Abstract: Wellbore strengthening has become one of the important drilling fluid technologies for enhancing the pressure bearing capacity of formations. The micro-mechanisms, simulation test methods and development of new materials presently in China all require extensive study. Methods of controlling mud losses into fractured formations with dense pressure bearing zone are investigated based on the basic principles of force chain network structure analysis of micro particle mechanics. Fine characterization parameters for the characteristics of wellbore strengthening materials are presented in the paper. A dense pressure bearing plugging zone with "strong force chain network structure" can be formed with rigid particles, elastic particles and fibrous materials through sizing of particles (type and size) and optimization of particle concentration. Using self-developed simulation test device, wellbore strengthening with drilling fluid plugging materials was studied through simulation test. The experimental results have proved that the new wellbore strengthening material developed is not only able to effectively plug micro-fractures to form a dense pressure bearing zone to seal off the fractures, it also enhances pressure bearing capacity of the formation when the widths of the fractures are opened to the designed width by the wellbore strengthening material.
Abstract: Two key issues encountered in hot dry rock drilling are high temperature and lost circulation. This paper introduces the analyses made on the geological characteristics of hot dry rock and the drilling fluid technology required for drilling the hot dry rock, and surveying performed on drilling fluid system for hot dry rock drilling and the field applications of the drilling fluids. New technologies for hot dry rock drilling found both in China and abroad suitable for different formation conditions are summarized. Problems found of the hot dry rock drilling fluid are also presented with the prospecting for the development of the technology. Presently, polymer sulfonate water base drilling fluid is mainly used for hot dry rock drilling, however, some other drilling fluids, such as high temperature foam mud, aerated drilling fluid, liquefied nitrogen fluid etc. are also prospective fluids for hot dry rock drilling. These new hot dry rock drilling fluids have been successfully applied in field operation with good results; they impose low formation damage, and are high temperature and salt resistant. Other advantages include good adaptability to different formation conditions and performance in environment protection, all of which represent the future of the development of the hot dry drilling fluid technology.
Abstract: High efficiency hydrate inhibitors are generally used in offshore deep water drilling to prevent the formation of hydrate which is able to plug pipelines and subsea blowout preventers (BOPs). In laboratory experiment, the decomposition of sI hydrate by glycerol triacetate and the synergy between glycerol triacetate and NaCl were studied at 4℃ and 20 MPa, using NPT ensemble molecular dynamics. The experimental results showed that the hydrogen bonds between glycerol triacetate and water destroyed the cage structure of the hydrate molecules. NaCl is able to reduce the activity of water, thereby destroying the equilibrium conditions under which the hydrate is stabilized. The decomposition of hydrate mainly takes place in the first 50 ps; the diffusion coefficient of the hydrate molecules under the co-action of glycerol triacetate is greater than the diffusion coefficient of the hydrate molecules under the action of glycerol triacetate alone. At 4℃ and 20 MPa, the reaction equilibrium pressure of 0.5% glycerol triacetate is 18.75 MPa, and that of 0.5% glycerol triacetate + 10% NaCl is 18.91 MPa, verifying the hydrate inhibitive capacity of glycerol triacetate and the synergy between glycerol triacetate and NaCl. The study findings can be used in developing new hydrate inhibitors for ultra-deep water drilling and in formulating hydrate inhibitors.
Abstract: The well Yantan-1 is a key well of mining rights protection of PetroChina Qinghai Oilfield Company. It is a vertical fourinterval exploration well drilled in the Luoyanshan structure in Yiliping in Qaidam Basin. The well was drilled to 5,909.95 m. The objectives of the well were to ascertain the potential of oil and gas production of the Luoyanshan Structure E32-N1; to understand the Since the well was shut in and killed in a prolonged time, the well had to be abnormally completed. Technical difficulties encountered during the drilling of this well are quite typical, and valuable experiences gained from the field operation are of good reference value in dealing with the same drilling difficulties. developmental state and hydrocarbon-generating potential of the Paleogene-Neogene dark-colored mudstones in Luoyanshan area, which will provide bases on which study and deployment of thermogenic gas exploration in the large-scale belt zone in the hinterland of Qaidam Basin can be performed in the future. Geological conditions of this well are quite complex, and no drilling data are available for reference. As a typical "four-high" well, the actual mud density used during drilling was as high as 2.50 g/cm3, the bottom hole temperature measured was as high as 205℃, CO2 concentration of the mud was 100% during CO2 invasion, and multiple high pressure salt water zones were encountered. A BH-WEI drilling fluid was selected to deal with these difficulties. Formulation of the mud and maintenance of the properties of the mud were focused on technical issues such as high temperature stability, resistance to sour gas contamination, resistance to salt water contamination, mud rheology at high density and filtration control. By elaborate adjustment of mud formulation and mud property maintenance, these technical difficulties were successfully resolved, and the well was successfully drilled to 5,700 m. When the well was then deepened to 5,909.95 m, an abnormally high pressure saltwater zone was encountered. Since the well was shut in and killed in a prolonged time, the well had to be abnormally completed. Technical difficulties encountered during the drilling of this well are quite typical, and valuable experiences gained from the field operation are of good reference value in dealing with the same drilling difficulties. Key words Qaidam Basin; Organic salt drilling fluid; Ultra-high density drilling fluid; High temperature; Salt water invasion; CO2 invasion; Borehole wall stabilization; Rheology
Abstract: The well CN-H in the Block Changning is a shale gas development horizontal well located in Gong County, Yibin City, Sichuan. The target zone of this well is the Longmaxi shale formation of the lower Palaeozoic group. Shale formations in the fourth interval of the well is easy to hydrate and disperse, and collapse, causing borehole instability during drilling. Oil base drilling fluids are not allowed to use in drilling operations because of environment protection requirement. A biosynthetic base drilling fluid was then developed to replace oil base drilling fluids. The continuous phase of the biosynthetic base drilling fluid is a vegetable oil modified with a special technique. The biosynthetic base drilling fluid functions normally at 200℃, and the density of the drilling fluid is adjustable between 1.10 g/cm3 and 2.50 g/cm3. A biosynthetic base mud formulation of 2.1 g/cm3 had a rate of linear expansion of 0.8% and extreme pressure friction coefficient of 0.089 after aging at 150℃. The HTHP filtration rate of the aged mud was 1.6 mL. These data indicated that the synthetic base drilling fluid has good lubricity, plugging capacity, and inhibitive capacity, as well as good high temperature stability. Good suspension performance and cuttings carrying capacity of the drilling fluid at elevated temperatures ensured efficient and safe drilling in horizontal section of the well. Borehole wall was satisfactorily stabilized in drilling the fourth interval of the well CN-H. Average percent hole enlargement of this well was 4.9%, and the average ROP was 9.74 m/h, 2.14 m/h higher than those wells drilled with oil base drilling fluids. The biosynthetic base drilling fluid is nontoxic, satisfying the requirements of environment protection in Changning.
Abstract: The tight sandstone gas reservoir in the Block B in Tarim Basin has small pore throats, low permeability, high bound water saturation, severe heterogeneity and highly developed micro fractures. The reservoir formations are easy to be damaged and the formation damage is difficult to eliminate. To address these problems, tests on the high temperature sensitivity of reservoir formation and water block damage were performed under simulated formation conditions. The mechanisms of formation damage taken place in tight sandstone reservoir are revealed as follows:Reservoir formations are mainly damaged by stress sensitivity, water block and invasion of solids into the micro fractures in reservoir rocks. A temporary plugging agent and a surfactant that effectively reduce surface tension were selected through laboratory experiments for use in polymer sulfonate potassium drilling fluid, which is commonly used in the block of interest. A low damage drilling fluid with "synergetic action" in tight sandstone gas reservoir protection was developed using ideal packing theory and the surfactant selected. Evaluation of the drilling fluid in reservoir protection through compatibility test and dynamic contamination test showed that the drilling fluid is compatible with the formation water in Block B, and the percentage of rock core permeability recovery is at least 85%, indicating that the drilling fluid has good reservoir protection ability. The optimized drilling fluid has been used successfully on the well B2 in Block B in drilling the Bashijiqike formation. The skin factor of the reservoir rocks was greatly reduced after drilling, meaning that drilling fluid-induced reservoir damage was greatly reduced.
Abstract: Coproduction of "three gases" in coal measures requires drilling fluid to have the ability to maintain the stability of coal beds, dense sandstones and shales penetrated by the well. The patterns in which positively charged additives affect the Zeta potential of the surface of coal are studied based on the analyses made to the mineral composition of coal and shales. Laboratory experiments have been done to find a compounded surfactants that are able to effectively enlarge the contact angle of shale/coal, and to reduce the surface tension of the drilling fluid. Comprehensive evaluation was done to the properties of the drilling fluid, such as rheology, filtration, electrical property, wetting property, inhibitive capacity, reservoir protection and contamination resistance performance etc. Evaluation of these properties showed that positively charged organic gel and cationic surfactants effectively neutralize the electronegativity of the coal in Longtan formation in Bijie County. Quaternary ammonium salt surfactants and organosilicon surfactants all are able to change the Longmaxi shale and Longtan coal from water wetting to oil wetting. The optimized mixture of surfactants and mixed metal hydroxide (MMH-1) solution are able to effectively retard pore pressure transmission in shales and in coal. An MMH-drilling fluid with moderate viscosity and API filter loss of only 7 mL showed strong ability to inhibit the hydration of coal and shales. This MMH-1 drilling fluid also showed very weak damage to reservoir permeability; permeability impairment caused by the drilling fluid was only 10%. Gas permeability reduction by base mud can be reduced by 3.6% using the MMH-1 drilling fluid. MMH-1 drilling fluid is resistant to contamination; in laboratory experiment the MMH-1 drilling fluid was able to resist contamination by 3% NaCl, 1% CaCl2 and 5% attapulgite (to simulate drilled cuttings). MMH-1 drilling fluid is of low bio-toxicity and is environmentally friendly. All these advantages enable the MMH-1 drilling fluid to satisfy the needs for borehole stabilization in "three gases" coproduction from coal measures.
Abstract: With drilling geological conditions becoming increasingly rigorous, high drag and torque encountered in long horizontal drilling and high temperature deep well drilling have imposed higher requirements on the lubricity, thermal stability and toxicity of lubricants. These requirements are apparently not be able to be satisfied with lubricants presently in use. Laboratory experiments have been conducted in the selection of base oil, optimization of lubricity enhancers and optimization of conditions for the development of a high performance environmentally friendly lubricant, HPRH. In laboratory evaluation test, 0.5% (mass ratio) HPRH in fresh water base drilling fluid reduced the friction coefficient of mud by 93.75%, while in 4% NaCl saltwater base drilling fluid, this percentage reduction in friction coefficient was more than 80%. HPRH functions properly at 160℃, has low foaming and is free of fluorescence. Laboratory pin-disc friction and wear test results show that HPRH has remarkable anti-wear and wear-resisting property, and good lubricity persistence. After being wore for 60 min, the volumetric abraded quantity of the disc was only 6.92×10-13 mm3/(N·m). Field application of HPRH on two appraisal wells drilled in Block LN in Tarim Basin showed that, compared with compound lubricants used in field operations, HPRH has better lubricity persistence, and the amount of HPRH was reduced by at least 50%. The use of HPRH effectively avoided downhole troubles such as being unable to exert pressure on bit and pipe sticking etc., greatly reducing the drilling cost and enhancing the operational efficiency.
Abstract: Testing the degree of cationic substitution of quaternary ammonium salts with sodium tetraphenylborate (STB) is one of the most effective methods that have been widely used. The drawbacks of this method are that the interference of inorganic potassium ions and ammonium ions, as well as the molecular structure of the samples make the test inaccurate to some extent. Studies have been conducted on the improvement of the accuracy of the STB method by eliminating ionic interferences to the STB method, optimizing the test conditions of the STB method and investigating the effects of the molecular structure of polymers on the measurement of cationic substitution. In laboratory tests, the polymer samples were purified with 90%-95% ethanol to eliminate interference from potassium ions, ammonium ions and low molecular weight (MW) cationic monomers from outside. The mass of sample was determined to be 0.2 g, pH value for the precipitation between 3.0 and 4.0, temperature for precipitation between 15℃ and 25℃, and pH value for titration between 7.0 and 8.0. H2O2 was used at a certain temperature to reduce the MW of polymers to minimize the effects of molecular structure on the test accuracy of test, thereby improving the accuracy of the STB method. The test results show that the modified STB method has good feasibility and accuracy; the identification limit of the test is 0.1 g, and recovery rate 92%-94%.
Abstract: A shale gas well was drilled with high density invert emulsion drilling fluid in the third interval, and the barite recycling system was the key solids control equipment for the maintenance of drilling fluid properties. In the field operation there was no method for evaluating the performance of barite recycling system, and the barite recycling equipment was run at low efficiency. The barite recycling system was composed of a medium speed centrifuge and a high speed centrifuge. High density solids and low-density solids can be fractionally separated inside the centrifuge by different forces acted on them. The criteria for evaluating the performance of a two-speed centrifuge system are as follows:for medium speed centrifuge, the efficiency of separating the low-density solids in the underflow and the low-density solids in the overflow should be as low as possible. For high speed centrifuge, the efficiency of separating the low-density solids in the underflow and the low-density solids in the overflow should be as high as possible. A mathematical model and an evaluation method were established and tested in horizontal drilling of the well Wei204H7-6, where the medium speed centrifuge was running at a speed of 2,200 r/min, and 3.2% low-density solids were separated out of the underflow of the drilling fluid. On the other hand, 20.74% low-density solids were separated out of the overflow of the drilling fluid, apparently not being up to the evaluation criteria. Then the speed of the medium-speed centrifuge was reduced to 2,000 r/min, at which only 0.15% low-density solids were separated out from the underflow, and 4.6% low-density solids were separated out from the overflow, satisfying the criteria to some extent. The high speed centrifuge was run at 2,805 r/min, and the efficiency at which the low-density solids were separated was 61%, realizing high efficiency operation of the centrifuge system.
Abstract: Gel lost circulation material (LCM) presently in use swells fast when absorbing water, making it difficult for the LCM to enter into the flow channel in formation through which mud is lost. Part of the LCM entering the flow channel forms plugs of low strength in the flow channels because of early swelling, resulting in poor mud loss control. A swelling deferrable lost circulation material (LCM), BZYD-1, has been synthesized with acryl acid (AA), methyl acrylate (MA), 2-acrylamide-2-methyl propane sulfonic acid derivative (AMPSA), and N,N'-methylene-bis-acrylamide (MBA), and characterized. Laboratory evaluation showed that BZYD-1 had good thermal stability, and was resistant to high temperature to 150℃. At room temperature, BZYD-1 did not swell in fresh water, and rate of swelling after soaking for 4 hours in alkaline water was less than 50%. At 80℃, BZYD-1 soaked in alkaline water swelled to 17.8 times of its original size, demonstrating remarkable deferred swelling. The swollen BZYD-1 had pressure bearing capacity of 4 MPa. This swelling deferrable LCM has good application prospect.
Abstract: A low damaging drilling fluid formulated with compound salts has been developed to deal with production problems such as water sensitivity and water block taken place in production stage of "low production rate, low recovery factor and low water-cut" of the low permeability beach bar sand reservoirs in Block Bin425 in Shengli Oilfield. The development of the drilling fluid, based on the mechanisms of flow in porous media and reservoir protection, involved the optimization of key mud additives that functions synergistically in drilling fluid. The drilling fluid was evaluated quantitatively and analyzed with high-resolution CT and SEM for its damage to the permeability of cores taken from the reservoirs and the mechanisms of low damaging. It is concluded that the drilling fluid has high plugging capacity, being able to minimize the invasion of mud solids and filtrates into reservoirs. The surface tension of the filtrates is 26.2 mN/m, indicating low water block of the filtrates. Percent recovery of permeability of cores is greater than 90%. The low damaging compound salt drilling fluid has been successfully used on 26 wells in the Block Bin425, with average ROP of 22.80 m/h, and average drilling time saved by 11.23 d which meant that time for the wellbore to be contacted with drilling fluid was shortened. This drilling fluid is efficient in reservoir protection; the skin factors of the wall of newly drilled borehole were negative, meaning the new wells can be produced without the need for fracturing. This not only reduces the cost for a new well to begin production, it also enhanced the oil recovery of the well. It provides a new way of efficiently and economically developing reservoirs with low permeability.
Abstract: A self-degrading temporary plugging fluid was developed, through one-factor experiment analysis and synergistic compounding of different additives, to address the water sensitive and water block issues resulted from mud losses during working over the low permeability reservoirs in the Weizhou RRX oilfield in the west of South China Sea. Laboratory experimental results showed that the drilling fluid developed has excellent rheology and low filtration rate. Without injecting gel breaker, 50% of the gels developed in the drilling fluid were degraded in 6 days. Surface tension of the drilling fluid filtrate is less than 20 mN/m. The inhibitive capacity of the drilling fluid is at least 95%. Core experiment with the drilling fluid showed that the average percent permeability recovery is 90%. No mud loss and contamination to reservoir were found in field application of the drilling fluid, demonstrating the ability of the drilling fluid to minimize damage to low permeability reservoirs during workover operation.
Abstract: To characterize the mechanical property of the long set cement under a certain temperature gradient, the nonlinear changing pattern of the mechanical property of set cement at different temperatures was studied, and the causes for the changing pattern was analyzed. Curves describing changes of compressive strength, Young's modulus and Poisson ratio with temperature were drawn using the mechanical properties of set cement at temperatures between 30℃ and 160℃, and a functional equation was established by fitting the mechanical property of set cement with temperature. A nonlinear physical equation taking into account the eff3ects of temperature on the mechanical property of set cement was formulated. Analyses of the physical properties of set cement cured at different temperatures were done with the data obtained through TGA and XRD experiments. Using SEM, the micro morphology of set cement was analyzed, and the inherent causes of temperature affecting the mechanical property of set cement were primarily studied. It was found that at the same time of curing, the mechanical property of set cement had sudden changes at 60℃ and 80℃. At temperatures over 80℃, no obvious difference in the mechanical property was found of the cured set cement. It was also found that at temperatures below the temperature at which the sudden change takes place, the mechanical property changes in a pattern of quadratic function; at temperatures above the temperature at which the sudden change takes place, the mechanical property changes in a pattern of exponential function. Combined with the data obtained from micro analyses, it was found that different hydration products of cement and the different degrees of hydration reactions are what cause the mechanical property of the set cement to have sudden changes.
Abstract: To resolve the very high thixotropy problem encountered in using nanometer silicon cement slurry, three cement slurries were treated with 1%, 2% and 3% of PEG200, PEG400 and PEG600, respectively, and their rheological properties were tested and measured. The optimum concentration of PEG was determined by comparison of gel strength, plastic viscosity and yield point of the three cement slurries. The properties of the set nanometer silicon cement slurries before and after treatment with the optimized concentration of PEG were compared, and the IR spectrogram of the nanometer silicon emulsion before and after treatment with PEG were analyzed from the point of view of reaction mechanism. It was found that the properties of the set nanometer silicon cement slurry remained unchanged before and after being treated with 2% PEG200, indicating that addition of 2% PEG200 is best for improving the thixotropy of nanometer silicon cement slurry, the efficiency of thixotropy improvement was increased by more than 5 times. It was also found that the mechanisms of the PEG-nanometer SiO2 reaction include not only hydrogen bonding, but also ether bonding, both of which improve the thixotropy of the anti-channeling nanometer SiO2 cement slurry. Treatment of nanometer silicon cement slurry with 2% PEG200 resolved the very high thixotropy problem associated with nanometer silicon cement slurry, and the original properties of the cement slurry can also be maintained.
Abstract: Several difficulties have been met in cementing the φ168.3 mm liner (with hanger) in the ultra-deep well Wutan-1 in Southwest Oil and Gas Field, such as severe mud losses during drilling, deep well, high bottom hole temperature, long salt rock formation, severe contamination to the oil base mud and cement slurry used, and influence on the integrity of cement sheath by changing wellbore temperature in later-stage operations. Using low density high strength micro-expansion anti-channeling high toughness cement slurry with optimized column structure, the dynamic ECD at the bottom of the hole during cementing was maintained at almost the same level of the dynamic ECD at the bottom of the hole during drilling. These measures effectively prevented wellbore fluid losses from happening during well cementing, and minimized contamination to the cement slurry and the oil base drilling fluid. The job quality of cementing was 100% certified, and 99.8% of the job with high quality. This technology has provided technical support to cementing deep wells with narrow drilling windows and drilled with oil base drilling fluid.
Abstract: By compounding a high water demand material, a high active material and an ultra-fine material, a low cost strengthening light weight material BCE-650S was developed for use in low density cement slurry as a high performance additive. An ultra-low density cement slurry was developed with BCE-650S and other additives and mixed materials selected for use with BCE-650S. This cement slurry has densities adjustable between 1.20 g/cm3 and 1.30 g/cm3, and liquid/solids ratio between 1.07 and 1.23, and therefore has its cost greatly reduced. Laboratory study showed that the 24-hour compressive strength of the ultra-low density cement slurry at 60℃ is greater than 8 MPa, and the 72-hour compressive strength is greater than 10 MPa. The settling stability of the cement slurry is quite good; the difference between the density of the top and the density of the bottom of the cement slurry is only 0.01 g/cm3. The cement slurry has controllable filter loss, adjustable thickening time and high compressive strength, satisfying the need of field operation. This cement slurry is suitable for cementing low pressure long open hole with mud loss zones. Success in applying the cement slurry in Jilin Oilfield indicates that this cement slurry will have good application prospect.
Abstract: Loss of cement slurry into fractured formations is a problem often encountered and remained partially unresolved in cementing low pressure, fractured petroleum reservoirs. Foamed cement slurry, such as the chemically nitrogen filled foamed cement slurry is often used in dealing with this problem. Presently, the mechanisms of preparing the chemically nitrogen filled foamed cement slurry is not clear, and the efficiency of the chemical gas formers used is low. In this study the mechanisms of chemical nitrogen filling are revealed based on chemical thermodynamics and electrochemistry. A high efficiency gas former, LTPN, has been developed in preparing chemically nitrogen filled foamed cement slurry. LTPN basically does not affect the thickening time and compressive strength of cement slurry. When used in combination with animal protein foam stabilizer and nano foam enhancer, LTPN is able to reduce the density of cement slurry to 0.95 g/cm3. By extensively studying the chemical nitrogen filling pattern of gas formers in cement slurry, a high performance chemical nitrogen filled foamed cement slurry NFLC was developed. Cement operations of 30 wells have proved that NFLC is able to resolve problems encountered in cementing low pressure, fractured reservoirs. The cement slurry return height in cementing coalbed methane well with the NFLC cement slurry meets the designed requirements. In cementing the low pressure, fractured reservoir in Qinshui basin, Shanxi, cement slurry loss was avoided successfully, and the cement slurry returned to the designed height in the first try. 90% of the well was cemented with high quality. The chemically nitrogen filled foamed cement slurry has provided an effective way of cementing low pressure, fractured reservoirs, and has good application prospect.
Abstract: In CO2 water-free energy-storing fracturing, the fracturing fluid generates fractures of high flow conductivity in formations. By interacting with crude oil, the fracturing fluid also shows some special stimulation characteristics that are different with those of the conventional fracturing fluids, such as viscosity reducing, volume expansion and phase mixing etc. Thus, the optimization design process of the CO2 water-free energy-storing fracturing fluid is different with that of the conventional fracturing fluids. In CO2 waterfree energy-storing fracturing fluid design, the interaction between crude oil and CO2 is tested to obtain the minimum miscibility pressure. Using the relation pattern between the length of fractures caused by liquid CO2 fracturing and the physical parameters of the reservoir, the fracture parameters can be determined. Using 3-D reservoir numerical simulation method, the sweep area of CO2 and the area of miscible zone can be determined based on the value of minimum miscibility pressure, the fracture parameters and the injection pressure of the bottom of the wellbore, and finally the optimum amount of CO2 can be determined. Using FracProPT, a virtual 3-D fracture simulation software, with the friction loss along the flowline, the operational flow rate can be determined from the perspective of hydraulic power efficiency and economic benefits and the prerequisite of ensuring the safety and stability of wellhead and downhole string. Using the formation temperature-pressure computational model established after fracturing operation, the area of the miscible zone after well shut-in can be simulated, and from the simulation it can be determined that the optimum well shut-in time is the time spent for the miscible zone to become maximized, that is to say, the time spent when the bottom hole pressure after fracturing is greater than the minimum miscibility pressure. CO2 water-free energy-storing fracturing technology has been successfully applied in Jilin Oilfield to fracture tight reservoirs. Oil production rate was obviously enhanced after reservoir fracturing. 6 wells fractured with the CO2 water-free energy-storing fracturing technology have oil production rates that are at least one time of those wells fractured with conventional fracturing technology. Study results have shown that CO2 water-free energy-storing fracturing is able to substantially enhance oil recovery, and the method for the parameter optimization design of the CO2 water-free energy-storing fracturing is reasonably practical.
Abstract: Field practices have proved that fuzzy ball diverting agent is able to control fracture strike by altering rock strengths, theoretical study on diversion of fractures is rarely seen though. The relationship between the strength of diverting agent and diverting angle is one the key factors that ensures the diverted fractures extend to the designed positions. Diverting agent plugging experiment and rock triaxial stress experiment were done on a fuzzy ball diverting agent formulation:2.0% epithecium agent+1.5% fuzz agent + 0.3% nucleating agent+0.5% filming agent. When injecting 4, 8, 10 and 12 mL fuzzy ball diverting agent, the pressure bearing capacity of the formation being plugged by the diverting agent was 10.15 MPa,12.37 MPa,16.52 MPa and 25.14 MPa, respectively. An artificial sandstone core of 75 mm in diameter was tested on triaxial stress tester before and after being plugged with the fuzzy ball diverting agent, an inflexion point was found on the radial stress-strain curve at which the strain increased from 0.0048 mm/mm to 0.0127 mm/mm. On axial stress-strain curve there was also an inflexion point at which the strain increased from 0.0143 mm/mm to 0.0186 mm/mm. These data indicate that rock strength was increased. In calculating elastic modulus by dividing stress by axial strain, and Poisson ratio by dividing transversal strain by axial strain, in was found that the incremental diverting angles measured were 24.9°, 23.2°, 37.5°, and 55.9°, respectively. Four rocks after being plugged had elastic modulus of 19.55 GPa, 16.65 GPa, 19.61 GPa and 19.77 GPa, respectively, and Poisson ratios of 0.36, 0.30, 0.46 and 0.38, respectively. Using elastic modulus and Poisson ratio as the parameters affecting diverting angle, fit the mathematical relationship between the parameters and the diverting angle of fractures with least square method. It was found that the natural logarithm of the quotient of elastic modulus/Poisson ratio was linearly related to the diverting angle. From this finding a functional relationship between injection amount of diverting agent with diverting agent has been worked out. It is understood that the injection amount of the fuzzy ball fracturing fluid is able to control the diverting angle, thereby extending the diverted fractures to the target zones.
Abstract: Fracturing fluids with proppants are commonly used in field operations for better fracturing efficiency. Study on the rheological pattern of sand-content fracturing fluids is expected to provide a better theoretical basis on which accurate prediction of the sand carrying capacity of fracturing fluids in pipe and in fracture can be made. Taking the fracturing fluid and the sands in it as a whole, the mixed fluids were studied for the patterns and mechanisms of the change of apparent viscosity with shearing rate. It was found that after mixing with proppants, the viscosity of the mixture of a fracturing fluid and the proppants under certain shearing condition is lower than the viscosity of the fracturing fluid itself, the apparent viscosity first decreases with shearing strength and then increases, showing a "V" pattern. This is the result of the synergy between the change of the internal structure of the solid-liquid mixture and the disturbance of the proppant particles. The special rheological behavior of the sand-content fracturing fluids is also influenced by the concentration and particle size of the proppant and the liquid temperature. At high shearing rate, the collision of proppant particles is frequent, and the apparent viscosity of the sand-content fracturing fluid increases with the concentration of the sand. At low shearing arte, the apparent viscosity of the sand-content fracturing fluid first decreases and then increases with the concentration of the sand because of the additional shearing action of the sand particles, and the viscosity of the sand-content fracturing fluid is reversely related with the particle size of the proppant and the temperature of the fluid.
Abstract: In deep water gas well testing, changes in the temperature field of the wellbore usually result in a huge risk-the formation of hydrates. The hydrate generated will cause test pipes to block, and the annular space to have high pressure. Study has been conducted on the application of the phase curve of hydrate generation in deep water gas well testing. Based on an accurate prediction of the wellbore temperature field in deep water gas well, the area inside the test string in which hydrate will be generated during well testing is quantitatively predicted using the phase curve of hydrate, the depth at which the chemical injection valve is run on the test string is calculated, and the amount of hydrate inhibitor injected in wellbore and at the surface (choke) during testing is determined. All these together form the method of using the phase curve of hydrate in deep water well testing. This method has been used on a deep water gas well in South China Sea. The depth at which the chemical injection valve was run was calculated to be 2,450 m. Two hydrate inhibitors, methanol and glycol (3%-5%), were injected into the wellbore and at the choke on the surface respectively. Well testing was done in accordance with the standard work system, no hydrate had ever occurred in the wellbore during testing. Hydrate was produced at the choke, and after injecting hydrate inhibitor, the pressure was reduced by 13.6%, ensuring the success of the well testing operations. The operation procedure can be used for reference in controlling the formation of gas hydrate during well testing in deep water gas fields.
Abstract: In drilling, well completion or water injection operations, clays in formation rocks may swell when in contact with water base fluids, causing formation damage. Many studies have been conducted on formation damage caused by clay swelling, the numerical studies on the changing pattern of swelling with time and in space are scarcely seen. In our laboratory studies, a mathematical model has been established based on osmotic hydration of clay and the Fick diffusion of water molecules. Using this model, the changing pattern of the non-dimensional permeability of rocks around a wellbore with time and space was simulated, and the change of skin factor with time was calculated. It was demonstrated that the swelling of swelling has the characteristics of fast increase in the early stage, and slow increase to increase ceasing in the middle and late stages, meaning that formation damage is mainly contributed by the early swelling. At a certain point in the reservoir, the permeability impairment may be small, the formation damage is spatially extended, far from its origin, several meters, for instance, causing remarkable damage to the permeability of reservoir formations. To sum up, this study, based on simplified mathematic model, quantitatively simulated the spatial characteristics of the swelling of clays around a wellbore, and the swelling pattern of the clays with time, realizing the space-time dynamic simulation of single-factor controlled formation damage. The studies shed light on field engineering practices.
Competent Authorities：China National Petroleum Corporation Ltd
Sponsored by：CNPC Bohai Drilling Engineering Co. LtdPetroChina Huabei Oilfield Company
Address： Editorial Department of Drilling Fluid and Completion Fluid, Bohai Drilling Engineering Institute, Yanshan South Road, Renqiu City, Hebei Province