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Abstract High molecular weight partially hydrolyzed polyacrylamides (HPAM), have been shown to effectively increase oil recovery of medium viscous and heavy oil. Using a rheometer, these polymers show shear thinning behavior. However, determining the apparent viscosity from coreflood tests for different frontal velocities, an increase in the apparent viscosity is observed. This apparent increase is attributed to the visco-elastic properties of the polymers. In this paper, a set of laboratory experiments has been performed for cores similar to the rock in the 8 Torton Horizon (8 TH) of the Matzen Field in Austria. The results show that for the conditions in the near-wellbore region of the reservoir, an increase in apparent viscosity is expected. In addition, the relationship of velocity versus apparent viscosity for pre-sheared polymers was investigated. Dependent on the amount of pre-shearing, the apparent viscosity was significantly decreased. For different polymer concentrations, the apparent viscosity versus velocity of the pre-sheared polymers was almost identical. A polymer injection pilot performed in the 8 TH in the Matzen Field in Austria confirmed that shearing of the polymer solution in the near-wellbore occurs for injection below the fracturing pressure. Above the fracturing pressure, the flow velocities are significantly decreased owing to the large surface area of the fracture. Hence, polymer injection should be performed above the fracturing pressure to improve sweep efficiency.
- Research Report > Experimental Study (0.48)
- Research Report > New Finding (0.34)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
A New Approach to Deliver Highly Concentrated Surfactants for Chemical Enhanced Oil Recovery
Barnes, Julian (Shell Global Solutions International B.V.) | Dirkzwager, Henk (Shell Global Solutions International B.V.) | Dubey, Sheila (Shell Global Solutions US Inc.) | Reznik, Carmen (Shell Global Solutions US Inc.)
Abstract A novel process has been developed to produce highly concentrated forms of surfactants suitable for chemical Enhanced Oil Recovery (cEOR) in the form of powders. Powders are advantageous for cEOR applications because, through their lower water content (typically 3%), they have the potential to reduce transportation costs and simplify the logistics of transporting surfactants from the production location to field locations. Data are presented showing the properties and advantages of powder cEOR surfactants and how they compare to the more conventional liquid form of surfactants. The manufacturing route first involves the preparation of higher active matter liquids (around 70% active) that are subsequently converted into powders using dedicated, standard mixing equipment, the same type used for the manufacture of laundry powders. In this work, several surfactant powders were produced on a pilot plant scale using a number of internal olefin sulfonates to establish applicability for different cEOR projects. The blended powders are agglomerates of surfactant and sodium carbonate and were made both with and without polymer (termed ASP and AS powders respectively). The AS and ASP powders were found to easily dissolve in brine, eliminating the need for special field equipment for dissolution, and gave faster polymer dissolution in water compared with dissolving the polymer as a separate component. The powders have acceptable physical properties that facilitate transport and dispersion in brine and have been tested at desired ratios of surfactant to alkali. This paper also outlines how higher active matter liquids can be manufactured to avoid gel phases, improve their handleability and lower their viscosity. The surfactant powder approach has the potential to substantially reduce costs for full scale chemical EOR projects where large chemical volumes are manufactured, transported, stored and injected.
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.89)
Study of Surfactant-Polymer Flooding in Heavy Oil Reservoirs
Feng, Anzhou (China University of Petroleum) | Zhang, Guicai (China University of Petroleum) | Ge, Jijiang (China University of Petroleum) | Jiang, Ping (China University of Petroleum) | Pei, Haihua (China University of Petroleum) | Zhang, Jianqiang (China University of Petroleum) | Li, Ruidong (China University of Petroleum)
Abstract As the alkali in alkaline-surfactant-polymer (ASP) flooding often causes the difficult problems of scaling and emulsification, surfactant-polymer (SP) flooding was proposed for enhancing heavy oil recovery in China. However, it is difficult to reduce the interfacial tension (IFT) to an ultra-low value without alkali for the traditional chemical system. This paper presents a type of betaine surfactant which has an excellent ability to reduce oil/water IFT at low concentration without alkali, and alkali lignin with low-price was compounded as a sacrificial agent to reduce the adsorption. Finally, sandpack flooding tests were conducted to examine the effectiveness of enhanced oil recovery by compound chemical system containing polymer, betaine and alkali lignin. The results showed that the IFT reduced to 0.001 mN/m or less at a betaine concentration range of 0.01wt% to 0.1wt% without alkali, meeting the requirements of SP flooding; the dynamic adsorption test showed that of the adsorption amount reduced approximately 40% when the mass-ratio of alkali lignin and betaine was 1 to 7.5; moreover, the polymer added into compound surfactant system accelerated the reduction of the oil/water IFT. Sandpack flooding tests indicated that the injected chemical system containing polymer, betaine and alkali lignin after water flooding could enhance oil recovery by 13%~20%, which was significantly higher than that of polymer flooding under the same conditions.
- Asia > China (1.00)
- North America > United States (0.93)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Asia > China > East China Sea > Bohai Basin > Jiyang Basin > Gudao Field > Guantao Formation (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Improvement of Silicate Well Treatment Method by Nanoparticle Fillers
Lakatos, I.. (Research Institute of Applied Earth Sciences, University of Miskolc, Miskolc-Egyetemvaros, Hungary) | Lakatos-Szabó, J.. (Research Institute of Applied Earth Sciences, University of Miskolc, Miskolc-Egyetemvaros, Hungary) | Szentes, G.. (Research Institute of Applied Earth Sciences, University of Miskolc, Miskolc-Egyetemvaros, Hungary) | Vágó, Á.. (Hunfarian Oil and Gas Plc., E&P Division, Kiskunhalas, Hungary)
Abstract The divers silicate technologies have been used more than 120 times in Hungary, Germany, Serbia and Oman for reservoir conformance improvements including water shut-off and profile correction in oil and gas wells, restriction of gas conning in oil reservoirs, blocking of gas leakage in gas storage and restriction of CO2 migration in a collapsed well. The advanced methods based on simultaneous application of polymers, urea, humates, etc. recognizing that the pure silicate gels have disadvantageous properties under reservoir conditions. The present efforts were focused on replacement of some additives in gel-forming solutions; meanwhile the efficiency of the method remained the same or even better under various formation conditions. Based on earlier results, it was proved that addition of water-soluble polymers to silicates improved significantly the stability and flexibility of such gels. Beside the beneficial effects, however, the polymer-containing silicate solutions may also have some drawbacks to placement and in-situ dispersion of treating fluids. These difficulties can be eliminated by replacing polymers with nanomaterials. The detailed laboratory studies focused on polymer free, but SiO2 and Al2O3 nanoparticle containing silicate solutions. Results of laboratory study of gelation mechanism, rheological properties, flow behavior, and nanoparticle sizing served to draw fundamental conclusions. It has been shown that these nanomaterials can replace completely the polymers, they are compatible with even low permeability porous, and fractured media, and less pH-controlling agent is necessary to catalyze gelation. Recently, the efficient and flexible silicate technologies arouse high interest in oil and gas production. Their environment friendly solutions are particularly appreciated. Replacing the often-questionable synthetic polymers in gel-forming solutions with nanomaterials is the final step toward to use harmless chemicals in absolute sense. Based on the laboratory tests the silicate/nonmaterial method was tailored to oil producers operating in the largest Hungarian oil field. The pilot tests will be carried out in 2013. Combining silicates and nanomaterials, new and efficient method was developed for water shutoff and profile correction in various oil and gas fields and that may open new vistas in improvement of well performance of both producers and injectors.
- North America > United States (0.69)
- Europe > Norway (0.67)
- Europe > Hungary (0.67)
- Asia > Middle East > Oman (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lista Formation (0.99)
- (2 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- (5 more...)
Application of Injection Fall-Off Analysis in Polymer flooding
van den Hoek, P. J. (Shell Global Solutions International B. V.) | Mahani, H.. (Shell Global Solutions International B. V.) | Sorop, T. G. (Shell Global Solutions International B. V.) | Brooks, A. D. (Shell Global Solutions International B. V.) | Zwaan, M.. (Shell Global Solutions International B. V.) | Sen, S.. (Shell Global Solutions International B. V.) | Shuaili, K.. (Petroleum Development Oman LLC) | Saadi, F.. (Petroleum Development Oman LLC)
This has a significant impact on pressure decline signature as exhibited during Pressure Fall-Off (PFO) tests. Therefore, applying a different PFO interpretation method, compared to conventional approaches for Newtonian fluids is required. This paper presents a simple and practical methodology to infer the in-situ polymer rheology from PFO tests performed during polymer injection. This is based on a combination of numerical flow simulations and analytical pressure transient calculations, resulting in generic type curves that are used to compute consistency index and flow behavior index, in addition to the usual reservoir parameters (kh, faulting, etc.) and parameters relating to (possible) induced fracturing during injection (fracture length and height). The tools and workflows are illustrated by a number of field examples of polymer PFO, which will also demonstrate how the polymer bank can be located from the data.
- North America > United States (1.00)
- Europe (0.69)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics (1.00)
- (2 more...)
Abstract Clay swelling has been recognized as one of the main mechanisms of formation damage during various well operations. Many researchers have extensively investigated the effects of many parameters such as pH, and salinity of water-based fluids on montmorillonite swelling behavior. However, studies of supercritical carbon dioxide (CO2) interactions with montmorillonite clay have been limited. These interactions can affect injectivity during enhanced oil recovery (EOR) operations. Therefore, the main objective of this study is to investigate the swelling behavior of montmorillonite in supercritical CO2 as a function clay original state: dry or hydrated. The swelling behavior of both Ca-montmorillonite and Na-montmorillonite clays in distilled water and supercritical CO2 was investigated at temperature values of 25°C. Nearly 1 g of each clay was soaked in 10 g of distilled water at the desired temperature and atmospheric pressure for 24 hours. Then, these swollen clays were soaked in supercritical CO2 for 24 hours at the desired temperature and at nearly 2,000 psi. Absorbed water content and increase in interlayer space, after each soaking stage, were determined using nuclear magnetic resonance (NMR) and X-ray diffraction (XDR). Results based on this study have indicated that the swelling degree of Na-montmorillonite was higher than that of Ca-montmorillonite after being soaked in distilled water for 24 hours. After absorbing distilled water at 25°C, the (001) d-spacing of dry Ca-montmorillonite of 14.95 Å increased by 25%, while the (001) d-spacing of dry Na-montmorillonite of 11.67 Å increased by 60.4%. The (001) d-spacing of these swelled clays decreased after they were soaked in supercritical CO2. For example, the (001) d-spacing of hydrated Na-montmorillonite of 18.72 Å decreased by nearly 25% after soaking in supercritical CO2for 24 hours at 25°C and 2,000 psi. This paper presents new interesting interaction results of shrinkage, swelling behavior and structure change of montmorillonite clay after interaction with supercritical CO2, which are important for different EOR operations.
- Asia > Middle East (0.69)
- North America > United States > Oklahoma (0.16)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Clay swelling has been recognized as one of the main mechanisms of formation damage during various well operations. Many researchers have extensively investigated the effects of many parameters such as pH, and salinity of water-based fluids on montmorillonite swelling behavior. However, studies of supercritical carbon dioxide (CO2) interactions with montmorillonite clay have been limited. These interactions can affect injectivity during enhanced oil recovery (EOR) operations. Therefore, the main objective of this study is to investigate the swelling behavior of montmorillonite in supercritical CO2 as a function clay original state: dry or hydrated. The swelling behavior of both Ca-montmorillonite and Na-montmorillonite clays in distilled water and supercritical CO2 was investigated at temperature values of 25°C. Nearly 1 g of each clay was soaked in 10 g of distilled water at the desired temperature and atmospheric pressure for 24 hours. Then, these swollen clays were soaked in supercritical CO2 for 24 hours at the desired temperature and at nearly 2,000 psi. Absorbed water content and increase in interlayer space, after each soaking stage, were determined using nuclear magnetic resonance (NMR) and X-ray diffraction (XDR). Additionally, environmental scanning electron microscope (ESEM) analysis was used to explore the effect of liquid-like CO2 on clay structure of both dry and hydrated Ca and Na- montmorillonite clays. Results based on this study have indicated that the swelling degree of Na-montmorillonite was higher than that of Ca- montmorillonite after being soaked in distilled water for 24 hours. After absorbing distilled water at 25°C, the (001) d- spacing of dry Ca-montmorillonite of 14.95 Å increased by 25%, while the (001) d-spacing of dry Na-montmorillonite of 11.67 Å increased by 60.4%. The (001) d-spacing of these swelled clays decreased after they were soaked in supercritical CO2. For example, the (001) d-spacing of hydrated Na-montmorillonite of 18.72 Å decreased by nearly 25% after soaking in supercritical CO2 for 24 hours at 25°C and 2,000 psi. This paper presents new interesting interaction results of shrinkage, swelling behavior and structure change of montmorillonite clay after interaction with supercritical CO2, which are important for different EOR operations.
- Asia (0.69)
- North America > United States > Oklahoma (0.30)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract In preparation of a gelant solution for making crosslinked polymer gels for water shutoff applications, unpublished experiments and chemical intuition suggest that, unless hydrolyzed polyacrylamide (HPAM) polymer is fully hydrated before addition of crosslinker, the final gel will have lower than optimum mechanical strength, presumably because polymer chains need to be fully unfolded before proper crosslinking can occur. When using dry polymer, which is usually the lowest cost form on a delivered basis, this may require more equipment and a large tankage footprint. However, if conditions exist where crosslinker can be added to wetted but not fully hydrated polymer, then dry polymer and crosslinker can be blended in a small continuous flow unit, with full hydration occurring as the gelant flows downhole prior to gelation. We have evaluated gel strengths of "flowing" gels for water shut off in natural fractures and other non-matrix features as a function of time of addition of crosslinker relative to time of hydration of polymer. Gels were prepared from moderately high molecular weight HPAM crosslinked with chromium(III) acetate (CrAc) or polyethyleneimine (PEI). Crosslinker was added after either (1) initial wetting of solid polymer particles or (2) complete dissolution of the polymer. Gel strengths were determined using a common qualitative coding system. Comparisons were made for gels prepared in an identical manner, except for the timing of crosslinker addition. Samples were prepared either in fresh water or 4% NaCl brine and then hydrated either at an ambient temperature or 122 °F. Gelant viscosity and crosslink time were also characterized with a viscometer. Results of this work demonstrate that for most field applications using CrAc as crosslinker, optimum quality gel can be obtained using dry polymer and a small continuous mixing system for initial wetting of the polymer, after which the crosslinker can be added to the polymer solution on-the-fly. This practice can decrease the footprint and cost of large volume flowing gel treatments.
- 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)
- (21 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Enhanced Oil Recovery Using Nanoparticles
Ogolo, N. A. (Petroleum Technology Development Fund Research Group, Institute of Petroleum Studies, University of Port Harcourt, Rivers State, Nigeria) | Olafuyi, O. A. (Petroleum Technology Development Fund Research Group, Institute of Petroleum Studies, University of Port Harcourt, Rivers State, Nigeria) | Onyekonwu, M. O. (Petroleum Technology Development Fund Research Group, Institute of Petroleum Studies, University of Port Harcourt, Rivers State, Nigeria)
Abstract Nanoparticles have been speculated as good in-situ agents for solving reservoir engineering problems. Some selected types of nanoparticles that are likely to be used include oxides of Aluminium, Zinc, Magnesium, Iron, Zirconium, Nickel, Tin and Silicon. It is therefore imperative to find out the effect of these nanoparticle oxides on oil recovery since this is the primary objective of the oil industry. These nanoparticles were used to conduct EOR experiments under surface conditions. Distilled water, brine, ethanol and diesel were used as the dispersing media for the nanoparticles. Two sets of experiments were conducted. The first involved displacing the injected oil with the nanofluids. In the second case, the sands were soaked in nanofluids for 60 days before oil was injected into the system and displaced with low salinity brine. Generally, using nanofluids to displace injected oil produced a better result. Results obtained from the experiments indicate that Aluminium oxide and Silicon oxide are good agents for EOR. Aluminium oxide nanoparticle is good for oil recovery when used with distilled water and brine as dispersing agents. For the use of ethanol, Silane treated Silicon oxide gave the highest recovery in all the conducted experiments while hydrophobic Silicon oxide in ethanol also yielded good results. Aluminium oxide reduces oil viscosity while Silicon oxide changes rock wettability in addition to reduction of interfacial tension between oil and water caused by the presence of ethanol. For the use of diesel as a nanoparticle dispersing fluid, because diesel and crude oil are miscible, the actual crude oil recovery cannot be determined but the overall result with Aluminium, Nickel and Iron oxides appears good. Magnesium oxide and Zinc oxide dispersed in distilled water and brine cause permeability problems. Generally, distilled water lowers oil recovery. This emphasizes the significant role a fluid plays as a nanoparticle dispersing agent in the formation because it can contribute positively or negatively in oil recovery apart from the effect of the nanoparticles.
- Europe (0.93)
- North America > United States > Texas (0.29)
- Asia > Middle East > Saudi Arabia (0.28)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.68)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.67)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.50)
Abstract Excess water production can lead to premature operating cost escalation or well abandonment in conventional oil and gas reservoirs. This can also happen in tight and source rock production in cases where hydraulic fractures connect the stimulated well to a water source, especially with low hydrocarbon production rates. Polymer gel technology has been successfully used in controlling water influx with no or minimal damage to hydrocarbon production in conventional naturally fractured or hydraulically fractured reservoirs. However, there has been no public description of polymer gels tailored for shutting off water flow from fractures with the very narrow apertures expected in tight and source rock reservoirs. Established water shutoff polymer gels like those based on hydrolyzed polyacrylamide (HPAM) crosslinked with chromium(III) acetate will exhibit high extrusion pressure while penetrating the expected narrow aperture fractures present in source rock and tight gas reservoirs. This is likely to cause significant limitations to their application in unconventional resources, thus giving rise to this study on development of a polymer gel system that can be used for shutting off water flow from narrow aperture fractures. In addition to improved placement rheology, an improved gel system should ideally be composed of components that are less of an environmental concern than metal ion-crosslinked systems. This report focuses on developing a low viscosity, environmentally benign polymer gel system based on high molecular weight (HPAM), as the polymer component and a commercial grade polyamine containing polyethyleneimine (PEI) as an organic crosslinker. Gelant and gel samples of different concentration ratios of polymer and crosslinker were prepared, subjected to rheological measurements and classified using a semi-quantitative gel strength coding to find optimum concentration ratios that gave good gels. Results indicate that the HPAM/PEI system can provide a gelant with lower initial viscosity, higher final gel strength and potential greater stability at higher temperatures than current metal ion crosslinked gel systems.
- North America > United States > Texas (0.46)
- North America > United States > Louisiana (0.29)
- North America > United States > Oklahoma (0.28)
- North America > Canada > Alberta (0.28)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.41)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (2 more...)