOR) purposes are required to have long term mechanical, thermal, chemical, and biological stability across a wide variety of conditions throughout field deployment. In this work we expand upon initial studies of scleroglucan biopolymer stability and demonstrate that scleroglucan solutions retain a significant proportion of their initial viscosity over a large range of stresses. Thermal stability of the biopolymer, scleroglucan, was tested at temperatures of up to 115°C, wherein the samples retained >95 % of the original viscosity over several months, and at 105 °C sclergolucan maintained >95 % viscosity over the course of 720 days. Scleroglucan was found to be chemically compatible with formaldehyde, glutaraldehyde, tetrakis(hydroxymethyl)-phosphonium sulfate (THPS), and 1,3,4,6-tetrakis(hydroxymethyl)tetrahydroimidazo-[4,5-d]imidazole-2,5(1H,3H)-dione (TMAD) for six months at 37 °C, 85 °C, and 95 °C, indicating these biocides have the potential for use in microbial control during scleroglucan implementation under various conditions. Rheological studies indicate the viscosifying power of scleroglucan is largely unimpacted by common reservoir salts (including divalents and trivalents) even through 20 % (wt/wt) salt addition. Microbial risks to polymer stability were also investigated. The susceptibility of scleroglucan to microbial degradation was assessed under reservoir relevant conditions using a bottle test system in which the polymer was incubated with active microbial cultures under various conditions that simulate reservoirs spanning 3.5 % to 17 % salinity and 30 °C to 90 °C. Our tests of microbial degradation found that anaerobic samples incubated with active microbial consortia under lower salinities and temperature lost viscosity with concomitant microbial growth indicating the presence of scleroglucan degrading organisms in the inoculum. However, anaerobic samples at temperatures above 60 °C and salinities greater than 7 % retained viscosity during the experiment illustrating polymer stability under conditions similar to those of harsh reservoirs. This study further refines the window of operation where scleroglucan maintains functional viscosity and may be employed for EOR use.
- Asia (0.68)
- North America > United States > Texas (0.46)
- North America > United States > California (0.46)
- North America > United States > Oklahoma (0.29)
- Geology > Geological Subdiscipline (0.46)
- Geology > Mineral (0.36)
Abstract Polymer flooding with visco-elastic polymers is an EOR technique improving both macro and microscopic recovery of oil. Its efficiency can be greatly limited by mechanical and chemical degradation of polymers. When injected in the reservoir, the early few centimeters travelled through the rock are crucial for determining the degradation undergone (degradation being defined as the irreversible loss of viscosity). Our aim is is to establish predictive laws for the degradation of polymer solutions flowing through porous media and for the associated flow thickening which can mobility reduction curves of polymer solutions injected or re-injected through sintered ceramic cores of length varying between 1 and 8 mm, we develop a model for predicting mobility reduction and degradation at any length of porous medium, any flux. The model is built by considering that a single injection at flux J on a core having a length NL0 is equivalent to N successive injections at flux J on a piece of the core of length L0. In linear fow, it is found that degradation increases sharply for the first few millimeters and then tends toward a quasi steady state value after a critical length Lc which decreases for increasing fluxes. This model is then transposed to radial flow. Similarly, there exists a critical distance Dc at which degradation reaches a steady state value. Dc is an increasing function of the injection well radius Rw and tends towards Lc at high Rw since radial flow becomes nearly linear. Results obtained with the model are then discussed for predicting precisely on which distance degradation will be experienced and for determining if degradation experiments performed in linear flow in the lab are representative of radial flow around a real polymer injector. This study is a first in injecting polymer solutions through cores as short as 1 mm and in predicting mobility reduction and degradation in both linear and radial flow profiles.
Polymer Chemical Structure and its Impact on EOR Performance
Beteta, Alan (Heriot-Watt University) | Nurmi, Leena (Kemira Oyj) | Rosati, Louis (Kemira Chemicals Inc.) | Hanski, Sirkku (Kemira Oyj) | McIver, Katherine (Heriot-Watt University) | Sorbie, Kenneth (Heriot-Watt University) | Toivonen, Susanna (Kemira Oyj)
Abstract Polymer flooding is a mature EOR technology that has seen an increasing interest over the past decade. Co-polymers of Acrylamide (AMD) and Acrylic Acid (AA) have been the most prominent chemicals to be applied, whereas sulfonated polymers containing 2-Acrylamido-tertiary-butyl sulfonic acid (ATBS) have been used for higher temperature and/or salinity conditions. The objective of this study was to generate guidelines to aid in the selection of appropriate polyacrylamide chemistry for each field case. Our main focus was in sandstone fields operating at the upper end of AMD-AA temperature tolerance, where it needs to be decided whether sulfonation is required. The performance of the polymer throughout the whole residence time in the reservoir was considered since the macromolecule can undergo some changes over this period. Several key properties of nine distinct polymer species were investigated. The polymers consisted of AMD-AA co-polymers, AMD-ATBS co-polymers and AMD-AA-ATBS ter-polymers. The polymers were studied both in their original state as they would be during the injection (initial viscosity, initial adsorption and in-situ rheology) as well as in the state which they are expected to be in after the polymer has aged in the reservoir (i.e. in a different state of hydrolysis and corresponding viscosity retention and adsorption after ageing for various time periods). We note that the combination of viscosity retention and adsorption during the in-situ ageing process has not been typically investigated in previous literature, and this is a key novel feature of this work. Each of the above parameters has an impact on the effectiveness and the economic efficiency of a polymer flooding project. The content of ATBS was limited to 15 mol%. Buff Berea sandstone was applied in the static and dynamic adsorption experiments. The majority of the work was carried out in seawater at temperature, T = 58°C. Under these conditions AMD-AA samples showed maximum viscosity and lowest adsorption when the content of AA was moderate (20 mol%). When the AMD-AA polymers were aged at elevated temperature, the AA content steadily increased due to hydrolysis reactions. When the AA content was 30 mol% or higher, the viscosity started to decrease, and adsorption started to increase as the polymer was aged further. Thermal stability improved when ATBS was included in the polymer structure. In addition, sulfonated polyacrylamide samples showed increasing initial viscosity yields and decreasing initial adsorption with increasing ATBS content. For most of the samples, the maximum observed apparent in-situ viscosity increased when the bulk viscosity and relaxation time of the sample solution increased. The information generated in this study can be used to aid in the selection of the most optimal polyacrylamide chemistry for sandstone fields operating with moderate/high salinity brines at the upper end of AMD-AA temperature tolerance.
- North America > United States > Oklahoma (0.29)
- North America > United States > West Virginia (0.24)
- North America > United States > Pennsylvania (0.24)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Geology > Mineral > Silicate (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/25 > Greater Schiehallion Field > Schiehallion Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/20 > Greater Schiehallion Field > Schiehallion Field (0.99)
Abstract A polymer pilot in the 8 TH reservoir in Austria showed promising results. The Utility Factors were below 2 of kg polymer injected / incremental barrel of oil produced (polymer cost are 2 – 4 USD/kg). Furthermore, substantial incremental oil was produced which might result in economic field implementation. The results triggered the planning for field implementation of polymer flooding. To optimize the economics of field implementation, a workflow was chosen ensuring that the uncertainty was covered. 1200 geological models were generated covering a variety of different geological concepts. These geological models were clustered based on the dynamic response into 100 representative geological realizations and then used for history matching. For infill drilling, probabilistic quality maps can be used to find locations. However, injection and production well optimization is more challenging. Introducing probabilistic incremental Net Present Value (NPV) maps allows for selection of locations of injection and production well patterns. The patterns need to be optimized for geometry and operating parameters under uncertainty. The geometry was optimized in a first step followed by operating parameter optimization. In addition, injectivity effects of vertical and horizontal wells due to the non-Newtonian polymer rheology were evaluated. The last step was full-field simulation using the probabilistic NPV map, optimized well distance and operating parameters. The resulting Cumulative Distribution Function of incremental NPV showed a Probability of Economic Success (PES) of 91 % and an Expected Monetary Value of 73 mn EUR.
- Asia > Middle East (1.00)
- South America (0.93)
- Africa (0.93)
- (3 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.46)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (30 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)
Evaluation of Viscosity Loss of Viscosified Brine Solutions Due to Shear Degradation in Distribution System Components
Theriot, Timothy P. (Chevron Energy Technology Company) | Linnemeyer, Harold (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Perdue, Charles (Chevron Energy Technology Company)
Abstract High molecular weight HPAM's tend to be highly shear sensitive. Various components of polymer mixing and distribution systems pose risk to the integrity of HPAMs due to high shear experienced at valves, chokes and other flow control devices. At a minimum, this risk can severely impact chemical EOR operating cost due to polymer degradation and consequential viscosity loss of the injectate. Low-shear, low-cost polymer injection distribution systems have the potential to reduce polymer usage, maintain injection stream viscosity, and enable integration into brownfield facilities. Lower viscosity losses translate into optimized operating and capital cost for CEOR pilot and full field projects. The objective of this work was to determine the equipment (piping), process, and polymer parameters that affect viscosity loss due to shear degradation. In this work, polymers were evaluated from two different vendors. The effects of molecular weight, chemical concentration, and brine salinity on polymer sensitivity to viscosity loss due to shear degradation were investigated. Polymer solutions were either blended on site or purchased pre-blended in synthetic brine solutions. Pumped by a positive displacement, low-shear pump, the solutions flowed through a mass meter and were delivered to a distribution system component at various flow rates. For flow control devices, pressure differentials were adjusted at fixed flow rates. Polymer solution samples were collected upstream and downstream of the tested component. Samples were taken in no-shear sample collectors. Pressure upstream and downstream of the test component and flow rate were recorded during the flow test. Viscosity was measured with a Brookfield viscometer at ambient temperature. When higher concentration solutions were tested, viscosity was measured of diluted samples at target concentration to determine amount of shear degradation as evidenced by viscosity loss. Results indicate that viscosity degradation of polymer solutions does occur in flow control devices and is directly correlated to pressure differential across the pipe device. Internal geometry has little impact on the amount of degradation. Velocity has little impact on the amount of degradation. Polymer molecular weight and structure both affect the amount of degradation due to shear as does solution concentration. Generally, viscosified brine solutions will lose viscosity when flowed through devices with greater than 50 psi differential pressure in the range of 15-50% of initial viscosity. Using more concentrated polymer streams and diluting to target concentration after flow control will reduce the amount of viscosity loss. Based on the laboratory results, design and operating condition, recommendations can be made for polymer injection distribution systems to minimize shear degradation of the flowing viscosified brine stream.
- Asia (1.00)
- North America > United States > Oklahoma (0.28)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- (3 more...)