Abstract: Many problems exist in the use of high temperature high density saltwater drilling fluids, such as more additives (both type and quantity) that are used than necessary, HTHP filtration rate and rheology after aging becoming difficult to control, and high costs in mixing and maintaining the property of the drilling fluid, etc. The reasons that these problems have been studied for a long term but remained unresolved are analyzed in this paper, and based on the analyses, a method has been presented to resolve the high viscosity, high HTHP filter loss and difficulties in controlling the properties of the drilling fluids, problems that are associated with the use of high density drilling fluids. This method, based on the high temperature crosslinking of mud additive, resolves the problems through optimized sizing of barite particles. A new technical clue has been presented for the study of high temperature high density saltwater drilling fluid, and based on the technical clue, a high temperature high density saltwater drilling fluid with excellent performance (low HTHP filter loss, good rheology…) was formulated with only 4 kinds of additives whose total amount was only 1/2-1/3 of the total amount of additives used in the high temperature high density saltwater drilling fluids presently in use. The high temperature properties of this new drilling fluid had the potential of becoming better after long time of using, and being easy to maintain. The study conducted and the drilling fluid formulated have provided a way of resolving the stubborn problems associated with the use of high temperature high density saltwater drilling fluids in China.
Abstract: A solid-free drilling fluid having stable properties at 220℃ has been developed with high temperature additives such as XCC (viscosifier), AADC (filter loss reducer) and FSCC (plugging agent). The detailed composition of the drilling fluid is:2%XCC+1% AA DC+3%SPNH+1%SMP+3%FSCC+0.5%Na2SO3. SEM experiment showed that shale cores taken from a well drilled with this drilling fluid had layered micro-fractures apparently plugged, and a dense tree-like polymer layer parallel to the direction of the micro-fractures was found on the surface of the shale cores. FT-IR experimental results showed that, after aging at 220℃, the drilling fluid still had stable mud properties, good rheology and filtration properties. The inhibitive capacity and lubricity of the drilling fluid can satisfy the needs of drilling operation. This drilling fluid was able to tolerate the contamination from 10% clay and 5% drilled cuttings, or from 10%KCl+20%NaCl salt solution. The LC50 of the drilling fluid measured was 80,000 mg/L, conforming to the stipulated discharge criteria. The drilling fluid has been successfully used to drill the Well 24 located in the Sebei-1 gas field.
Abstract: Oil base drilling fluids, because of its high operation cost and pollution to the environment, are more and more replaced by water base drilling fluids. Based on the requirements for the performance of drilling fluids imposed by shale drilling, drilling fluid additives have been optimized to formulate an environmentally friendly non-toxic high performance water base drilling fluid. In selecting the additives, the environmental rules of "chloride-free, heavy metal ion-free and no black material" were followed. Amine based polyalcohol and polymers synthesized through emulsion polymerization were selected as the main shale encapsulators, whose inhibitive capacity was enhanced with potassium formate. A highly effective plugging agent was selected to improve the ability of the drilling fluid to plug the nanometer and millimeter micro-fractures. Laboratory evaluation indicated that in a density range of 1.22-2.18 g/cm3, the drilling fluid had excellent rheology and filtration property. After standing for 24 hours, the density difference between the top and the bottom of the mud sample was 0.03-0.06 g/cm3, and the settling index was less than 0.508, indicating good suspending stability and high thixotropy. The friction coefficient of the mud cakes formed by the sample drilling fluid on an API filter press was as low as 0.0262, meaning that the drilling fluid had very good lubricity. Laboratory experiments also showed that this drilling fluid had strong inhibitive capacity and tolerance to drilled cutting contamination. After contamination with 5.0% and 8.0% British evaluation clay or drilled cuttings from the well VDW** (Cuba), changes in PV, YP and gel strengths of the drilling fluid were controlled within about 25%. The evaluation results also proved that this drilling fluid satisfied the needs for drilling shales of varied formation pressures.
Abstract: Presently the problem of wellbore instability in long horizontal wells is still a major technical problem in hindering the development of shale gas resources in the world. To solve this problem encountered in the long horizontal well section penetrating the shaly Longmaxi Formation, XRD analysis, pore volume tests by helium adsorption, high pressure mercury test, high resolution field emission SEM, CT scanning and continuous rock engraving strength experiments were used to analyse the micro petro-fabric and physicochemical characteristics of the Longmaxi shale, and their effects on borehole stabilization. The studies showed that the Longmaxi shale was rich in brittle minerals, and the clay minerals were mainly I/S mixed layers. Pores of micro-and nano-meters in sizes were developed, and micro cracks in the formation were slit shaped and in nearly parallel distribution. The presence of water sensitive minerals and the beddings developed therein as well as the micro fractures were the main factors causing shale wellbore instability. A set of wellbore stabilization measures was presented to solve these problems using inhibitive water base drilling fluid with synergistic effect, that is, borehole wall plugging strengthening-controlled inhibitive capacity of drilling fluid-reasonable density of drilling fluid-efficient lubrication of drilling fluid. A high-performance water base drilling fluid was formulated based on this technical strategy, exhibiting good plugging, and the ability to suppress crack propagation. This drilling fluid was used in drilling the 3rd interval of two wells in the Huangjinba block, successfully resolved the problems of wellbore instability and high friction in the long horizontal section of the Longmaxi shale, providing a new clue and experiences of using water base drilling fluid in the drilling and exploring shale gas resources.
Abstract: A degradable clear drilling fluid has been developed with a gel enhancer BZ-2 and a film fixating agent GMJ to resolve the contradiction between the safety of drilling operation and the protection of coal beds in coal-bed methane drilling. Laboratory experiments were done to evaluate BZ-2 and GMJ for their inhibitive capacity, rheology, residue contents, and their influences on the strengths of formation cores. The experimental results showed that the clear drilling fluid had percent shale recovery of 93.5%, YP/PV ratio of 0.93 Pa/mPafs, gel strengths of 2.5 Pa/3.0 Pa, yield point of 20.5 Pa, API filter loss of less than 12 mL, and residue content of 4.5 mg/L. The strength of the cores tested increased by 16.7%. This drilling fluid has been tested on 4 wells in the Zhengzhuang block, south of Qinshui basin in Shanxi Province. The test has successfully resolved the problems of drilling safety and coalbed protection in multilateral well drilling. Daily gas production rate has been increased by 2 times more than that of the wells nearby, and the calculated constant rate of gas production was between 3,000-5,000 m3/d, suggesting a good prospect of promotion.
Abstract: Oil-in-water emulsion drilling fluid is an important low-density water base drilling fluid and is widely used in drilling lowpressure reservoirs. To enhance the high temperature stability of the oil-in-water emulsion drilling fluid in deep well drilling, a sulfonated betaine with varied carbon chains was synthesized in laboratory and used in formulating emulsion drilling fluid after measuringthe change of its surface characteristics. Experimental results showed that the drilling fluid formulated had excellent rheology and good emulsion stability. After hot rolling at 180-210℃ for 16 hours, the viscosity and gel strengths of the drilling fluid were maintained in reasonable ranges. HTHP filter loss was less than 20 mL, satisfying the basic requirements as an emulsion drilling fluid. No oil separation and emulsification were found of the drilling fluid. The drilling fluid was resistant to contamination caused by 15% water, 15% diesel oil, 15% drilled cuttings, or by 2% salt, respectively, indicating that it was able to satisfy the needs for deep low pressure reservoir drilling.
Abstract: In high pressure jet drilling, the viscosity of drilling fluid at bit nozzle has long been a problem associated with the use of anionic filter loss reducers. A new drilling fluid filter loss reducer has been developed through the copolymerization of 2-Acrylamido-2-methylpropane sulfonic acid (AMPS), acrylamide (AM) and potassium acrylate at an optimum ratio of 7:6:1. The total concentration of these monomers was 17%. The filtration control performance and the rheology of the copolymer in fresh water drilling fluid, saltwater drilling fluid and saturated saltwater drilling fluid were studied. The studies showed that the viscosity of the copolymer synthesized in flow-control line was lower than the viscosity of the copolymer synthesized in three-necked flask under the same conditions, solving the problem of high viscosity at the bit nozzle caused by the conventional anionic filter loss reducers. The AMPS/AM/AA copolymer can reduce the filter loss of high salinity water base drilling fluids by 94%. It showed good filtration control and viscosifying performance in fresh water base fluid, saltwater base fluid and saturated saltwater base fluid. Thermal stability analysis and high temperature aging evaluation showed that the copolymer was able to retain its stability at 330℃, satisfying the needs for high temperature drilling fluids in field operation.
Abstract: The Syl gas field located in Country B has complex geological structures. 21 wells were drilled in this gas field, nine of which have encountered pipe sticking during drilling, 7 abandoned. During drilling of the 21 wells, 23 times of various drilling troubles took place. To better develop the Syl gas field, a cooperation agreement was reached between the National Gas Field Company Ltd. of the country B and Sinopec, which proposed 4 wells in this gas field. The Well Syl-25 was the first well to be drilled, with designed depth of 3,200 m, and actual drilled depth of 3,560 m. Different drilling fluid formulation were selected for use in different intervals. To avoid the flow of drilling fluid over the shale shakers in siltstone drilling, the bentonite content of the drilling fluid was reasonably increased and the inhibitive capacity improved. Good mud rheology, which was maintained to clean the hole, accompanied by reaming operation, overcame the problem of "sudden slim hole" along the sandstone section in the Block Syl. In drilling the fourth interval, amine based poly alcohol drilling fluid was used to stabilize the borehole wall. The Well Syl-25 was finally deepened to 3,560 m with the consent from drilling and geology engineers. Drilling of the hole section from 3,200-3,560 m, which had never been performed in the past in the country B, not only helped the engineers obtain lithological data of this section, it also found 7 extra pay zones with high production rates. Completion tests of the well gave birth to 640,000 m3/day industrial gas flow.
Abstract: Severe mud losses have frequently taken place in drilling the top formation in the Lukeqin oilfield located in the central region of the Mountain of Fire, Tuha Basin. Time spent in controlling mud losses accounted for more than 60% of the time drilling the top section, badly affected the development of the Lukeqin oilfield. Lost circulation control with conventional method, cement slurry squeezing, mixed lost circulation materials (LCMs), expandable LCMs, Neotoy fiber LCMs and gel LCMs, has been proved unsuccessful. For the effective control of mud losses in drilling the top section, a composite gel LCM was developed. The gel LCM is a water soluble high molecular weight polymer whose molecular chains exhibit spatial network gel structure. Based on the shear thinning property of structured fluids, some rigid LCMs of different particle sizes and deformable particles are introduced into the gel LCM to obtain close packing and consolidation of the LCM particles, thereby enhancing the pressure bearing capacity of the formation. The gel LCM has the ability to both prevent and control mud losses. The gel LCM has been tried on the well Yubei10-20, the well Yubei8-17 and the well Yubei8-16 located in the central region of the Mountain of Fire. Compared with other wells drilled in that area, the volume of mud lost was reduced by 74.3%, time spent controlling lost circulation was saved by 93.5%, and time spent drilling the top section was saved by 57.8%. The gel LCM has been proved to be an effective LCM in controlling lost return, mud losses into caves, and mud losses into fractures with only small volume of mud return.
Abstract: Drilling fluid additives have very complex composition which will cause corrosion to downhole drilling assembly, or even cause the drilling assembly to become unusable. To resolve this problem, corrosion inhibitors for use in KCl drilling fluids have been selected through weight loss method, electrochemistry experiment and SEM, and the mechanisms of corrosion caused by KCl drilling fluids have been studied. The best corrosion inhibition results were obtained with this drilling fluid composition:0.7% silicon compound + 0.7% diethylenetriamine + 0.1% triethylenetetramine, the rate of corrosion inhibition was 90.36%. Electrochemistry and SEM tests showed that the corrosion inhibitor selected for use in KCl drilling fluid had good corrosion inhibitive capacity and application prospect.
Abstract: Drilled cuttings from wells drilled with oil base drilling fluids are waste solids containing mineral oils, phenol chemicals and heavy metals. As a complex multiphase system, the waste solids have been listed in the national hazardous waste catalog. To reuse the oil base waste solids, laboratory experiments have been conducted on the oil base waste solids for their percent residue oil retained, water content, gross heat value, element content and burning performance. The experimental results showed that an oil base waste solid with residue of 74.006%, retained oil of 18.71%, and gross heat value of 8,000-9,000 J/g can burn steadily, without the need for auxiliary fuels. The waste solids tested had gross sulfur of 5.3%, and the average total sulfur content in the combustible constituent was 1.25%, and the nitrogen content was low. All these factors considered, it can be concluded that the discharge of the oxides of nitrogen and the oxides of sulfur from the combustion of the waste solids would not be high. The chlorine content of the waste solids was 0.346,7%, meaning that the probability of producing dioxin would be low. Heavy metal content in the burned residue of the waste solids was low, indicating that the waste solids can be backfilled.
Abstract: Sulfonated asphaltene, an additive widely found in water base and oil base drilling fluids,is generally used to effectively plug the micro fractures, prevent sloughing shales from collapsing, and inhibit shale from becoming hydrated. It also has good lubricity, emulsifying capacity, and abilities to reduce filter loss and to stabilize mud properties at elevated temperatures. The content of sodium sulfonate in sulfonated asphaltene is an important index ofevaluating the quality of the sulfonated asphaltene; the higher the content of the sodium sulfonate, the better the quality of the sulfonated asphaltene. In laboratory studies, the ion chromatography and element analyzer were used together to establish a fast way of measuring the content of sodium sulfonate in sulfonated asphaltene. Using this method, the relative standard deviation (RSD) of the measuring result of each sample was less than 1% (n=5), indicating that this method had good repeatability. Experimental results demonstrated that this method is fast, reliable and easy to use in measuring the sodium sulfonate content in a sulfonated asphaltene.
Abstract: Nano material is able to accelerate the hydration of cement. Nano silica has recently been widely studied for its use in well cementing. Nano silica accelerates the hydration of cement excessively because of its high specific surface area. Calcium silicate hydrate seed crystal, an artificially synthesized nano calcium silicate hydrate, can accelerate the hydration of cement through nucleation. Using Ca(NO3)2·4H2O and NaSiO3·5H2O as raw materials, a calcium silicate (C-S-H) seed crystal was developed through precipitation reaction, and study on the use of C-S-H as oil well cement accelerator was conducted. The heat of hydration and hydration rate of cement were measured unintermittently at 10℃ for 96 hours with Tam air isothermal calorimetry. It was found that with an increase in the concentration of the seed crystal, the induction time of cement hydration was notably shortened, and the amount of heat released was increasing. The developing progress of the strength of the set cement, measured with an ultrasonic strength analyzer in the study, indicated that the use of seed crystal notably shortened the time required for the cement slurry to develop strength, and the rate of strength development of the set cement increased obviously. The more the seed crystal used, the faster the development of the strength of set cement. It was also found that the addition of the seed crystal did not notably increase the viscosity of the cement slurry. From these studies it is understood that the C-S-H seed crystal is able to accelerate the hydration of cement, increase the early strength of set cement and shorten the induction time for gel strength development. It is a potential low temperature accelerator.
Abstract: Cementing slurries formulated with seawater are generally used in cementing the wells penetrating high pressure saltwater zones, long salt/gypsum formations, or wells drilled offshore. Friction reducers commonly used are difficult to disperse in the seawater cementing slurries, and have short dispersion duration and strong retarding performance. A polycarboxylic acid friction reducer with comb-like molecular structure has recently been developed to overcome these problems. The friction reducer was synthesized through free-radical polymerization, and was studied for its molecular structure and thermal stability using IR, SEM and thermogravimetric analysis. The effects of the friction reducer on the rheology, thickening performance and strength of cement slurries were measured in accordance with relevant industrial standards. The adaptability of the friction reducer to cement slurry was also studied. Thermogravimetric analysis showed that the friction reducer was stable at temperatures as high as 233℃. SEM and atomic force microscope measurement demonstrated that the friction reducer had comb-like molecular structure. This friction reducer was highly dispersible in cement slurries formulated with saturated saltwater or seawater, and had weak retarding power. It didn't deteriorate the strength of the cement slurries which were formulated directly from seawater.A cement slurry treated with the friction reducer had density of 2.72 g/cm3, filter loss of 24 mL, 24 h strength of 22 MPa, and good stability and rheology at 90℃. Good dispersity in saturated saltwater and good adaptability to high density cement slurry indicated that the comb-like polycarboxylic acid friction reducer was of high efficiency.
Abstract: In shale gas drilling, the residues of oil base drilling fluid on the borehole wall and the surface of the casing strings have long been a problem. The residual oil base drilling fluid will inevitably be mixed with and therefore render contamination to cement slurry. The surface of casing and the borehole wall, which are long in contact with oil base drilling fluid, can become lipophilic or hydrophobic, thus bringing about many problems, such as difficulties in displacing the oil base drilling fluid and cleansing the casing string, poor rheology of the mixed slurry, reduced strength of the contaminated cement slurry, and poor bonding of the interfaces between cement sheath and casing string and the interfaces between cement sheath and the borehole wall. Laboratory studies have been conducted on surfactants and spacers to resolve the problems mentioned above. The studies included the following:1) investigating the mechanisms of the contact contamination between oil base drilling fluid and cement slurry; 2) verifying the flushing efficiency of surfactants by measuring surface tension; and 3) measuring the flushing efficiency of surfactant solution and spacer using simulated casing flushing experiment. The results of the studies showed that use of surfactant remarkably decreased the oil-water interface tension, hence enhanced the flushing efficiency. A compounding surfactant spacer, having a flushing efficiency of 92.86%, was formulated with three surfactants in a ratio of LAS:JFC-6:AOS=1:1:1. The spacer was able to enhance the bonding quality of the interfaces between casing and cement sheath and the interfaces between cement sheath and borehole wall, and was helpful in improving the quality of shale gas well cementing.
Abstract: Oil base drilling fluids (OBMs) are widely used because of their high temperature stability, resistance to salt and calcium contamination, good lubricity and low filtration rate, the problems of using OBMs are difficulty in cleaning them off the borehole wall and casing string and being ready to flocculate, thus negatively affecting the quality of well cementing. To effectively flush residue OBMs off the borehole wall and the surface of casing strings, a water base flushing fluid, TGD-65, was formulated, with furfuraldehyde as flushing additive. BHA, a high temperature stabilizer for furfur-aldehyde was used for the flushing fluid (called TGD-60) to work at elevated temperatures. Experimental results showed that BHA had the ability to enhance the high temperature stability of furfur-aldehyde, rendering TGD-60 good emulsification dispersion to OBM at 160℃, completely breaking the structure of OBM to small-sized droplets. The OBM was finally turned into oil-in-water emulsion. Meanwhile the flushing fluid after high temperature treatment had good wettability to the mud cakes formed by OBM, and the flushing efficiency at high temperatures was enhanced from 79.71% to 99.18%.
Abstract: Cement slurry with thickening time of regular pattern is the premise for safe cementing operation. Abnormal thickening time will bring about severe bad effect on well cementing. In temperature range of 100-120℃ changes in the hydrated Portland cement will take place. The thickening time of the cement slurry is of poor regularity, sometimes resulting in reversed thickening or the failure of cement retarder, bringing about hidden dangers to the safety of well cementing operation. A new polymeric cement retarder, CCH120, has been developed and a temperature sensitivity resistant cement slurry (for use in big temperature difference well cementing) treated with the CCH120 has been compared with the presently available cement slurries for their performance. It was found that in 100-120℃, in which cement slurries exhibit temperature sensitivity, the thickening time of the CCH120 treated cement slurry was gradually shortened as the temperature was increased, and no reversed thickening was observed. The mechanisms of this phenomenon are explained in this paper. This cement slurry has temperature sensitivity resistance, thickening time with strong regularity, low fluid loss, high compressive strength, and fast strengthening at the top of the cement slurry.
Abstract: A toughness-enhanced cement slurry was formulated to cement gas storage wells which have special requirements for the toughness of set cement. A surface modified rubber powder (particle size between 0.15 mm and 0.18 mm) and a polypropylene fiber were used in the cement slurry as an elastic enhancer and a toughening agent, respectively. The optimum concentrations of the elastic enhancer and the toughening agent were determined to be 3.0% and 0.1%, respectively, through laboratory experiments. PVA latex was used as a filter loss reducer to minimize the brittleness of the set cement, improving its impact resistance and antibreaking performance, and satisfying the needs of cement sheath for long-term airtightness under frequent high-pressure injection and production. Laboratory experiments were done to evaluate the toughness-enhanced set cement for its elastic modulus, anti-breaking strength, compressive strength, bonding strength, permeability, and the airtightness of the cement sheath under stress. Compared with the set cement formed with base cement slurry, the elastic modulus of the toughness-enhanced cement slurry was reduced by 43%, the anti-breaking strength was increased by 118%, and the permeability of the set cement was less than 0.05 mD. These data indicated that the toughness-enhanced cement slurry was able to satisfy the needs for airtightness of the cement sheath under 35 MPa and 35℃ temperature difference, suitable for cementing gas storage wells.
Abstract: In reservoir fracturing with liquid CO2 (LCO2), low viscosity of the fracturing fluid has long been a problem restricting the spread of this new fracturing technology.The phase change of LCO2 after mixing it with a thickening agent LPE and a micelle enhancer CJ-1 has been studied to investigate the thickening mechanisms of LCO2 -LPE-CJ-1. HAAKE viscotesters (Model D300/D400) were used to verify the thickening effect of LPE+CJ-1 on the LCO2. Using polarizing microscope, the state of the micelles of the LCO2 -LPE-CJ-1 fracturing fluid was studied. The experimental results showed that LPE and CJ-1 can thicken the LCO2 -LPE-CJ-1 fracturing fluid to about 112 mPa·s, nearly 6 times of the highest viscosity of LCO2 (20 mPa·s)that had been reported previously. The thickening mechanismsare that,through ionic complexation between the molecules of LPE and CJ-1, the two molecules form rod-shaped micelles, a structure analogous to the 3-D spatial network structure formed by the intertwined molecules of a crosslinked polymer.
Abstract: In view of the current fracturing operations toward high-temperature oil and gas reservoir measures, water saving, mixing fracturing fluid by seawater or high salinity water, and other unconventional areas of development based on the study of the mechanism of hydrophobic associative polymer fracturing fluid, a self-association high salt-resistant fracturing fluid system was developed using the principle of anion and cation suction. Performance evaluation and field application of this kind of fracturing fluid system were carried out. Results show that addition of the anionic surfactant named dodecylbenzenesulfonic acid to the cationic polymer solution made the polymer molecules occur self associative reaction of electrostatic attraction; the addition of spherical micelles, calcium and magnesium ion stabilizer, enhanced the anti-temperature and salt resistance performance of the fracturing fluid.The fracturing fluid system viscosity can reach 331 mPa·s, it's salt resistant to 60,000 mg·L-1 and it has good resistance to calcium and magnesium,the core damage is lower than other fracturing, and the viscosity can be maintained above 50 mPa·s at 130℃and 170 s-1 shear 1h, which can meet the requirements of water temperature distribution and fracturing construction at the temperature of 60-130℃. Moreover, the viscosity of the fracturing fluid decreases with the increase of shear rate and the viscosity will be restored when the shear rate decreases,this shows that it can effectively reduce the friction resistance.The system is applied in the field of 3-26 well in the Erlian of North China oil field,It uses the mineralization degree of 9,104 mg·L-1 of the formation of water directly to the liquid, which can improve the construction efficiency and increase the oil effect obviously.This system is easy to get raw materials, low cost, salt resistance is better than other fracturing fluid system, so it has a good application prospect.
Abstract: Deficiencies exist in empirically predicting the friction reducing efficiency of slick water fracturing fluids in field operation, yet the experimental methods presently in use for evaluating the performance of friction reducers are only focused on the performance comparison and product optimization, while the illustration of how to apply the test results to field operation is rarely seen in literatures. To resolve this problem, a laboratory loop-line friction measurement system has been established. According to the Prandtl-Karman law, the diameters of three straight pipes used in the system were determined to be 10.46 mm, 7.59 mm and 5.86 mm using turbulent flow rate of clear water. For any one of the pipe diameters, the frictional pressure drops of five different concentrations of DR-800 (a friction reducer) water solutions were tested at a certain flow rate. For the 0.07% and 0.10% DR-800 solutions, the test pressure drops were converted into frictional coefficients, and then corresponded with the Reynolds numbers calculated which took into account viscosity. In this way the frictional coefficients can be satisfactorily fitted with Virk asymptote, and the excellent performance of the DR-800 was proven. After quantitatively measuring the friction reducing performance, using friction-velocity method (a submethod of the so-called friction amplification method), the ratios of friction reduction and velocities-under-friction obtained from the experiments can be regressed into a mathematical expression that can be used to work out the rate of friction reduction corresponding to a specific velocity-under-friction. Using this expression, a comparatively affirmative rate of friction reduction under a work condition can be determined through iteration. The calculation has better precision than empirical prediction, and the laboratory study method is instructive to the field application of friction reducers.
Abstract: In recent years, reports have been found of new clear fracturing fluids, a liquid system with "supramolecular structure" formulated with hydrophobically associating polymers and surfactants. Most of the reports have focused on the development and performance evaluation of the polymeric thickeners, while the mechanisms of forming molecular network and regaining viscosity through shearing of the fracturing fluids have rarely been studied. To study the mechanisms mentioned above, varied shearing rheology experiment, environmental scanning electron microscope (ESEM) experiment and proppant suspending experiment have been conducted, and the effects of molecules' self-assembly on the two mechanisms have been visually analyzed and explained. The analytical results demonstrated that the "spatial networking structure" of the association fracturing fluid is formed through the "shared" micelles between hydrophobic molecular side-chains and surfactant molecules, inter-molecular association and inter-molecular entanglement of the hydrophobically associating polymer. When shearing of the fracturing fluid is stopped, the shear-broken surfactant molecules will form new "micelles" through self-assembly, and further re-form new "networking structure" with the hydrophobic side-chains of the shear-broken hydrophobically associating polymer. "Sliding movement" between two layers of molecules causes the new "networking structure" of the "association fracturing fluid" to be in a "dynamic equilibrium" state, and to suspend proppants with much tighter "networking structure".
Abstract: Wells drilled in the offshore low porosity low permeability M oilfield are completed with conventional completion fluidsthatlack the ability to stimulate the reservoirs. A composite well completion and stimulation fluid has recently been formulated with some optimized additives suitable for use in low porosity low permeability reservoirs, such as a clean-up additive HWDA-2, a corrosion solvent HTA-H, a corrosion inhibitor HCA101-8, and a demulsifier (with emulsification prevention ability) H409. This fluid is both a well completion fluid and a stimulation fluid. In laboratory experiments, the fluid showed percent reduction of core swelling of 96.4% and percent permeability recovery of 120%, indicating that the fluid had good inhibitive capacity and low corrosion. Application of the fluid on two wells acquired lower skin factor and higher specific productivity index compared with other wells completed with conventional latent acid completion fluids. Early-stage oil production was increased by about 30%, indicating that the fluid had good stimulation capacity.
Abstract: The chelating agent used was mainly composed of diethylene triamine pentacetic acid (DTPA). It was neutralized with KOH until the pH was 13, and then treated with a certain amount of inorganic salts. This solution was used to dissolve out barite powders. The experimental results showed that, at a certain mass ratio of DTPA, the efficiency of potassium salts as solubilizing agent was 2 times of that of sodium salts due to the effect of the solution viscosity. Increasing the mass ratio of the inorganic salt, the efficiencies of potassium carbonate, potassium fluoride and potassium chloride as solubilizing agents in dissolving barite were correspondingly enhanced. At 10% of potassium carbonate, 47.79% of barite was dissolved. After 4 h of reaction, the conglomeration of barite led to an increase in reaction area, increasing the solubilizing efficiency of potassium carbonate to a value that was 10.56% higher than that of potassium fluoride. After reacting for 12 h, the reaction tended to complete, the solubilizing efficiency of potassium fluoride was instead higher than that of the potassium carbonateby 12.39% because of the salt effect on the reaction endpoint. The steady configuration of the DTPABa3-ions was obtained through computerized simulation, and the cause of low complexation constant of barium ions was analyzed. A chelating agent was chosen based on the study and was used on a well blocked with barite. The flowback fluid was analyzed for inorganic salts and precipitated sulphate using XRD. Barium was found in the precipitates, indicating that the well was successfully unblocked.
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