Abstract: Unlike conventional cements, synthetic resins as a new cementitious material have unique advantages and are hotspot in recent studies. This paper, on the bases of summarizing and analyzing the categories, advantages and disadvantages and curing mechanisms of synthetic resins, presents property requirements for synthetic resins as cementitious material in oil and gas well applications. Latest studies on synthetic resin cementitious materials developed both in China and abroad are also summarized in this paper. The development trend of synthetic resin cementitious material is discussed on the bases of the status quo of synthetic resin studying.
Abstract: In horizontal drilling, high friction, high torque and HTHP impose much more rigorous requirements on the lubricity and anti-wear capacity of drilling fluid lubricants. Conventional drilling fluid lubricants are not able to satisfy these requirements. A highperformance anti-wear lubricant SDL-1, has been developed based on "solid-liquid" synergism. A modifed vegetable oil MVO-3, a modifed expandable graphite GIC have been used with dispersant, emulsifer in the development of SDL-1. Laboratory evaluation experiment showed that 5% fresh water bentonite mud treated with 0.5% SDL-1 has coeffcient of friction reduced by at least 85%, and 4% brine mud treated with 0.5% SDL-1 has coeffcient of friction reduced by at least 70%. SDL-1 is well compatible with drilled fluids used in actual drilling operations. It functions normally at 150℃, has low foaming capacity. The fluorescence level of SDL-1 is less than 5. Pin-disc friction and wear test results showed that SDL-1, as a lubricant that is worth spreading, has excellent anti-wear capacity and good lubricity, and is able to effectively mitigate or resolve high friction high torque problems encountered in complex well drilling.
Abstract: Th establishment of conventional pressure gradient models is based on the idea that the cross section of a wellbore is round, however, in practical situation, the cross section of a wellbore is elliptical under the influence of non-uniform in-situ stresses. The flow pattern in annular space of an elliptical cross-section wellbore is obviously different to the flow pattern in annular space of a round cross-section wellbore. Based on the basic equations of fluid mechanics, a concept of "effective hydraulic diameter" has been introduced in establishing a pressure loss model of annulus flow in elliptical wellbore. Studies showed that with an increase in the ratio of long radius over short radius of an elliptical wellbore, the average flowrate in the annular space decreases, and the annular pressure gradient decreases with it. The greater the ratio of the long radius over the short radius of an elliptical wellbore, the more obvious the grading of the high and low flowrate areas along the helix direction of the annular space. Furthermore, compared with simulation results (using the CFD software), this model has calculation errors that are in a range of less than ±10%. Analyses of affecting factors indicated that when other conditions remain constant, the annular pressure gradient of a elliptical wellbore increases somewhat linearly with increases in annular flowrate and yield point and consistency index of the fluid, and somewhat exponentially with increases in flow index. The model established based on the studies can be used to calculate the wellbore pressure of an elliptical wellbore.
Abstract: Polymers are generally used for viscosifying water base drilling fluids, but their tolerance to high temperature is not suffcient to meet the requirements of ultra-high temperature water base drilling fluids. It is thus proposed that artifcial hectorite can be used as an ultra-high temperature viscosifer for water base drilling fluids. Characterization of the structure of the synthesized hectorite with X-ray powder diffraction and TGA showed that the synthesized hectorite, H-6, has excellent viscosifying property and thermal stability; it is able to function normally at temperature of up to 240℃, and its viscosifying effect at high temperature is superior to other high temperature viscosifers presently used worldwide. Testing of a 4% sodium-bentonite water base mud treated with 1% H-6 showed that after aging at 240℃ for 16 hours, the water base mud had the same apparent viscosity of 16.5 mPa·s, before and after aging. As a comparison, another 4% sodium-bentonite water base mud treated with 1% HE300, a high temperature viscosifer, had its viscosity reduced by at least 92% after aging at 240℃ for 16 hours. Laboratory study showed that H-6 is compatible well with other commonly used additives, and is suitable for use in water base drilling fluids as an ultra-high temperature viscosifer. It will fnd wide application in formulating ultra-high temperature water base drilling fluids.
Abstract: The preparation of measures to prevent and control CO2 contamination requires an accurate determination of the concentration of contaminants and an understanding of the patterns in which the contaminants affect the properties of drilling fluids. Field quantitative method of determining the alkalinity of drilling fluids was improved, based on the principle of color change with acid/base indicators, to have a better accuracy and operability. Analyses of feld sampling and laboratory evaluation were performed to study the effects of CO2 on the rheology and fltration property of high-density water base drilling fluids. Study was also conducted on the effects of CO2 on the Zeta-potential of the surfaces of clays used in drilling fluids, particle size distribution of clays and adsorption of mud additives from the point of view of colloid chemistry, and on the mechanisms of the effects. The studies showed that the concentrations of carbonate and bicarbonate ions in high-density water base drilling fluids have critical values; when the concentrations of carbonate and bicarbonate ions exceeds the critical values, the structural viscosity and fltration rate of drilling fluid increase with the increase in the concentrations of the carbonate/bicarbonate ions. Carbonate/bicarbonate ions have altered the extent of the solubilization and the sizes of clay particles, which can be seen from the decrease in the Zeta-potential of the surfaces of clay particles, the decrease in the number of submicron-sized particles and the increase in the number coarse particles. Decrease in the adsorption quantity of colloid protective agents by clay particles results in the coalescence of clay particles and association of the clay particles to form a gel with 3D network structure. These phenomena have revealed the intrinsic mechanisms governing the macro property changes.
Abstract: A new flming plugging agent, CMF, has been developed to deal with the problems encountered in drilling the brittle fractured shale formations in an oilfeld in the Liaodong Gulf area. CMF is formulated with nesquehonite whisker, hydrated basic magnesium carbonate wafer and a commonly used flming agent LPF-H. The nesquehonite whisker and the hydrated basic magnesium carbonate wafer, having length/diameter ratios of 20-30, were developed under controlled reaction conditions. The ratio of LPF-H, the whisker and the wafer is 7:1.6:0.4. Laboratory experimental results showed that CMF has good compatibility with the drilling fluid treated with it, and the rheology of the drilling fluid is able to satisfy the needs of cuttings carrying. Experiment on sand specimens of different porosity showed that CMF is superior to LPF-H in plugging the sand specimens. The synergism of the whisker, the wafer and LPF-H results in a dense and tough flm on the borehole wall, effectively plugging the formation fractures and stabilizing the borehole wall, and therefore reducing the consumption of drilling fluid additives. Application of CMF on the well X-1 in an oilfeld in Liaodong Gulf showed that the properties of the drilling fluid treated with CMF satisfed the needs of drilling operations. The fltration rate of the drilling fluid was lower than that of the drilling fluid (treated with LPF-H) used on the adjacent well X-2, indicating that CMF is able to protect the reservoir from being damaged, and is therefore worth spreading.
Abstract: A mud loss control fluid was formulated to control mud loss under pressure during drilling the fractured Ordovician reservoirs in the Block Tahe 10, where mud losses prevailed in the past drilling operations. This mud loss control fluid was formulated with optimized sized acid soluble materials. In determining the sizing of the particles of the lost circulation materials (LCM), the amount of mud losses was used as the main evaluation index based on the sizes of the fractures found in the formations of the reservoir, and the response surface methodology (RSM) was used for optimized design of the sizing of the particles. Laboratory evaluation results showed that the particle size distribution has a continuous and wide-spanned distribution curve. Fractures of any sizes can be plugged with enough particles of matching sizes. Three mud loss control (under pressure) fluids for different sizes of fractures were formulated using the particle sizing technique. These fluids performed very well in controlling mud losses and pressure bearing capacity was greater than 8 MPa. The volume of mud loss through 3 mm fractures was less than 200 mL, and the volume of mud loss through 2 mm and 1 mm fractures was less than 50 mL. More than 99% of the LCM was dissolved by acids, while 98.4% of the particles in the layers of LCM formed on the surfaces of the borehole wall can be acid dissolved.
Abstract: Fibers are the main component of bridging lost circulation material (LCM) frequently used in dealing with drilling/drill-in fluid losses into fractured reservoir formations. Fibers commonly used in LCM slurries have low acid solubility, which does not satisfy the needs of acid stimulation of the fractured reservoir. A highly acid soluble fber LCM, SDSF, has been developed to resolve this problem. SDSF has average diameter between 10 μm and 30 μm, lengths between 3 mm and 12 mm, which can be adjusted based on operational requirements. Acid solubility of SDSF is about 95%, and SDSF functions normally at high temperatures up to 150℃. SDSF disperses very well in water base drilling fluids, and is resistant to the attack of bases. Fibrous LCM slurries suitable for controlling mud losses into wedge-shaped fractures of different opening widths were optimized using SDSF and other highly acid soluble particle bridging agents. The maximum pressure bearing capacity of these LCM slurries is 10 MPa. Lost circulation control with highly acid soluble fbrous LCM can be used as an effective technical means of resolving problems such as drill-in fluid losses into reservoir formations and removal of formation block by LCM particles.
Abstract: To avoiding borehole wall collapse drilling in brittle coal beds full of micro fractures, an emulsion anti-sloughing plugging agent has been developed with hydrophilic monomers and hydrophobic monomers through O/W emulsion polymerization. Laboratory studies showed that the dispersion of the anti-sloughing plugging agent has particle sizes ranging in 0.1-1.5 μm, which match the sizes of micro fractures developed in the coal beds, meaning that the micro fractures can be effectively plugged with the plugging agent. This plugging agent can render the surface of coal beds oil-wettability and thus greatly mitigates the dispersion of coals in water. In bentonite slurry, the plugging agent can reduce API flter loss, thereby enhancing the plugging performance of the bentonite slurry. Coal samples rinsed in the solution of the plugging agent had their compressive strength increased. Drilling fluids treated with the anti-sloughing plugging agent have good rheology and fltration property, and cause low damage to coal beds. Percent recovery of permeability of coal samples tested with water can be as high as 95.4%. A drilling fluid treated with the anti-sloughing plugging agent was used on the well SX-2** to drill the coal bed formations from 795.00 m to 1088.00 m. The drilling operation and coring job was successful. Percent recovery of cores taken from the coal section was 96.51%, and the integrity of the coal formations was maintained pretty well.
Abstract: Sealability can be characterized by the change of permeability before and after sealing. As to shales, their permeability is diffcult to measure accurately using regular static permeability measuring methods because of the low porosity and low permeability characteristics of shales. Based on plenty of permeability measuring practices, a method of measuring the permeability of shales with ultra-low permeability was proposed. This method, the so-called transient pressure pulse method, is able to measure permeability to 1×10-7 mD. A shale sealability simulation evaluation instrument has been developed based on the transient pressure pulse method. This instrument is able to accurately measure the change of permeability before and after a low porosity low permeability shale is flooded and sealed. The application of the instrument has to some extent resolved the problem of measuring the permeability of sealed shales, providing technical support to evaluating the shale stability of a well and to the large-scale of shale gas development.
Abstract: Wellbore instability has been a risk encountered in drilling the Weizhou formation in Weixinan oilfeld, Beibu Gulf Basin, west of South China Sea, because of the effects of tectonic stresses and the hard and brittle shales existed in the formation. Diffculties in pulling out of hole, wellbore instability and poor well cementing quality are problems found in using conventional oil base drilling fluids. A new high-performance oil base drilling fluid, with oil/water ratio of 95:5, has been developed based on the analyses of the application of conventional oil base drilling fluids and through optimization of emulsifer, plugging agent and gelling agent. This new oil base drilling fluid had the good borehole wall stabilizing capacity, good plugging capacity, excellent ECD control ability, and tolerance to contamination of 15% low quality clay. Percent recovery of permeability of cores contaminated by this new oil base drilling fluid was more than 90%, with flowback pressure of only 0.4 MPa, indicating that the oil base drilling fluid had good reservoir protection capacity. Field application of the oil base drilling fluid showed that when drilling the Member Ⅱ of the Weizhou formation, the drilling fluid had stable rheology, good plugging capacity and good hole cleaning performance, no mud losses happened during drilling. It only spent 8.09 d to drill 2,500 m of the well, 48% less than the drilling time spent previously drilling other development wells nearby. Reservoir was also well protected. The success of the drilling operations with the new oil base drilling fluid provides a good clue for oilfeld development in areas similar to Beibu Gulf Basin.
Abstract: The shallow gas reservoir presently produced in the D gas feld in western South China Sea is located in the Yinggehai formation of the Tertiary System, which is a medium porosity medium permeability mudstone reservoir. This formation has complex geological characteristics, and sloughing, borehole collapsing and pipe sticking have all been encountered during drilling operation in the past. Based on the studies on the rock properties of the reservoir and the problems associated with the drilling fluids it was concluded that the plugging and inhibitive capacity of the drilling fluids should be strengthened. That being said, the drilling fluid (PRG) previously used to drill the φ311.1 mm was treated with VIS to retard the invasion of mud fltrate into the formation and to minimize the erosion of drilling fluid to the borehole wall. The concentration of PLUS in the drilling fluid was reduced and PFFLOTROL increased to reduce viscosity and flter loss. In the φ215.9 mm interval, the PRF mud was treated with Greenseal to plug micro fractures and pore throats, and to retard the fltration of mud fltrate, thereby prolonging the time of borehole wall stability. Using more EZCARB and weighting the mud with KCl, the inhibitive capacity of the mud was improved. Evaluation experimental results showed that PRG and PRF muds had low flter loss (API fltration rate was 2.1 mL and and HTHP fltration rate was 4.3 mL), good rheology, strong inhibitive capacity (shale cuttings recovery on hot rolling test was ±90%) and excellent contamination resistance (salt resistance to 10% and calcium resistance to 2%). Application of the PRG and PRF drilling fluids on well P3H and D4H in D gas feld showed that downhole troubles previously encountered, such as bit balling, pipe sticking and mud losses were successfully avoided.
Abstract: The formation rocks of the reservoir in Block Wushi in Beibu Gulf, west of South China Sea, have low permeability and are developed with hard and brittle shales. Shales, plus small-sized pore throats and severe water sensitivity resulted in serious formation damage by water block, and high skin factors. Borehole wall instability and washout during drilling resulted in frequent drilling accidents. To resolve these problems, a new drilling fluid has been formulated based on the composition of the drilling fluid previously used, through selection of a fluorocarbon water block preventing agent, reduction of oil/water interfacial tension, using flming plugging agents and optimizing the size distribution of CaCO3 particles. This new drilling fluid not only helped stabilize borehole wall, it also had low fltration rate and was able to prevent drilling fluid particles from entering the reservoir formations, thereby protect the reservoir from being damaged. Laboratory evaluation results showed that the fltration rate of the drilling fluid and the invasion depth of solid particles and fltrate were all remarkably reduced. HTHP experiment and solid particle distribution in mud fltrate showed that the invasion depth of solid particles was reduced. SEM experiment showed that HTHP mud cakes were dense and smooth. The percent damage by water block was reduced to 17.5%, and the percent recovery of core permeability was greater than 80%. Field application of the new drilling fluid in Block Wushi showed that it has the ability of better stabilizing borehole wall; the rate of hole enlargement was only 5.4%. Skin factor was only 1.2, indicating that the drilling fluid is capable of protecting the reservoir. The drilling fluid technology used on this well is of reference signifcance in designing drill-in fluids for low permeability reservoir drilling.
Abstract: Wellbore instability, inability to exert weight-on-bit and adhesion of asphalt on drilling tools and solid control equipments are diffcult problems associated with SAGD (steam-assisted gravity drainage) horizontal drilling. A water base drilling fluid with high inhibitive capacity and good lubricity has been formulated, based on additive selection through laboratory experiment, to resolve these diffcult problems. This drilling fluid in laboratory experiment showed good properties, such as high temperature resistance (180℃), resistance to contamination caused by 20% asphalt and by 25% drilled cuttings, and percent cuttings recovery of 91.7% in hot rolling test. The lubricity of the drilling fluid is equivalent to that of oil base mud. This drilling fluid was used on 10 SAGD horizontal wells in Block Maikaihe, showing stable and easy-to-control properties, and good lubricity. High ROP was obtained with the use of the formulation. Ho downhole troubles have ever been encountered during drilling. This water base drilling fluid of strong inhibitive capacity and good lubricity fully satisfed the needs of shallow oil sand SAGD horizontal well drilling, and is worth spreading.
Abstract: Oil cuttings, as a kind of oil-bearing hazardous waste, pose grave effect on environment, ecology and safety. An extraction agent CQJ, has been developed to deal with oil cuttings produced in shale gas drilling. Compared with commonly used solvents, CQJ has advantages such as high flashing point, low volatility, good extraction performance and low toxicity. In a pilot test, oil cuttings of 56 m3 taken from a shale gas block in Sichuan were treated with CQJ. The test results showed that average oil content in the cuttings after treatment was 0.76%, and 91.5% of the oil in cuttings was recovered. CQJ can be used repeatedly, and the oil extracted can be used again in preparing oil base drilling fluid. Harmlessness, resourcing and avoidance of secondary pollution are realized with the use of CQJ.
Abstract: In thermal production heavy oil well cementing operations, loss of cement sheath integrity caused by high heat load produced during steam injection results in wellhead uplift. This phenomenon, which is widely found in the development of offshore thermal production heavy oil wells, and is of great harm, imposes great impact on the production life of the well and results in well control risks. Research work has been conducted on the cement sheath integrity of the thermal production wells in Bohai oilfeld. Based on heat transfer analyses, a 3D temperature feld analysis model for heat injection wellbore and a model for the cement sheath integrity analysis under the condition of coupling of heat load, load of nitrogen injection and non-uniform in-situ stresses have been developed. Measures for enhancing the integrity of cement sheath in thermal production well have been presented from drilling fluid, feld operation techniques and the performance of the thermal insulated tubing etc. Application of the models and the measures showed that the 3D temperature feld profle of a thermal production steam injection well can be effectively simulated, the damage mechanisms of the integrity of the cement sheath and the failure type of the cement sheath under heat load can be determined. This study is of reference to the development of new thermal production wells, and has wide application prospects.
Abstract: Frequent water invasion in water injection blocks in China gravely undermine the strength and bonding quality of set cement. A dispersion resistant flocculant BCY-100S has been developed to deal with these problems. BCY-100S is produced through radical polymerization and is used in preparing cement slurries for oil well cementing. The flocculating capacity and heat resistance of BCY- 100S were measured through zeta-potential analysis and TGA. The effects of BCY-100S on the performance of cement slurry to resist water invasion and on the thickening property of cement slurry were tested. It was found that BCY-100S functions normally at temperatures up to 324℃. Cement slurries treated with BCY-100S have to some flocculating ability. The BCY-100S treated cement slurries did not disperse or segregate when flushed with water at 80℃. Compared with cement slurries that were not treated with BCY- 100S, the cement slurries treated with BCY-100S were able to resist water flooding. BCY-100S does not affect the thickening time of cement slurry, which is a requirement of oil well cement property. Considering the effects of formation fluids on set cement, such as "migration after dissolution" and "mass interchange", the use of BCY-100S has provided a new method of resolving these problems.
Abstract: Foams developed in mixing oil well cement slurry, especially latex cement slurry, are diffcult to remove and therefore result in cement slurry with reduced density and diffculties in mixing cement and pumping the slurry. A new defoamer recently developed is able to eliminate the foams developed in makeup water and foams developed during slurry mixing. It works very well in mixing latex cement slurry. When agitated at 4,000 r/min, time spent in defoaming makeup water and the cement slurry was less than 10 s, and the foaming height was less than 10 mm. The defoamer imposed no negative effect on the rheology, strength and thickening properties of the cement slurry. The synthetic process of the defoamer is simple. Pilot production product of the defoamer has been used in feld well cementing operations and has good prospects of popularization.
Abstract: Surface properties of high-performance hollow glass microbeads (HGM) used in cement slurry were studied using SEM, XPS, silicon molybdenum yellow spectrophotometry, turmeric paper and titration methods, and the effects of HGM on the properties of cement slurry evaluated. It was found that the particles of HGM are in spherical shapes of different sizes. Some of the spheres have cavities on their surfaces. The composition of HGM, apart from glass, includes small amount of organic coupling agents on the surfaces of HGM. Also on the surfaces of HMG are soluble adhesive substances such as sodium silicate and sodium borate. The amount of the adhesive substances is different in different batches of HGM. Too many adhesive substances on the surfaces of HGM have bad effects on the properties of cement slurry. In the adhesive substances, the soluble boron content is the main factor affecting the properties of cement slurry, and should be controlled when selecting HGM for well cementing. According to laboratory experiment, borax does not affect signifcantly the properties of cement slurry if the content of borax is less than 0.38%, thus, HGM with borax content in this range is preferred in terms of oil well cementing.
Abstract: To use microemulsion/reverse microemulsion polymers in preparing gel fracturing fluids with sands, an instant emulsion thickening agent BCG-2 has been developed through reverse microemulsion polymerization, with acrylic acid, acrylamide, strong hydrophilic monomers, 2-acrylamido-2-methylpropane sulfonic acid (AMPS), methyl methacrylate, ethylene, sodium salt of vinyl sulfonate etc. as the monomers, and aliphatic alcohol polyethoxylate and cyclohexane compound as the external phase. BCG-2 is soluble in both fresh water and high salinity saltwater. A slick water fracturing fluid and a weak gel fracturing fluid were formulated with a retarded weak crosslinking agent and selected functional agents. In well testing with coiled tubing, the rate of friction reduction of the slick water at a flowrate of 600 L/min was 70.9%, and was increasing with the increase of the flowrate. The weak gel fracturing fluid, after shearing for 120 min at 150℃ and 170 s-1, still had viscosity of at least 80 mPa·s, indicating that the weak gel fracturing fluid is less affected by high shearing rate. The fracturing fluids, after thorough gel breaking, become semitransparent and have no precipitate and almost no residue (< 3 mg/L). The surface tension of the gel-breaking fracturing fluids is 23.87 mN/m. The mixture of the gel-breaking fracturing fluids and a crude oil sample from a well in Yanchang oilfeld can be completely demulsifed in 4 hours. In a feld experiment, a well in Yanchang oilfeld was fractured with an online prepared fracturing fluid of 120℃. The experimental operation has solved many problems encountered in feld fracturing operations in the past, and is of signifcance in promoting fracturing operations toward the direction of simplicity, high effciency and recyclability.
Abstract: Diversion agents commonly used in present acidizing operations are unable to be easily and effectively used in acidizing high temperature offshore sandstone reservoirs. An invert emulsion diverting system has been developed with an active diesel oil and formation water to overcome this defciency. The volumetric ratio of the active diesel oil and formation water is 3:7 in the emulsion which has viscosity of 40 mPa·s even shearing at 170 s-1 under 130℃. Single barrel core test results showed that the permeability of simulated cores of water zones was reduced by more than 80%, and the permeability of simulated cores of oil zones reduced by less than 21.6%. Parallel dual-barrel core test results showed that the rate of diversion of the emulsion to low permeability pay zones was greater than 80%. Diverted acidizing physical simulation experimental results showed that after diverted acidizing with the emulsion, the permeability of low permeability pay zones was increased by about 170%, and the permeability of high permeability water zones reduced by about 60%. This technology has been applied in Nanhai West Oilfeld, the oil production rate was increased by 103.3 m3/d, and the water cut was reduced by 18.8%, indicating that the technology is worth spreading.
Abstract: The main component in fracturing flowback fluids is guar gum, the detection of its effective content and the change of its molecular structure are of importance in subsequent treatment of the flowback fluids. Based on the chemical properties of guar gum, anthrone colorimetry has been selected for use in detecting the concentration of guar gum in fracturing flowback fluids. The linear correlation coeffcient of the standard curve established is 0.999 2, and the percent recovery is between 96.5% and 101.1%. This method has a high repeatability and is accurate and reliable. Using GPC and LC/Q-TOF-MS method, the changing of the molecular weight and molecular structure of the guar gum in the fracturing flowback fluid was identifed. It was found that the standard curve linear correlation coeffcient of using GPC to measure the molecular weight of guar gum was 0.995 5. The relative molecular weight of the guar gum used in Mahu area was about 840,000, and the content of the high molecular weight guar gum in the flowback fluids was decreasing obviously with time. The B-O bond in the molecules of guar gum can be broken preferentially by adding oxidizing gel breaker, and the guar gum is then turned into PEG complex.
Abstract: The fractured tight sandstone gas reservoir in Block Keshen, Tarim Basin, is deeply buried, and has those features such as low porosity and permeability, developed fractures and strong heterogeneity. The reservoir, if not stimulated by fracturing operation, is of no commercial value. Contact of the reservoir with work fluids during drilling/completion operations and stimulation process results in reduction in formation permeability because of the invasion of the solid particles in the fluids into the formation, thereby causing decrease in the productivity of the reservoir. In laboratory experiments, reservoir cores with artifcial fractures were used to evaluate reservoir damage caused by drilling/fracturing fluids, and the width of the fractures was determined by imaging logging data of the reservoir. Experimental results showed that when the confning pressure was less than 4.5 MPa, the permeability of the cores with artifcial fractures, which has cubic relation with fracture width, remained constant. As the width of the fractures increased, the permeability damage caused by fracturing fluid decreased. However, permeability damage caused by drilling fluid frst increased and then decreased when the fracture width was increasing, showing a peak value of permeability damage. Furthermore, acid can be used to remarkably increase the permeability of the fractures, thereby removing damage caused by drilling/fracturing fluids. This study is useful in guiding the development of new low damaging work fluids and the optimization of reservoir protection measures.
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