Abstract: Pickering emulsion is widely used in biomedical science, food and cosmetic industries because of its good aggregation stability, variety, ease of handling, low cost, low toxicity and biocompatibility etc. In recent years, more attention has been drawn to the use of Pickering emulsion in petroleum industry. This paper analyzed the stability mechanisms of Pickering emulsion and its advantages over conventional emulsions, investigated several factors influencing the stability of Pickering emulsion and the methods of adjusting and controlling these factors, and finally, summarized the application of Pickering emulsion in drilling and oil and gas flooding both in China and abroad. The future of the development of Pickering emulsion in petroleum industry was also discussed.
Abstract: Downhole problems have been frequently encountered in horizontal shale gas drilling with oil base drilling fluids in Sichuan, China. This paper, based on the analyses of the characteristics of the shale in Longmaxi formation in Weiyuan, Sichuan, discusses how to enhance the inhibitive capacity of oil base drilling fluids in shale gas drilling from three aspects:drilling process, geology and drilling fluid, especially oil base drilling fluid. 1) Select and use, through laboratory experiment, multi-function additives to control the properties of the drilling fluid and reduce the HTHP filtration rate as many as possible. The multi-function additives should have these functions such as emulsifying and filtration reducing, increasing viscosity and gel strength while emulsifying the drilling fluid, plugging formation pores while reducing filtration rate. 2) Use oil base drilling fluids with oil/water ratios between 85:15 and 95:5. 3) Use plugging technique and pay attention to the change of rheology, mainly the increase in funnel viscosity, gel strength and yield point, and plastic viscosity. 4) Increase the activity of water phase by using potassium formate in the water phase, or further increasing the concentration of CaCl2 in the water phase. 5) Use potassium formate or CaCl2 with inhibitive intercalation agents such as amine, to improve the inhibitive capacity of the filtrates of oil base drilling fluids.
Abstract: Sodium styrene sulfonate and AMPS were used to react with acrylamide and dimethyl diallyl ammonium chloride respectively in explosive polymerization to produce two high temperature salt resistant filter loss reducers WS-1 and WS-2. Explosive polymerization was used in the synthesis reaction because in aqueous phase polymerization, the yield of the product is low, the molecular weight of the product is easy to increase during drying, and the energy required for the reaction is high. The molecular structure and thermal; stability of WS-1 and WS-2 were characterized using FT-IR spectroscopy and TGA. The effects of WS-1 and WS-2 on the rheology and HTHP filtration rate of high salinity water base drilling fluids at elevated temperatures were evaluated in laboratory experiment. The experimental results showed that WS-2, having rigid sodium styrene sulfonate molecular chains in its molecules, had good high temperature stability, the thermal decomposition temperature of WS-2 was tested to be 310℃. HTHP filter loss at 220℃ of a saturated saltwater base drilling fluid treated with WS-2 was 7.6 mL. WS-1, having large molecular chain of AMPS in its molecules, had thermal decomposition temperature of 270℃. HTHP filter loss at 200℃ of a saturated saltwater base drilling fluid treated with WS-1 was 1.6 mL. These experimental results showed that WS-1 and WS-2 both have good high temperature and salt resistant performance.
Abstract: PF-MOSHIELD, a high temperature plugging agent, has been developed for use in oil base drilling fluids to enhance the efficiency of plugging fractures with wide size distribution at elevated temperatures in drilling high temperature high pressure wells complicated with developed beddings and microfractures. PF-MOSHIELD is made from a unique chemical modifier, sulfonated asphalt, acid soluble calcium carbonate, nanophase silica and styrene acrylate. PF-MOSHIELD, with its particle sizes distributed in the range of 1-189.02 μm, has good thermal stability; the decomposition temperature of PF-MOSHIELD is 378℃, and the softening point is 260℃. PF-MOSHIELD is dispersible in oil. Compared with conventional plugging agents for oil base drilling fluids, PFMOSHIELD can be squeezed into microfractures under pressure, taking part in the buildup of both the "inner filter cake" and the "surface mud cake". PF-MOSHIELD can, at high temperatures, plug fractures of different porosities, effectively reducing the amount of filtrate and the rate of filtration. Field application of PF-MOSHIELD on wells drilled in the Block WZ6-9 and Block WZ12-1 showed that drilling fluids treated with PF-MOSHIELD had stable rheology and enhanced electric stability, and pressure transferring in the pores in shale formations was weakened, all satisfying the needs of borehole wall stabilization in drilling hard brittle and fractured formations developed with beddings and microfractures.
Abstract: High temperature ultra-high-density oil base drilling fluids have long been used in drilling the salt/gypsum formations of the Kumugeliemu group in Kuche piedmont area in Tarim Basin. Oil base drilling fluids used in this area should have good rheology, low HTHP filtration rate, good plugging capacity and dynamic/static settling stability. This paper discusses the effects of different weighting agents on the properties of a high temperature (160℃) ultra-high-density diesel oil base drilling fluid. The performance of an ultra-high-density diesel oil base drilling fluid formulated with single weighting agent, such as barite with density of 4.2 g/cm3, barite with density of 4.3 g/cm3, iron oxide powder or Microdense, cannot satisfy all the needs of drilling engineering. A weighting agent MicroMax, which is an ultra-fine, high density and spherical powder was then used to formulate the required oil base drilling fluid. The MicroMax weighted oil base drilling fluid had excellent rheology and good settling stability, the HTHP filtration rate of the drilling fluid was out of control though. Using a weighting material mixed with 60% barite and 40% MicroMax, a high temperature ultra-highdensity (2.4-3.0 g/cm3) diesel oil base drilling fluid with good properties was formulated; it can satisfy all the needs of drilling high pressure saltwater zones and hole sections in which mud losses are easy to take place.
Abstract: A high temperature gas blocking plug has been developed to resolve the problems of too fast gas channeling and long period of gas drainage encountered in high temperature high pressure fractured reservoirs in the periphery of Tazhong area. The gas blocking plug, developed with choice high temperature gelling agents and high temperature filter loss reducer etc., functions normally at 180℃, with its gel strength greater than 30 Pa, viscosity greater than 60 mPa·s, and time of stabilization of longer than 120 h at elevated temperatures. Field application of the gas blocking plug indicated that the rate of gas channeling was reduced by more than 80%, greatly prolonged the time required foroperation and enhanced the safety and efficiency of well drilling and completion. The high temperature gas blocking plug can be used to resolve the gas cut problem encountered in drilling high pressure fractured petroleum reservoirs in Tazhong area, providing a safe and effective well control technology for gas channeling prevention during well drilling and completion.
Abstract: High friction and high torque are two factors restricting the use of water base drilling fluids in extended reach horizontal drilling. A water base drilling fluid lubricant SDL-1 has been developed to resolve these problems. SDL-1 is a compound of ester synthesized with long chain fatty acid and low molecular weight polyalcohol, and some extreme-pressure additives. Evaluation of SDL-1 showed that addition of 1% SDL-1 in 4% fresh water base mud reduced the coefficient of friction of the mud by 85.2% and reduced the adhesion coefficient of mud cake by 59.3%. When aging at 160℃ for 16 h, the coefficient of friction of the mud was reduced by 94.0% and the adhesion coefficient of mud cake was reduced by 62.3%. When aging at 180℃ for 16 h, the coefficient of friction of the mud was still reduced by 90.0%, indicating that SDL-1 functions effectively at 180℃. SDL-1 is able to resist contamination by 30% NaCl and 30% CaCl2. In four-ball friction test, after 30 min of friction, SDL-1 effectively reduced the amount of scratch, reducing the surface wear-and-tear. This test showed that SDL-1 is a better lubricant in friction resistant than another lubricant DFL. When treated with 2% SDL-1, the rheology of a clay-free drilling fluid of density 2.0 g/cm3 and an environmentally friendly drilling fluid of density 2.2 g/cm3 was only slightly affected, and the friction coefficient of the two drilling fluids was reduced to 0.08. SDL-1 as a lubricant shows good lubricating performance and resistance to high temperature and salt contamination, and will find its application in deep extended reach drilling.
Abstract: Drilling operations in the Pearl River Mouth Basin have been face with downhole troubles in the Paleogene System, such as borehole wall collapsing, pipe sticking and difficulties in tripping the drill string. Addressing these problems with increased drilling fluid density resulted in other problems such asdifferential pipe sticking and low time efficiency. The causes of borehole wall collapse in drilling the Paleogene System in the Pearl River Mouth Basin were analyzed through clay content analysis, SEM experiment, hot rolling test and core swelling test. The Paleogene System is developed with micro fractures, formation stress change due to drilling operation and invasion of mud filtrate into the micro fractures cause borehole wall collapse, followed by pipe sticking and difficulties in tripping the drill string. To address these problems, silicate drilling fluid was adopted to drill the Paleogene formation. Silicate drilling fluid has good inhibitive capacity and plugging capacity. It helps enhance the strengths of the rocks and reduce the collapse pressure of the formation drilled, thereby reducing the density of the drilling fluid to balance the formation pressure. Performance evaluation of an optimized silicate drilling fluid showed that its properties satisfy the requirements of drilling operations. It helps increase the cohesion and compressive capacity of rocks. Compared with the PLUS-KCl drilling fluid and oil base drilling fluid that have been already used in drilling the Paleogene formation, the optimized silicate drilling fluid performed much better; rocks immersed in the optimized silicate drilling fluid had higher compressive strength and cohesion, the cohesion was tested to be 11.7 MPa, 1.9 times of the cohesion of the rock samples immersed in PLUS-KCl drilling fluid, or 1.5 times of the cohesion of the rock samples immersed in oil base drilling fluid. These experimental results proved that silicate drilling fluid can be used to reduce the density of the drilling fluid while maintaining the borehole wall in stable condition.
Abstract: Shale gas drilling in block Changning is conducted in an area with karst landform at the surface and underground cavern and underground rivers resulting in severe water kick and lost return during drilling in surface formations. To address these problems, bridging slurries, high filtration rate lost circulation material (LCM), cement slurries and smart gels were used to stop mud losses, however the results of applying these LCMs were not satisfactory, and the mud losses started again after a while of applying the LCMs. A gel that is able to fast swell when intact with water was developed in an effort to address the problems effectively and efficiently. The mechanisms of this gel are "swelling+crosslinking+filling"; when in contact with water, a crosslinking reaction takes place in the gel water mixture, and the mixture swells and releases CO2 which makes the gel swell further to a volume that is several times of its original volume. The crosslinked gel finally becomes an elastic water-tight non-toxic gel. CO2 inside the gel drives the non-crosslinked elastic gel into the formation pores in the thief zones, inhibiting water kick by swelling and elasticity. Laboratory evaluation of a fastswelling gel LCM formulated with optimized additives showed that the gelling time of the LCM is between 15 min and 70 min, it is able to expand to 250% to 350% of its original volume, and to block distilled water or water base drilling fluid that is 3 or 5 times by volume of the gel LCM, respectively. Test of the gel LCM on a model CDL-Ⅱ HTHP LCM tester showed that, using 4-3 mm and 5-4 mm simulated channels for mud loss, the pressure bearing capacity of the plugged channels were 3.8 MPa and 1.7 MPa, respectively.Test of a compound LCM mixed with the gel LCM and a bridging LCM showed that the pressure bearing capacity of the plugged channels were increased to 6.25 MPa and 5.2 MPa, respectively. In a field application, a water production zone was plugged at the first try of the gel LCM, and the pressure bearing capacity of the plugged water production zone was increased to 5.8 MPa, resolving water production when drilling the top formations and ensuring safe drilling.
Abstract: The well Shunbei 52X is an exploratory well located in the north margin of the Shuntuoguole low uplift, Tarim Basin. This well penetrated a section of the easy-to-break Silurian igneous rocks with plenty of fractures, poor cementation and low-pressure bearing capacity. Repeated mud losses and well kicks happened during drilling from 5,600 m to 6,200 m. High formation temperature of 150℃ was the major reason prohibiting the use of chemical gel to stop mud losses. To deal with mud losses encountered and extend the use of chemical gel, a new high temperature chemical gel was developed, making use of the thermoplasticity of organic gel, the compound action of gel and the retarding effect of modified methyl silicone oil. Laboratory experimental results showed that the thickening time of the high temperature chemical gel can be maintained to more than 4 h, and the compressive strength of the chemical gel after aging for 10 hours was 3.2 MPa. The high temperature chemical gel was used on the well Shunbei 52X to control mud losses; the pressure bearing capacity of the formations at which mud losses have happened in the past was increased to 4.8 MPa as tested, and the equivalent circulation density of the Silurian system was raised to 1.40 g/cm3, successfully resolving the mud losses and well kick problems encountered in drilling the well Shunbei 52X.
Abstract: Well Chuanshen-1 is an ultra-deep exploratory well drilled in northeast Sichuan by Sinopec. Drilling of this well was faced with several technical difficulties such as high formation temperature, complex formations penetrated, less geological data available, borehole wall instability and high mud density etc. Drilling fluid additives were selected through laboratory experiment to deal with the high-density problem. The additives selected and their concentrations were:2%SPNH, 2%SMP-3, 0.5%SMPFL (DSP-1), 3%SMT (SMS-H), 3%RHJ-3, 1%HPA, 3%nanophase SiO2. A high-density polymer sulfonate drilling fluid with good rheology, strong inhibitive capacity, high temperature resistance, good settling stability and high resistance to contamination, was formulated through orthogonal experiment. This drilling fluid was successfully applied in the fourth interval of the well Chuanshen-1. Difficulties encountered in filed operations and technical measures (such as gas-liquid conversion, drilling fluid treatment for special formations, mud property maintenance in field operations and reservoir protection etc.) are discussed in this paper. The major technical measures include:1) When weighing the active mud, high density mud with low viscosity low gel strength should be used and the MBT of the mud should be reduced gradually. 2) Solids control equipment should be used to control solids content strictly under designed value. 3) Drilling fluid density can be increased when drilling into salt and gypsum formations and filter loss should be strictly controlled. pH value of the drilling fluid should be no less than 10. 4) When drilling formations with acidic fluids, pretreat the drilling fluid with high chloride content, thereby enhancing its ability to resist salt contamination. 5) High density with some additives can be used to drill broken formations, borehole instability can be resolved through coupling of mechanical and chemical measures. 6) Drilling fluid density should be strictly controlled when drilling formations at which mud losses are easy to take place. Meanwhile the flow rate should be appropriately reduced, and mud viscosity and gel strength should be increased to some extent. Temporary plugging with acid soluble lost circulation materials of different particle sizes can be used to control mud losses.
Abstract: Formations drilled in the Mingbulak Oilfield in Uzbekistan have very complex structures. Wells drilled in this oilfield with depths between 800 m and 3,500 m penetrated saltwater-bearing zones, long segment of anhydrite, gypsum/shale mixed formations and highly water sensitive formations. Part of the formations also have high concentration of CO2. Formations between 3,850 m and 5,900 m are full of fault zones, vugs and fractures, and gypsum segments that may creep and form tight hole during drilling. Coexistence of high-pressure oil, gas and water may cause well blowout and mud losses to happen simultaneously. When drilling an ultra-deep well with high temperature (≥ 170℃), high pressure (pressure gradient ≥ 2.3), high salt content (≥ 20%) formation water, high H2S content (5%-6%), the drilling fluid should satisfy the needs of both stabilizing the high pressure formations in the upper section of the well as well as preventing mud losses and flowing of H2S in the lower section of the well. Difficulties associated with ultra-deep well drilling include creeping of long section of gypsum/anhydrite which leads to tight hole, borehole wall collapse caused by high pressure saltwater invasion, difficulties in controlling the rheology of high-density drilling fluid, high circulation pressure and reservoir protection etc. By optimizing the composition of the drilling fluid and carefully selecting mud additives, it was decided that a highdensity compound formates drilling fluid was used to drill the extremely complex second interval and the sections beyond that. Filed operations showed that the compound formates drilling fluid had good inhibitive capacity and lubricity, strong resistance to calcium contamination and low solids content. The compound formates drilling fluid had controllable rheology even when the drilling fluid was treated with high concentration of lost circulation materials. With this drilling fluid, downhole problems previously encountered such as pipe sticking (because of high mud weight and creeping of salt/gypsum layers), coexistence of well blowout and mud losses, as well as inability to drill deeper reservoirs, have all been wiped out. The aim of drilling the well successfully has been realized, and technical support and experiences have been provided to subsequent operations.
Abstract: Well Huashen-1x, designed to drill to 5713.16 m, is the deepest exploratory extended-reach well deployed by CNPC in Fushan oilfield, Hainan. This well was drilled to ascertain the reservoir engineering data of the member Liu-3 located on the top of a fault nose structure. This well is located in the Fushan depression in the Beibuwan Basin, and the formation at the deep part of the well is the so-called Liushagang formation of the Paleogene System, which is complex. Faulting, broken belt of 1300 m in length, hard and brittle mudstone, developed micro fractures and beddings, strong water sensitivity of the formation rocks which are very instable and easy to slough, and high well temperature of up to 180℃, are all challenges to drilling fluid operations. The maximum displacement of the well designed was 3208 m. Extended-reach well places higher requirements on the rheology, inhibitive capacity and lubricity of the drilling fluid. During drilling, lack of understanding of the lithology of the formations resulted in severe sloughing in the highly deviated fourth interval and three times of sidetracking in this interval. In the third sidetracking, a drilling fluid formulated with organic salts and inorganic salts was used. This compounded salt drilling fluid, with its strong inhibitive capacity, good plugging capacity and high temperature resistance, resolved the borehole instability problems encountered in the broken belt between the Liu-2 member and Liu-3 member of the Liushagang formation, ensuring safe drilling and other operations in the fourth interval.
Abstract: Nanoparticle plugging agent is presently a research hotspot of drilling fluid technology, no special method has ever been developed for evaluating the plugging capacity of this category of drilling fluid additives though. When using the presently available methods to evaluate nanoparticles in laboratory, the evaluating results cannot be used to describe the plugging capacity of nanoparticle materials. Using the existing evaluation methods for reference, a new method has been developed to resolve this problem. In the new method, the filtration medium was carefully selected and modified, and the operability of the new method was improved. The evaluating results of the new method can reflect the plugging capacity of the nanoparticle tested, and nanoparticles of different particle sizes were tested using the new method to verify its applicability. The new method is of reference value to the evaluation of nanoparticles in laboratory and selection of nanoparticles in filed operations.
Abstract: When cementing wells drilled in low temperature deep water zones, cement slurry should give off less heat during hydration process to minimize the increase of temperature of the formations with natural gas hydrate. A new phase change material has been developed for use in low heat cement slurries used to cement wells penetrating formations with gas hydrate. The heat storage performance of the phase change material and its effects on the properties of cement slurry were studied. Laboratory experimental results showed that the peak temperature at which phase change takes place was 15.5℃ for the new phase change material. This temperature sits between downhole low temperatures and ambient temperature, and the latent heat of phase change was high. At temperatures below 77.8℃, the phase change material had good thermal stability. No change to the chemical structure of the phase change material ever happened after the phase change material had undergone many times of temperature fluctuation between 0℃ and 60℃. The rheology of the cement slurry increased with an increase in the concentration of the phase change material. Increasing the concentration of the phase change material to 8% did not affect the ability of the cement slurry to satisfy the needs of well cementing. Furthermore, the new phase change material helped improve the stability of cement slurry and only slightly affected the compressive strength of the low heat cement slurries. A low heat cement slurry treated with 8% of the new phase change material had set cement with compressive strength of 8.9 MPa, and the decrease of the compressive strength was less than 5% at most. When added 2%, 4%, 6% and 8% new phase change material into a cement slurry respectively, the thickening time of the cement slurry was 15 min less than that of the cement slurry without the new phase change material (the blank cement slurry). The 72-hour heat of hydration of the four cement slurries were reduced by 5.2%, 29.1%, 35.6% and 47.6% than the blank cement slurry, respectively. This study has provided a technical support and reference to the design of low heat cement slurry for use in cementing wells penetrating formations with natural gas hydrate.
Abstract: CNOOC has in recent years drilled several ultra-deep water wells in South Sea of China, the deepest water depth has been more than 2,000 m. Extremely low temperature has imposed serious challenges to the strength of set cement. Two new low temperature early strength agents, ACC and NS, have been developed to deal with well cementing challenges in deep water drilling. Studies on the effects of ACC and NS on the early strength of cement slurry at low temperatures showed that the optimum concentrations of ACC and NS was 8% and 3%, respectively. At low temperatures between 3℃ and 15℃, ACC and NS can improve the 24-hour and 48-hour compressive strengths of set cement. Continual monitoring of cement slurries for 24 hours at 15℃ using hydration heat analyzer and ultrasonic strength analyzer showed that, compared with blank sample cement slurry and original early strength additives, addition of ACC and NS obviously increased the amount of heat of hydration and hydration reaction rate of cement. The rate at which the strength of the set cement was developing was obviously increased, while the transition time of the gel strength of the cement slurry was obviously shortened. ACC and NS have been used satisfactorily on the well WN-XX in China's South Sea.
Abstract: Rotating casing string during well cementing is an important measure of increasing displacement efficiency. To quantitatively calculate the displacement efficiency when casing string is being rotated during pumping of cement slurry, infinitesimal method is used to analyze the stresses exerted on the cement slurry which is displacing drilling fluid while the casing string is being rotated, and a model was established for calculating the displacement efficiency of cement slurry when the displacement interface reaches an equilibrium. Using this model, different circumferential displacement efficiencies at different casing string rotational speeds can be worked out. Calculation using the model showed that when the rotational speed was greater than 10, the thickness of the stagnant retention layer of drilling fluid on the surface of the borehole wall can reduced. When the consistency coefficient of the cement slurry was increased, and the flow index was between 0.4 and 0.7, rotating casing string can remarkably increase displacement efficiency.
Abstract: The tight gas reservoirs in Changqing Oilfield have high fracturing pressures, imposing high requirements on the mechanical property of cement sheath. The integrity of cement sheath of a typical hole interval (φ152.4 mm hole size×φ114.3 mm casing size) of a well was analyzed using the established casing-cement sheath-formation combination model and the method for evaluating the sealing performance of a combination (sealing safety factor method). The analyses, taking account of the data gathered from field operations, showed that:① when the elastic modulus of a cement sheath was decreased, forces acting on the cement sheath was reduced, resulting in increased safety factor; ②when fracturing pressure was increased, the safety factor was reduced; ③ when the rate of volumetric contraction of cement was increased, the safety factor of the cement sheath was reduced remarkably. Based on the results calculated using the data gathered from the well, the mechanical property of cement sheath having good sealing performance in horizontal section of a well was presented. This study will provide theoretical support for analyzing the integrity of cement sheath in the tight gas reservoirs in Changqing Oilfield or other similar reservoirs.
Abstract: Keshen-243 is an appraisal well located 29 km to Baicheng County, Xinjiang. The 3rd interval of this well was drilled to 5,532 m, and two-stage cementing was to be conducted to cement the hole penetrating Kumugeliemu group (salt rocks). Bottom hole static temperature of the 3rd interval was 127.6℃, mud weight was 2.43 g/cm3, and the maximum formation pressure was 132 MPa. Casing strings of φ273.05 mm + φ293.45 mm in diameter were to be run into the hole and cemented. Several problems were expected during casing running, such as low pressure bearing of the formations to be cemented which may result in lost circulation, creeping of the salt/gypsum interbeds, channeling of cement slurry and slow setting of the top cement slurry when cementing long open hole section etc. In formulating the cement slurry to address these problems, a micro powder manganese mineral and another weighting agent GM-1 were dry mixed together into the cement slurry to ensure its density, two anti-channeling agents used to improve the anti-channeling performance of the cement slurry, and a combination of high temperature and low temperature filtrate loss reducers to improve the filtration property of the cement slurry. The amount of cement retarder was reduced to avoid long retarding period of the top cement slurry under the circumstance of big temperature differences. All these selected additives, plus the cementing techniques engineered, made the two-stage cementing operation through salt-gypsum interbedded formations smoothly done even when there was lost circulation flowed by mud kick. The cementing job was qualified.
Abstract: Field application of guar gum fracturing fluid treated with organoboron and inorganoboron crosslinking agents has been faced with problems such as large amount of guar gum consumed and high residue content of the fracturing fluid. In laboratory research on these problems, nanosilica was first made by the hydrolysis of sodium silicate, and the nanosilica made was then reacted with γ-aminopropyltrimethoxysilane to produce a surface modified nanosilica. The surface modified nanosilica was further reacted with boric acid to produce a boron-modified nanosilica crosslinking agent with particle sizes between 7 nm and 11 nm, and it was able to effectively reduce the amount of guar gum required in mixing fracturing fluid and the residue of fracturing fluids. Study was done on the performance of a hydroxypropyl guar gum fracturing fluid treated with the boron-modified nanosilica as a crosslinking agent, and it was found that the fracturing fluid had good properties. At temperatures 50℃ and 120℃ respectively, shearing of the fracturing fluid at 170 s-1 for 120 min produced a fracturing fluid with viscosity of greater than 50 mPa.s. At 50℃, after gel breaking for 60 min, the fracturing fluid had viscosity that was less than 5 mPa.s and surface tension of 22.77 mN/m. Core swelling test with the gel-broken fracturing fluid showed that the percent core swelling was 89.6% and the residue content was 145 mg/L. Permeability impairment of a core matrix tested with the fracturing fluid was between 9.82% and 14.86%. Other properties of the fracturing fluid were all satisfactory, the amount of hydroxypropyl guar gum required for mixing fracturing fluid was reduced by 20%, and the residue content of the fracturing fluid mixed was reduced by 25%, satisfying the needs of field operations.
Abstract: The pattern and extent of the viscous fingering of an acid are two key factors affecting the differentialized corrosion of the wall surface of fractures by the acid. Quantitative srudy of the relationship between the two factors is rarely seen at present. In laboratory experiment, the viscous fingering of acid was dynamically simulated using finite volume method, the change patterns of viscous fingering at different viscosity ratios, viscosity differences and density differences were analyzed, and the extent of differentialized corrosion at different conditions was quantitatively characterized using parameters describing the extent of differentialized corrosion at a certain fingering level. It was found that at flow rate of 5 m3/min, a high level of differentialized corrosion was reached when the viscosity difference was between 250 mPa·s and 350 mPa·s, the viscosity ratio between 15 and 20, and the density difference between 0 g/cm3 and 0.01 g/cm3. A similar pattern of change of the differentialized corrosion by acid can be found by changing the flow rate.
Abstract: To render fracturing fluid with functions of slick water and sand carrying fluid, and to recycle flowed back fracturing fluid having high salinity, a functional slick water has been developed with liquid functional drag reducer and conditioning agents. A water solution of low concentration functional drag reducer can be used as slick water, the water can be quickly viscosified in 15 secs, and the percent drag reduction of the slick water can be as high as 74%. This slick water, after treated with conditioning agents, will be rapidly viscosified and is able to carry more sands. The slick water flowed back for recycling is not affected by its hardness, and sand carrying capacity of the recycled slick water can be as high as 24%. The slick water has been used on a deep natural gas development well in Longdong, and the recycled slick water with salinity of 26,118 mg/L was used to formulate new slick water; totally 654 m3 of the newly formulated slick water was injected into the reservoir formations.
Abstract: Water injection is a key technique for long and efficient development of oil. In recent years, more and more wells in some blocks of the Huaqing oilfield are faced with increasing injection pressure resulted from the physical properties of the reservoir and the quality of injected water. Presently increasing injection rate is done by acidizing, but there are several challenges for this technique, for example, the time for this technique to work effectively is short, the injection efficiency is low after many times of acidizing, the execution of the technique lasts a too long, the equipment required for executing the technique is difficult to move, and finally, the operation cost is not acceptable. In laboratory study, a lot of experiments have been done to resolve these problems based on the study on the characteristics of the reservoirs in Huaqing. It was fount that by changing the commonly used hexadentate amino carboxylic acid chelating agent to octadentate chelating agent, the ability of the chelating agent to capture, chelate and wrap metal ions is enhanced. By mixing the chelating agent and acid, a new acid suitable for acidizing job was formulated. Meanwhile, the equipment used for water injection was also improved and optimized. A long-distance operational system was added to the equipment to improve the accuracy of the operation. Using a surface pulsed piston pump, a pulsed online acidizing augmented injection technology was formed. This technology has till now been applied 4 times, water injection pressure was reduced by an average of 9.0 MPa, volume of water injected per day per well was increased by 14.0 m3, and the average time for the stimulation measure to remain effective was 182 d. Other problems previously met, such as long time of operation, difficulty in moving the equipment required etc. have all been resolved. It is worth spreading this new and easy technology in water injection job.
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