Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Drilling Fluids and Materials
Abstract Hydraulic fracturing has long been an established well stimulation technique in the oil & gas industry, unlocking hydrocarbon reserves in tight and unconventional reservoirs. The two types of hydraulic fracturing are proppant fracturing and acid fracturing. Recently, a new of hydraulic fracturing is emerging which is delivering yet more enhanced production/injection results. This paper conducts a critical review of the emerging fracturing techniques using Thermochemical fluids. The main purpose of hydraulic fracturing is to break up the reservoir and create fractures enhancing the fluid flow from the reservoir matrix to the wellbore. This is historically achieved through either proppant fracturing or acid fracturing. In proppant fracturing, the reservoir is fractured through a mixture of water, chemicals and proppant (e.g. sand). The high-pressure water mixture breaks the reservoir, and the proppant particles enter in the fractures to keep it open and allow hydrocarbon flow to the wellbore. As for acid fracturing, the fractures are kept open through etching of the fracture face by acid such as Hydrochloric Acid (HCl). An emerging technique of hydraulic fracturing is through utilization of thermochemical solutions. These environmentally friendly and cost-efficient are not reactive as surface conditions, and only react in the reservoir at designated conditions through reservoir temperature or pH-controlled activation techniques. Upon reaction, the thermochemical solutions undergo an exothermic reaction generating in-situ foam/gases resulting in creating up to 20,000 psi in-situ pressure and temperature of up to 700 degrees Fahrenheit. Other reported advantages from thermochemical fracturing include the condensate bank removal (due to the exothermic reaction temperature) and capillary pressure reduction.
- Europe (0.93)
- North America > United States > Texas (0.47)
- Research Report (0.47)
- Overview (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.50)
- Geophysics > Seismic Surveying (0.68)
- Geophysics > Borehole Geophysics (0.68)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- (4 more...)
Preparation and Characterization of Rapid Gelling Agent for Light Hydrocarbons-Based Gelled Fracturing Fluid
Du, Tao (Sinopec Research Institute of Petroleum Engineering) | Chen, Chen (Sinopec Research Institute of Petroleum Engineering) | Feng, Jiangpeng (Sinopec Tech Middle East LLC) | Yao, Yiming (Sinopec Research Institute of Petroleum Engineering)
Abstract Light hydrocarbon-based gelled fracturing fluid is prepared by light oil, and oil-base fracturing fluid is prepared by heavy oil. The gelling agents for them contains different components. There are two kinds of the alkyl chains in gelling agents. They are the high carbon number alkyl chains and the low carbon number alkyl chains. High carbon number alkyl chains interact with each other and creat physical cross-linking. The existence of low carbon number alkyl chains helps to raise the compatibility between gelling agent and solvents. A L18(3) orthogonal tests are carried out and a series of gelling agent samples are synthesized. Range analysis, acidity value analysis and the gelling time are carried out to do experiments. The best concentration of gelling agents is tested by gelling kinetics. The results shows that the viscosity of the fracturing fluid is 75 mPa·s at the condition of 170 s shear rate and 80°C. A new gelling agent sample is synthesized adding a small amount of polyol. This new gelling agent has high viscosity and less gelling time compared to traditional gelling agents. This polyol-included gelling agent is rapid cross-linking gelling agent.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.74)
Testing and Analysis of Potential Damage Factors in Carbonate Reservoir
Xia, X. (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Mou, J. Y. (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Zhang, Y. C. (Research Institute of Petroleum Engineering and Technology, North China Oil & Gas Company) | Li, X. M. (Research Institute of Petroleum Engineering and Technology, North China Oil & Gas Company) | Li, Y. L. (Research Institute of Petroleum Engineering and Technology, North China Oil & Gas Company)
ABSTRACT: The pollution damage of injected water, fracturing fluid and drilling fluid in carbonate reservoir are mainly studied, however, the potential product precipitation damage have been seldom studied. Majiagou Formation in Daniudi gas field mainly has two kinds of rock samples, one with dolomite as the main component and the other with gypsum as the main component. On the one hand, through mineral composition analysis, the main composition of dolomite sample is CaCl2 and MgCl2. Then the ion concentration of acid rock reaction product solution was tested, the results show that the highest Ca content and the highest Mg content in the four groups are lower than the lowest solubility of Ca and Mg, so the products will not reach supersaturated state and precipitate in the solution. On the other hand, for the rock sample dominated by gypsum, the mass of rock plate changes little after water immersion and acid solution corrosion. Then the gypsum samples were subjected to acid displacement, and the surface morphology changes of the samples were observed and the mass changes were measured. The test results showed that the dissolution amount of the samples was small. Therefore, it shows that water and acid will not react with gypsum and will not produce potential precipitation. 1. INTRODUCTION Carbonate reservoir is a part of unconventional oil and gas resources. The key technology of developing carbonate reservoir is acid fracturing. (Arthur B et al., 2010). However, the acid fracturing construction process will also bring negative effects, mainly manifested in the damage to the reservoir. At present, carbonate reservoir damage mainly studies the pollution damage of injected water, fracturing fluid and drilling fluid (Tiner R. L et al., 1974, Moore W. R et al., 1996, and Shi F et al, 2018). Under the action of high differential pressure, some fracturing fluid will leak out and enter the reservoir matrix (Reinicke A et al, 2010, and Fang W et al., 2016). Usually, this part of fracturing fluid is difficult to completely break the gel, which is easy to cause mechanical blockage of matrix pore throat and reduce reservoir permeability. In the process of fracturing fluid invasion, flowback and production, due to the carrying effect of fluid on reservoir particles, when the particles migrate to the hole roar with small radius, they will be blocked, resulting in a certain degree of damage to reservoir permeability (Gray D. H et al, 1996, Wilson M. J ,2014, Q. Zhang et al, 2014, and AlMubarak T. A, 2015).
- Geology > Mineral > Sulfate > Gypsum (0.91)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.48)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
A New Acid Fracturing Fluid System for High Temperature Deep Well Carbonate Reservoir
Gao, Ying (Research Institute of Petroleum Exploration & Development, CNPC, RIPED-Langfang Branch, CNPC) | Lian, Shengjiang (Research Institute of Petroleum Exploration & Development, CNPC) | Shi, Yang (Research Institute of Petroleum Exploration & Development, CNPC) | Yang, Xianyou (Research Institute of Petroleum Exploration & Development, CNPC) | Zhou, Fujian (China University of Petroleum) | Xiong, Chunming (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Futao (Research Institute of Petroleum Exploration & Development, CNPC) | Han, Xiuling (Research Institute of Petroleum Exploration & Development, CNPC) | Zhang, Na (Research Institute of Petroleum Exploration & Development, CNPC)
Abstract When a high temperature deep well carbonate reservoir is stimulated with conventional acid fluid, some unfavorable behaviors often occur, such as high acid-rock reaction rate, short effective reaction distance of live acid, failure of acid etching in the acid fracture front, and serious corrosion to downhole string. This paper presents a new acid fracturing fluid system. This system consists of the acid-generator SGA-E, the optimized polymeric thickener CHJ-1 and the cross-linking agent SJL-1. With the performance of water-based fracturing fluid, this system can be used as prepad during acid fracturing. Moreover, this system has weak or no acidity at low temperature and slow release of Hat high temperature (120-150°C) in fractures, Its ultimate effective acid concentration is about 8% which is capable of effective acid etching. During pumping, this system shows less corrosion to the string, so few corrosion inhibitor is required. This new acid fracturing fluid system can achieve effective acid etching of a whole fracture, so as to increase the stimulated reservoir volume.
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Well Completion > Acidizing (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.99)
- (2 more...)
Abstract Acid fracturing is the most recognized and successful reservoir stimulation technique for conventional carbonate formations. Resulting fracture conductivity is the key parameter that controls final well productivity, while the competing diffusion and reaction phenomena control the "vital" acid coverage along the full areal extension of the fracture. However, not all reservoirs lend themselves to the same fracture geometry and conductivity, and this is where the "Unified Fracture Design" (UFD) approach is irreplaceable. Classic fracture design optimization with the UFD approach involves the maximization of well productivity. For any mass of proppant to be injected as part of the treatment, the algorithm determines the unique fracture length and width (with height as a parasitic variable) that will provide the maximum productivity index. In this paper we recast the UFD approach for specific acid fracturing applications, where the maximum productivity index is now determined as a function of the optimum fracture geometry determined for any volume of injected acid. The optimum fracture width profile is then obtained by solving the convection-diffusion equation for acid propagation, and subsequently used to study the required acid coverage through the fracture as a function of such optimum fracture width profile. Acid reaction retardation plays a crucial role in ensuring proper acid coverage throughout the optimum fracture length, and this paper focuses on the two major reaction retardation fluid systems: Acid-Internal Emulsions (AIE) and gelled acids. The workflow presented in this paper provides the basis for designing optimum acid fracturing treatments as a function of the volume of acid injected, the acid injection rate and the selected acid retardation method.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.31)
Dominant Considerations for Effective Hydraulic Fracturing in Naturally Fractured Tight Gas Carbonates
Arukhe, J.O. (Schulich School of Engineering, University of Calgary) | Aguilera, R. (Schulich School of Engineering, University of Calgary) | Harding, T.G. (Schulich School of Engineering, University of Calgary)
Abstract This study examines the results of laboratory work to establish rock strength data, acid solubility, fracture fluid selection and mineral identification of a fractured tight gas carbonate reservoir. Basic to a successful acid fracture design are acid etching and rotating disc tests which show for a given acid system, conductivity at a given stress (etched width or how much rock is eaten away) and parameters necessary to determine acid reaction rate, reaction order, rate constant and energy of activation at a given temperature. These tests address the measurement of mass transfer and diffusion with or without leak off in carbonates, and also enable the prediction of reactivity versus temperature for various acid strengths. Dynamic fluid losses are measured experimentally and laboratory data are converted to an estimate of in-situ leak off. The leak off profile and wall building coefficients enable a consideration of fluid loss additives for fracturing fluids to build up pressure for fracture opening. In the fracture conductivity tests, closure stress is applied across a test unit for sufficient time to allow the proppant bed to reach a semi-steady state condition while test fluid is forced through the bed. At each stress level, pack width, differential pressure, and average flow rates are measured as fluid is forced through the proppant bed. The proppant pack permeability and conductivity are then evaluated and compared. Introduction A discussion of dominant considerations for effective hydraulic fracturing in naturally fractured tight gas carbonates is presented along with the results of laboratory work to establish rock mechanical properties data, acid solubility, fracture fluid selection and mineral identification for a selected naturally fractured tight gas carbonate reservoir. The carbonates under consideration are located in the Western Canadian Sedimentary Basin (WCSB) in what is usually known as the "Deep Basin" of Alberta (Figure 1). The core samples studied come from the Savannah Creek field (Figures 2) and correspond to the Rundle group Mississippian Mount Head and Livingston carbonates (Figure 3). These carbonates were deposited in a shallow marine ramp setting. These are upward-shallowing cycles ranging from crinoid / bryozoan shoals to lagoonal mud facies. The reservoirs comprise dolomudstones and wackstones with an average pay of approximately 35 m. Reservoir zones can be discontinuous due to lateral facies changes and minor faulting. The presence of natural fractures in the tight formations considered in this research is corroborated by cores and thin sections. Notice the presence of calcite cemented fractures in the whole core and plugs displayed in Figure 4. The thin section shown on Figure 5 presents calcite-filled fractures (pink strip running from upper left to lower right) that have been re-fractured (thin blue streak). The thin section work corroborates that it possible to re-fracture existing healed fractures. General Considerations There are many mechanisms that contribute to the final created geometry (fracture height, fracture width, hydraulic or created fracture length or effective fracture length)2–8 and its evolution in naturally fractured tight gas carbonates. Pump rate, volume injected, fluid viscosity, fluid loss and proppant scheduling combine with static and dynamic rock properties.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > Texas > Harris County > Houston (0.28)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.45)
- North America > United States > Texas > Permian Basin > Delaware Basin > Sullivan Field (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
- Well Drilling > Pressure Management > Well control (1.00)
- 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)
- (5 more...)
Abstract Acid fracturing is the commonly applied stimulation technique in low permeability carbonate reservoirs. Achieving adequate fracture length is challenging due to the fast acid spending rates and high leakoff resulting from these treatments. The problem is exacerbated when treating high temperature formations and compounded with the difficulty of providing adequate corrosion control. In addition, the health, safety and environmental implications of acid handling at surface and shortage of hydrochloric acid in certain regions must also be considered to fully appreciate the challenges imposed by acid fracturing operations. The industry has successfully tried different methods to deal with each, or a combination, of these problems. However, none of them fully address all of the challenges discussed. This paper describes a detailed laboratory evaluation of an innovative, solid-based acid fracturing system to address the above-stated limitations of conventional systems. Extensive laboratory studies, which included acid capacity, etching patterns, conductivity measurements, solubility of reaction products, reaction kinetics, and corrosion tests were conducted at temperatures up to 300F. The studies demonstrate that the new system results in heterogeneous etching and wormholing in both limestone and dolomite rocks. In addition, this material exhibits increased fluid efficiency as compared to conventional acid fracturing systems, with the potential of achieving heterogeneously etched half-lengths that approach the length-scale achieved with traditional proppant fracturing operations. This paper will demonstrate the applicability of the novel solid-based acid fracturing treatment. Additionally, the paper will highlight some of the unique challenges of placing a solid-based acid system in the formation and the engineering steps taken to mitigate these challenges. Finally, application limitations of the system will be discussed. Introduction Hydrochloric acid (HCl) is widely used to stimulate oil and gas wells in carbonate formations, to improve the rate of hydrocarbon production. It is also used to stimulate water injection wells and disposal wells, to increase the formation uptake of the injected fluids. Oil and gas wells producing from carbonate formations are generally acidized by matrix acidizing or acid-fracturing treatments. In matrix acidizing treatments, a relatively small volume of acid is used to improve the conductivity of the area adjacent to the wellbore. In acid fracturing treatments, however, the acid is used to etch a created fracture, which penetrates deep into the formation. In such treatments the injected acid is consumed by either reacting with the fracture walls or leaking off through the walls of the fracture then reacting with the carbonate matrix.
- Asia (1.00)
- North America > United States > Texas > Harris County > Houston (0.28)
- Research Report > New Finding (0.93)
- Research Report > Experimental Study (0.66)
- North America > United States > Texas > Permian Basin > Midland Basin > Good Field (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- (5 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Acidizing (1.00)
- (2 more...)
Abstract Due to their thermal stability, organically cross-linked gels have been used to control water production in high temperature applications. Most of these gels consist of a polyacrylamide-based polymer and an organic cross-linker. Polyethyleneimine (PEI) has been used as an organic cross-linker for polyacrylamide-based copolymers. Recent work indicated that PEI can form ringing gels with polyacrylamide homopolymers (PAM). However, no study reported on the kinetics of PAM/PEI gels. The gelling system examined in the present study is based on a PAM cross-linked with PEI. This paper will show for the first time the possibility of cross-linking polyacrylamide with PEI at high temperatures and pressures. Therefore, the gelation time of the PAM cross-linked with PEI at high temperatures up to 285F (140C) and pressures up to 435 psi (30 bars) was measured. The effects of polymer concentration, cross-linker concentration, temperature, salinity and the initial degree of hydrolysis of the polymer on the gelation time were examined in detail. All measurements were conducted in the steady shear mode at low shear rates using an Anton-Paar high temperature/high pressure viscometer. C13 Nuclear Magnetic Spectroscopy (C13 NMR) was extensively used to relate gelation time to changes in the structure of the polymer and hence, explain the variation in the gelation time in terms of the system chemistry. Thermally stable gels were obtained by cross-linking PEI and PAM at high temperatures (120C) for at least 2 weeks. The activation energy of this system at high temperatures in distilled water was found to be 71.3 kJ/mol. The addition of sodium ions increased the activation energy to 88 kJ/mol. Introduction Water production is a serious problem in the oil producing operations. Additional costs are imposed by processing, treating and disposing unwanted water. Of the available remediation techniques, chemical methods using polymer gels have been widely applied. The success rate of these chemical treatments depends, among other factors, on the understanding of gelation kinetics, compatibility with reservoir fluids and gel stability. Polymer gels have been used to reduce water production by reducing the permeability of the reservoir rock to water unaffecting that to oil through disproportionate permeability reduction (DPR) or totally blocking the pore space of the water producing zone in both matrix and fractures. Polymer gels are generally classified into two categories based on the nature of polymer/cross-linker bonding chemistry. The first type is inorganic gel systems based on ionic interactions between a trivalent cation and the carboxylate groups on the partially hydrolyzed polyacrylamide chain (PHPA). Due to the fact that ionic bonding between the PHPA and the cross-linker weakens at high temperatures, this class has a low thermal stability range. The second class of polymer gels is based on covalent bonds between the cross-linker and the acrylamide-based polymer. High temperature applications require the use of thermally stable covalently bonded systems. However, these covalent bonds do not guarantee long term stability. Literature reports highlight the importance of using a thermally stable polymer. Polyacrylamide-based polymers are known to hydrolyze at high temperatures causing gel syneresis (expulsion of water out of the gel structure due to over cross-linking), especially in brines with high contents of Mg and Ca where polymer precipitation may also occur. Therefore, more thermally stable monomers are copolymerized with the acrylamide polymer to minimize excessive hydrolysis. Literature Review on PEI Cross-linked Gels PEI is reported in literature to form thermally stable gels with polyacrylamide-based copolymers. For example, copolymers of polyacrylamide tert-butyl acrylate (PAtBA), mixtures of acrylamide and acrylamido-2-methylpropane sulfonic acid (AMPSA), mixtures of acrylamide, AMPSA and N, N-dimethyl acrylamide can be cross-linked with PEI through covalent bonding. Gelation is believed to rely on two main mechanisms at high temperatures. Namely, the nucleophilic substitution of the groups copolymerized with the acrylamide . The second mechanism is based on the transamidation reaction between the PEI nitrogens and the amide groups on the base polymer chain. These PEI cross-linked systems have been extensively examined in porous media.
- Asia (0.94)
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.28)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Abstract A number of oilfield operations are controlled by use of delayed chemical reactions. Breakers for fracturing and gravel packing fluids, filter-cake cleanup treatments in horizontal wellbores, and retarded acidizing are just a few examples. However, these reactions are best described as slow or gradual reactions and not truly delayed chemical reactions. The gradual degradation of a fracturing-fluid viscosity or a drill-in fluid filter cake can take place over a matter of hours. But even greater benefit could be realized in completion operations if events could be delayed for days and triggered at the desired time. The delayed acid-releasing system, which is based on orthoesters in combination with alkaline inhibitors, can remain seemingly inactive for days before becoming strongly activated. The acid that is generated can then be used to break polymers, remove filter cakes, or activate other chemical processes. The paper describes the chemical principle on which the system is based, and discusses a number of applications that could be improved and economized with the long-term delay and scheduling flexibility offered by the chemical-trigger system. Also presented are the current operating envelope and plans for future widening of the temperature and delay-time ranges. A number of new testing procedures used to prove the system's unique properties are reviewed in the paper. Introduction and Background Many applications of chemicals in the oil field are improved when the chemical reactions are delayed on a controlled basis. Classic cases for delayed reactions are the breakers used with fracturing fluids and gravelpacking fluids for viscosity reduction. The breaker chemicals are added to the polymer system at the surface but the breaking of the polymer is only desirable after the viscous gel has transported the proppant or gravel downhole. After treating fluids are downhole, it is desirable to have the polymer broken so it is less damaging to the well's productivity. When acids, oxidizers, or enzymes are used for this purpose, they gradually break the polymer down, but at a rate that enables a useful service life from the polymer. Although encapsulation and other techniques are used to extend the break delay, the service life is usually measured in a matter of a few hours. The filter-cake cleanup treatments used in horizontal wells also benefit from some delay. At a minimum, the delay enables the spotting of the cleanup treatment across the entire interval before fluid loss occurs. A delay of 1 to 2 hours is sufficient for this purpose. In a gravel-packed lateral, it may be desirable to place the cleanup system in the gravel pack carrier fluid where a delay of 2 to 8 hours would allow the placement of the gravel pack without large fluid losses. Carboxylic acid ester systems have been used in this application to gradually generate acid over a period of hours. But only about 1 to 2% of the bridging particles in the filter cake need be dissolved before the fluid-loss rate starts increasing dramatically. If the rate of removal has to be limited to a few percent in 8 hours, it would take 2 weeks to completely remove the filter cake. The desired delay time is not necessarily limited to 8 hours, however. It would be of significant value to be able to remove the gravel-pack service tool and install the completion with the well's fluid level static. Once the completion is landed, complete removal of the filter cake would then pose no problems. This same problem is encountered with fluid-loss control pills that are spotted in vertical wells after a gravel pack or frac-pack. Getting the service tools out of the hole and the completion in place without fluid loss problems is generally desirable. This process may take 2 days, after which the removal of the pill is required for efficient wellbore cleanup. Breaker technology to date has not been able to offer such long delays in break times.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
Abstract Historically, enzymes have been used in the oil industry both for improving the characteristics of a range of biopolymers employed in the industry and as breakers for biopolymer gels. Until recently, the use of enzymes downhole was limited to gel breaking applications where suitable enzymes are used to break down or degrade a specific gel. In this case, the enzyme is used to remove a chemical which is no longer required, such as biopolymers in filter cakes following drilling or in fracing gels after the frac has occurred. More recently, enzymes have been used to produce useful chemicals in-situ. An enzyme-based method has already been reported which generates organic acids for a variety of acidizing applications such as matrix acidizing, the stimulation of natural fracture networks, damage removal over long horizontal intervals or gel breaking. The generation of acid in-situ following placement of the fluid ensures the even delivery of acid over the whole of the treated zone. The use of enzymes for generating useful oilfield chemicals has now been extended. Examples in the use of enzymes for the in-situ generation of minerals, gels and resins with potential for use in applications such as water shut off and sand consolidation are now reported. P. 467
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
- 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)
- Well Completion > Acidizing (1.00)
- (3 more...)