Abstract: In drilling operation, damage of drilling fluids to reservoir formations with low or ultra-low permeability is higher than the damage of the drilling fluids to reservoir formations with medium or high permeability. Some reservoir specialists have long thought that low- or ultra-low permeability reservoirs that need to be fractured before being put into production do not need reservoir protection measures during drilling operation because fracturing job can eliminate the negative effect of drilling fluids to the reservoir formations. This opinion has badly affected the productivity of oil and gas wells. This paper explains the particularity of the damage mechanisms of low- and ultra-low permeability reservoirs and the severity of the damage. It proves that, using the field production data, excellent reservoir protection drilling fluid technology is helpful to the great enhancement of the daily production rate of a well after being fractured. This paper also elaborates the development direction and trend of reservoir protection based on the international trend and the strategic requirements of the development of China's oil and gas industry. The ideas described in this paper are of not only applicable value to the enhancement of reservoir protection efficiency, the daily production rate of a single well and the overall economic benefit of a whole oilfield, they also have certain guiding significance to the development of drilling fluid technology and the establishment of Chinese-style “shale-gas revolution”.
Abstract: To eliminate the problems encountered in mud loss control with regular inert particle lost circulation materials (LCM) and water-absorbing gel particles, a shape memory epoxy compound foam was developed with shape memory epoxy as the base material and hollow glass beads added into the epoxy to improve its compressibility. With the epoxy compound foam, an expandable smart temperature-sensitive LCM, SMP-LCM was developed. SMP-LCM can be made to have different response temperatures and expanding ratios. By controlling the concentration of crosslinking agent in the shape memory epoxy, shape memory epoxies of different response temperature ranges between 50 ℃ and 100 ℃ were obtained. By controlling the number of pores in the epoxy, shape memory epoxy foams of different expansion rates (5% - 110%) and the foam particles can be obtained. Laboratory experimental results showed that at the effect of temperature, SMP-LCM can expand very fast, and the expansion rate is not affected by the type medium in which the LCM is dispersed. This makes SMP-LCM very suitable for plugging sand discs and sand beds with big pores and rendering them high pressure bearing capacity. SMP-LCM is a temperature-sensitive expandable LCM, able to enter into the very depth of loss zones with small volume and expand at the effect of the temperature therein. In the loss zones, SMP-LCM, because of its shape memory effect, can produce a restoring stress with which the formation can be strengthened while not be fractured, thereby enhancing the pressure bearing capacity of the weak formations. With these characteristics, SMP-LCM has shown a perfect application prospect.
Abstract: Although modified natural polymers such as celluloses have found wide application in drilling fluids, celluloses modified with conventional methods have only limited room for further improvement of their temperature resistance, hence, modified celluloses presently in use can only be used at temperatures below 150 ℃. Borrowing from nano cellulose's excellent characteristics, such as small size, large specific surface area, strong rigidity and high surface activity, a nano cellulose crystalline was developed by hydrolysis of refined cotton with sulfuric acid, and the nano cellulose was in turn made into a nano cellulose filter loss reducer CNCFL-1 through surface functional modification with chloroacetic acid. CNCFL-1 was characterized with degree of substitution measurement, IR spectroscopy and transmission electron microscopy. The comprehensive performance of CNCFL-1 was evaluated measuring its particle size, Zeta potential, rheology, temperature resistance, filtration control capacity and environmental friendliness. The working mechanism of CNCFL-1 was investigated. It was found that the molecules of CNCFL-1 are rich in polar groups such as hydroxyl, carboxyl and sulfonic acid groups, and have degree of substitution of 1.25. The Zeta potential of CNCFL-1 is greater than 30 mV at pH range of 3-13, thus having good dispersion stability. The particle sizes of CNCFL-1 are 50-80 nm. The EC50 value of CNCFL-1 is 31,600 mg/L, and is nontoxic and environmentally friendly. CNCFL-1 performs excellently in controlling high temperature filtration rate through adsorption, viscosifying and tight plugging with its nano sizes. At a concentration of only 1%, the filtration rate of a 4% brine mud can be reduced by 66.92% after hot rolling the mud for 16 h at 160 ℃. Apparently the performance of CNCFL-1 is better than that of PAC-LV and CMC-LV.
Abstract: Solids in a drilling fluid greatly affect its properties and are generally kept to an appropriate level by chemical flocculation and solids control equipment, A high performance environmentally friendly drilling flocculant, which is a cationic gelatin, has recently been developed for solids removal from drilling fluids. In laboratory experiment, HNMR and electric potential measurement were used to chemically characterize the gelatin samples synthesized; turbidity experiment, particle size analyzation and electric potential measurement were used to evaluate and analyze the working mechanisms of the final product of the cationic gelatin. It was found that the cationic gelatin has good flocculation effect on kaolinite particles; 20 mg/L of cationic gelatin in a kaolinite suspension decreased its percent residual turbidity to 4.0%. The cationic gelatin is able to effectively encapsulate and bridge clay particles, remarkably increasing the sizes of kaolinite particles. The cationic gelatin is also able to remarkably increase the sizes of solid particles in a drilling fluid, and can reduce the solids content of the drilling fluid from 22.5% to 12.6% when used in conjunction with solids control equipment. The flocculating performance of the cationic gelatin developed is better than the commonly used flocculants such as hydrolyzed polyacrylamide.
Abstract: The well Jitan-1 is a key exploratory well drilled by PetroChina Company Limited in the upper part of the Nanyishan structure in the northwest area of the Qaidam Basin (Qinghai Oilfield). The well, targeted to the E31, E1+2 and the bedrock zones, was designed to drill to 6500 m, and was actually drilled to the total depth of 6194.22 m. The well was drilled to ascertain the petroleum production potential of the E31 and bedrock zones and hence to provide the basis for further research and exploration of the Nanyishan structure in which the formations beneath the E1+2 zone had never been drilled before. These formations are complex and are located in a high and steep structure. Three fault zones, some broken belts and mudstone with gypsum have to be penetrated during drilling. The E31, E32 and the E1+2 zones are developed with plenty of fractures, which may result in lost circulation. Several high-pressure saltwater zones with CO2 exist with chloride content up to 23,500 mg/L, and CO2 content up to 75% (measures on the surface). The high-pressure saltwater and CO2 zones may result in well kick or even well blowout. Multiple zones of hard, fractured and brittle carbonaceous mudstone formations are a potential of borehole collapse and well deviation. To maintain the well in stable conditions, a mud weight of 2.32 g/cm3 was required. Abnormal high formation temperatures were encountered. The formation temperatures are too high for the logging instrument to measure, and thus the bottomhole temperature cannot be obtained. The formation temperature gradient in this area was (3.80-4.30) ℃/100 m, and the temperature of the mud at the exit of the flowline was 102 ℃. Volume of mud for dilution was at least 10 times of the hole volume. From these data and the stability cycle of the mud in circulation it was predicted that the bottom hole temperature was between 235 ℃and 266 ℃. These potential downhole troubles imposed serious challenges to the drilling fluid operation. To solve the problems such as ultra-high bottom hole temperature, high density, borehole wall instability, acid gas contamination and narrow safe drilling window, a high-density compound organic salts drilling fluid, which was a proprietary technology of the Bohai Drilling and Exploration Drilling Fluid Technical Service Company, was adopted to drill the well. This drilling fluid can be used at high temperatures up to 240 ℃ The drilling fluid was further optimized based on the geologic data and proposed drilling program; a filtration control agent functioning at 240 ℃ was used to control filter loss of the mud, a lost circulation material composed of rigid and plastic particles was used to minimized mud losses while drilling, a nano material was used to maintain borehole wall stability through chemical mechanisms, and a good “non-oxygen reduction” mud environment was maintained. By maintaining good mud rheology and low filtration rate (≤ 12 mL), potential downhole troubles such as high temperature rheology instability, settling of weight materials, mud losses, borehole wall collapse in drilling the fractured zones and contamination of the mud by acid gases, were all well solved.
Abstract: Optimization of drilling fluid rheology plays an important role in the safe, high quality and efficient drilling. Presently there is no systematic, scientific and quantified optimization theory and method available for drilling fluid rheology optimization. This paper presents an optimization and design principle, that is, the rheology of the drilling fluid should not only be suitable for operation on the formations to be drilled, it should also help maintain the annular space in good state. Different rheological models were presented for different drilling fluid formulations. A theory and a method which stated that optimization of drilling fluid rheology should be based on the formation to be drilled and the state of the annular spaces were established based on the characterization of the state of annular space with three parameters, which are, index of borehole wall erosion, rate of cuttings transportation in annular space and dynamic annular pressure coefficient. The study has provided a new theory and new technology for quantified optimization of drilling fluid rheology and field optimization of drilling fluids.
Abstract: The geological structure of the Zhunbei block is complex and volatile. Coexistence of several fractured zones and fracture development in this block have frequently resulted in severe borehole wall instability. A low activity high calcium content polyamine drilling fluid was developed to deal with these problems. The drilling fluid has calcium content of 3.0% at most the activity of the drilling fluid can be adjusted to less than 0.95, and the membrane efficiency of the drilling fluid can be maintained above 0.2; all these properties are beneficial to borehole wall stabilization. Application of this drilling fluid on the well Zhunbei101 showed that, between well depth of 2000 m and 4200 m, the activity of the drilling fluid was kept at below 0.95, the Ca2+ concentration was maintained at above 6000 mg/L. No mud loss and borehole wall collapse happened throughout the whole drilling operation. The average rate of hole enlargement of the second interval was 6.96%, and that of the third interval was 0.59%. The drilled cutting content of the drilling fluid was reduced by optimizing the solids control equipment. The lubricity of the drilling fluid was improved using drilling lubricant. The use of the drilling fluid has provided a reliable guarantee to the efficient development of the reservoirs in the north of Junggar Basin.
Abstract: In deep well drilling, ultra-high temperature, high salinity and high density impose rigorous requirements on the performance of drilling lubricants. A lubricant SDR-1, made from an environmentally friendly modified base oil, an extreme pressure filming agent, a compound surfactant and a compound anti-oxidant, has recently been developed for use in high density high salinity drilling fluids at high temperatures. Evaluation of SDR-1 showed that SDR-1 is able to work effectively at 200 ℃. A saturated salt mud and a saturated salt mud containing 6000 mg/L, when treated with SDR-1, had friction coefficient reduced by 80%. SDR-1 has good sedimentation stability and fluorescence of level 3 or lower. SDR-1 is well compatible with high density drilling fluids, and is able to effectively reduce the flow pressure loss and dynamic friction.
Abstract: The well Wh-1X has experienced whole mud losses into induced fractures formed when killing the well at 6828 m (φ215.9 mm, open hole length was 1178 m) and mud losses into caves at 7114.65 m in a sidetracked section (open hole length was 1464.65 m). The mud losses at the bottoms of the hole had to be stopped. It was believed that, to minimize the risk of pipe sticking caused by fracturing the upper weak formations when controlling mud losses into interbedded sandstone and mudstone at the bottom of the well with bridging method, the whole open hole section should be strengthened to bear pressures that may fracture the open hole. First, the drill string was run inside the technical casing to improve the pressure-bearing capacity of the weak formations above the hole bottom with bridging. Second, run the drill string into the open hole and control mud losses taking place at the bottom of the hole. By rotating the control head during mud loss control, the risk of pipe sticking was minimized. It was further believed that, failure in previous mud loss control was because of the serious defects in sizing and concentration of the bridging materials used. To succeed in controlling mud losses into fractures and caves with bridging method, three prerequisites should be satisfied: Large size and high concentration of firstclass size bridging agents, gradient matching and reasonable concentration of various sub-size bridging agents, high total concentration of the bridging agents. Unobstructed wellbore is important for the bridging slurry to reach the depth at which mud losses are taking place. Using the technology and principle aforementioned, three mud loss zones, 5650-5668 m, 5830-5842 m and 6279-6288 m in the sidetracked hole, were bridged successfully by running the drill string inside the casing twice, and two cave loss zones, at 6644-6649 m and 7114.54-7114.65 m respectively, were bridged successfully by running the drill string once into the open hole. The five loss zones were all at the bottom of the well when mud losses were taking place. Success in mud loss control helped drill the well successfully.
Abstract: The well Wenchu-6 is a pilot test well for the XX gas storage in Tuha oilfield. This well penetrated in its 3rd interval (reservoir section) the Xishanyao Formation, an ultra-low pressure depleted formation with formation pressure coefficient of only 0.25-0.27. This low formation pressure plus fractures generated in the sandstones by fracturing job in wells nearby easily led to lost return of drilling fluids during drilling. To ensure the success of coring in the reservoir section and well cementing, a mud loss control technique based on ideal packing was adopted involving the optimization of bridging particle size distribution and the use of several special lost circulation additives such as delayed hydration and swelling particles, elastic graphite particles and high-efficiency rigid bridging particles. Several times of mud losses during coring and well cementing in the 3rd interval have been cured with this technique. Four whole drums of cores with length of 32.2 m were taken in the sections of mud losses. Before cementing the 3rd interval, the well was treated with drilling fluid containing the lost circulation additives as said above. The lost circulation additives were then screened out of the mud and the borehole formation was tested for its pressure bearing capacity; it was 5.8 MPa (maximum). No losses were ever encountered during well cementing with cement slurries of normal densities. The successful practice of the lost circulation control technique based on ideal packing theory provides a new clue for lost circulation control in similar sandstones of ultra-low pressures and a technical support for efficient development of the gas storage in subsequent operations.
Abstract: Mud losses were frequently encountered in Mahu block. By carefully study the volume of mud losses, formation porosity, development of formation fractures and leaking pressure profile in this area, the characteristics and mechanisms of mud losses were analyzed. Lost circulation prevention and control slurries for the specific formations were evaluated and optimized, and lost circulation materials were selected using morphology analysis and particle size matching method. It was found in study that the second and the third intervals of the wells drilled in the Mahu block have higher volume of mud losses and high frequency of downhole troubles. The Badaowan formation, Baijiantan formation, Klamay formation and Wuerhe formation penetrated by these two intervals are full of pores and fractures and have low pressure bearing capacity, making them vulnerable to mud losses. Using the lost circulation materials available at the rig site, a new mud loss prevention slurry SDSZ and a mud loss control slurry SDDL were formulated with sized millimeter and micron particles by matching the shape of the particles and the morphology of the loss zones. The mud loss prevention slurry SDSZ was tested on a sand-bed and the depth of filtration of the SDSZ was 50% lower than that of the lost circulation control slurry previously used. The mud loss control slurry SDDL can strengthen the loss zones by increasing their pressure bearing capacity to above 7 MPa. Percent acid solubility of SDDL was at least 60%. In field application, 75% potential mud losses were prevented from occurring, and the success rate of controlling mud losses on the first try was 80%. The mud loss prevention and control slurries developed, as the study has shown, are able to effectively solve the mud loss problem occurred in Mahu block.
Abstract: To avoid formation damage to the high temperature deep buried hill gas reservoir in Bozhong 19-6 block, a high temperature water base drilling fluid with good overall performance was developed based on rock core analysis, permeability sensitivity experiment and analysis on the mechanisms of reservoir damage. Laboratory experimental results showed that the matrix of the gas reservoir in Bozhong 19-6 block has low porosity and low permeability. The reservoir rocks have low content of clay and are full of fractures. Laboratory experiments also showed that the reservoir rocks have strong flow rate sensitivity, medium to low stress sensitivity, and weak water, salt and alkali sensitivity. No acid sensitivity was found during laboratory experiment. The reservoir rocks are easily damaged by solids invasion because of the micro fractures developed therein. Loose cementation of particles in the micro fractures results in flow rate sensitivity and water block of the reservoir rocks. Cores flooded with the drilling fluid developed had percent permeability recovery of 85.95% and percent water block damage of 13.21%, indicating that the drilling fluid had excellent reservoir protection capacity. After being aged at 210 ℃ or contaminated with 10% NaCl, 1% CaCl2 or 8% poor quality clay, the drilling fluid still functioned properly, satisfying the requirements of gas reservoir drilling and reservoir protection in the Bozhong 19-6 block.
Abstract: Formations in the Zhunzhong (the middle of Junggar Basin) area has complex geological structure; the same hole section penetrates formations with several different pressure systems and the middle and the lower formations are developed with hard and brittle mudstones. The Xishanyao Formation and the Badaowan Formation have joint coal beds and are full of micro fissures which frequently caused sloughing, borehole wall collapse and pipe sticking to happen. Another drilling difficulty is the deep buried reservoirs. Principles of stabilizing the borehole wall and enhancing the rate of penetration were presented based on the analyses the affecting factors and mechanisms of borehole wall instability. A set of water base drilling fluid technology was developed for drilling in the Zhunzhong area safely and efficiently. This technology has been applied on 6 wells in Zhunzhong-1 block and Zhunzhong-4 block, NPT was reduced by 86.74%. Compared with wells previously drilled in the two blocks, the average ROPs were increased by 46.03% and 25.39%, respectively, and the percent hole enlargement was reduced by 69.07% and 45.18% respectively. Using this technology, the goals of stabilizing borehole wall and enhancing ROP have been achieved.
Abstract: A tight gas reservoir generally has low porosity, low permeability, high water saturation, high stress sensitivity and high clay content, the gas permeability of the tight gas reservoir is generally less than 0.001 mD. Gas reservoir damage is thus different from oil reservoir damage because of these characteristics. Presently there is no commonly agreed method for evaluating tight (included fractured) gas reservoir damage worldwide. In the common reservoir sensitivity evaluation method a liquid is used as displacing medium. This method is time consuming and is subject to great experimental errors and stress sensitivity. To overcome these shortages, a new evaluation method was developed based on the study of tight (including fractured) gas reservoir damage, and a set of procedure developed to evaluate the damage to tight (porous and fractured) gas reservoirs. Using this new method, reservoir cores from the block BZ19-25 was evaluated, giving results that were consistent to those obtained with standard industrial methods. This proves that the new method is reliable and is suitable for evaluating damage to porous and fractured gas reservoirs.
Abstract: The well Zhanghai 39-39Z is a real level-4 multilateral well drilled in Dagang Oilfield. A drilling fluid program for the three intervals of the main bore was designed based on several factors such as: the lithology of the formation to be drilled, the hole profile, drilling techniques adopted, the complexity of the multilateral well drilling, reservoir protection, environment protection, and drilling fluid application and performance in offset wells etc. The first interval of the main bore was drilled with bentonite-polymer drilling fluid. The second interval was drilled with polymer drilling fluid in the Minghuazhen formation and organosilicon inhibitive drilling fluid in the Guantao formation. The third interval and the laterals were drilled with organic salt drilling fluid. These drilling fluids satisfied the needs of drilling and other jobs, and had stable properties during drilling. Good mud rheology helped borehole cleaning. Organic salt and bentonite at reasonable concentrations in the mud ensured inhibitive capacity and stability of the drilling fluids. Borehole wall stability was obtained using reasonable mud weights. Drilling fluid operation on the well Zhanghai 39-39Z has provided a good technical clue to the drilling of other similar multilateral wells with regular drilling fluid formulations.
Abstract: Cement as the main component of well cementing material, has the disadvantages of high brittleness and poor corrosion resistance. Oil and gas wells cemented with cement slurry are susceptible to brittle failure which in turn results in pressurizing in annulus and channeling across layers. Curable resin based cementing materials have many advantages over cement, such as high strength, low elastic modulus and strong elasticity, hence can be used in well cementing. Several curable resins have been analyzed and epoxy resin was finally chosen as the cementing material. A curing agent was also selected for use with epoxy resin. In evaluating the thickening process of the resin based cementing material, a viscosity-time curve was used to replace the old thickening curve. Laboratory experiments were conducted to optimize the curing fluid. It was found that HSPT, a curing agent, remained in working status for a longer time than other curing agents. The reaction product of HSPT had compressive strength of greater than 70 MPa, elastic modulus of less than 3 GPa, and low gas permeability, suitable for well cementing at 50 - 90 ℃. The reaction product of another polyetheramine curing agent had compressive strength of greater than 75 MPa and elastic modulus of less than 2 GPa, which is suitable for well cementing at 30 - 50 ℃.
Abstract: Gas injection and gas production from a gas storage well and pressure accumulation and unloading of the annular space of the well result in repeated loading and unloading of the wellbore, leading to the failure of the cement sheath, or even gas invasion from formation into the well. To study the failure mechanisms of the cement sheath of a gas injector (also acted as a gas producer), a laboratory experiment was conducted in which the cement sheath was subjected to the action of internal circulation pressure of 8.1 MPa and 13.6 MPa, according to the work conditions of the cement sheath in the upper part of the annular space B of a gas storage. The cement sheath was studied for the change of micro fractures and pores in it by analyzing its sealing property and permeability as well as SEM and CT analyses. In the experiment, there was no gas channeling through the cement sheath after 30 times of circulation at 8.1 MPa; when the circulation pressure was increased to 13.6 MPa, 23 times of gas channeling were found in 30 times of circulation. This experimental result is in accordance with the situation of shallow gas channeling into the annular space B. Cyclic loading may result in micro fractures in the cement sheath, and with the increase in the amplitude of the cyclic load, the permeability of the sheath sample increased at a small amplitude. The more the number of the micro fractures in the cement sheath, the wider and longer the micro fractures extended, and some micro fractures even ran through the whole sheath. Micro-annulus path around the cement sheath were resulted from the accumulation of failures of the micro structure of the cement sheath. For a well with high quality cementing job, the failure of the microstructure of the cement sheath is essentially the cause of gas channeling. Microstructure failure in a cement sheath and micro-annulus path around the cement sheath both can directly result in gas channeling, though the dominant cause of the gas channeling is affected by many factors. The experimental results have revealed the mechanisms of failure of the cement sheath under cyclic loading in a gas injection and producing well and the relevance between the cyclic loading and gas channeling, and are of instructive significance on the optimization of gas storage operation and quality control of the wellbore of a new gas storage.
Abstract: In cementing ultra-deep gas wells with high temperature, high pressure and high sulfide content in marine Sichuan basin, settling of cement slurry at high temperatures, gas channeling and decline of the strength of set cement were the main technical problems that need to be addressed. In the development of a latex cement slurry with high elasticity, high toughness, low permeability and anti-channeling performance, different methods were used to optimize the cementing additives. The stabilizing agent was selected by settling stability evaluation performed on an HTHP thickening instrument and by particle sizing principles. By directly measuring the gas channeling permeability and the permeability of the set cement under plastic conditions, the gas channeling agent was selected. The high temperature retarder was selected using Ubbelohde viscometer which evaluates the thermal stability of polymers. The particle size and concentration of a quartz sand as high temperature stabilizer were optimized by analyzing the compressive strength of the set cement cured at 180 ℃ through orthogonal test method and thermogravimetry. It was found in these experiments that: 1) at temperatures between 150 ℃ and 180 ℃, the cement slurries of 1.90 g/cm3-2.30 g/cm3 all had good engineering performance, laying the foundation of solving the well cementing difficulties as mentioned above. 2) Adding sand into the cement slurry can mitigate strength decline of the set cement. At elevated temperatures, sand concentration has a positive relationship with compressive strength of the set cement. At the same sand concentration, sand of finer particle sizes is better than sand of coarse particles, but from the long run, addition of coarse sand is more beneficial to the strength development of the set cement. It was thus suggested that at temperatures between 150 ℃ and 180 ℃, the silica sand concentration should be greater than 35% and 45%, respectively. 3) Ubbelohde viscometer can be used to evaluate the high temperature resistance of filter loss reducer and retarder, and is therefore an important auxiliary means to fast screening of key additives for high temperature wells. 4) Further evaluation on the corrosion by acidic gases such as H2S, to set cement should be carried out, and this will be beneficial to the design of cement slurries with anti-gas-channeling and corrosion resistance capacities.
Abstract: Well Dabei-X is an exploratory well drilled in the Keshen block, an area located in the Kelasu structure, Kuche depression, Tarim Basin. The fifth interval of the well, which was to be cased with φ177.8 mm+φ182 mm liner strings, penetrated creeping pure rock salt and had coexistence of high- and low-pressure zones. Long open hole, narrow annulus, deep running of liner strings and narrow safe drilling window (only 0.03 g/cm3) were very likely to result in downhole troubles such as coexistence of blowout and mud losses in different depths or alternate occurrence of mud losses and well kicks. To avoid and solve these potential downhole problems, precise control of wellhead pressure was tried during cementing job. By precisely controlling pressure at the wellhead, the occurrence of well kick and well leaking can be avoided. During cementing, the wellhead pressure was precisely controlled in normal injection of cement slurry, and the cement slurry was further reversely squeezed into the annular space. Measures related to the safety of well cementing, such as anti-channeling, prevention of well kick and well leaking, were all put in practice to ensure the success of the cementing job. CBL/VDL logs proved that the bonding in the overlapping section and the open hole section was qualified. Quality of the cementing of the 200 m above the upper casing shoe was excellent. Low density drilling fluid can be safely used in the next interval because of the successful cementing job of the fifth interval. Techniques used in the cementing operation have provided experiences for cementing wells with narrow drilling windows and wells in the Keshen block with similar downhole problems.
Abstract: This paper focuses on the Temperature-tolerance and Shear-resistance mechanism of a physical gel fracturing fluid, which is mainly divided into the following three aspects: (1)The microstructure of the solution is analyzed using a transmission electron microscope, and shear degradation phenomenon of the linear polymer (HPAM) and thickener (SMPT) is explained. (2)The influence factors of Temperature-tolerance and Shear-resistance of HPAM and SMPT are compared and analyzed through testing the viscoelastic modulus of samples before and after the Temperature-tolerance and Shear-resistance test. (3)The Factors of Temperature-tolerance and Shear-resistance Degradation of the physical gel was analyzed by the viscoelastic modulus and micromorphology of the samples before and after the Temperature-tolerance and Shear-resistance test of 0.6% HPAM + 0.5% PHCA and 0.6% SMPT + 0.5% PHCA. The result shows that sample of 0.6% HPAM + 0.5% PHCA undergoes shear degradation and transforms into a viscous fluid after the Temperature-tolerance and Shear-resistance test under the condition of 120 ℃, 170s-1 for 2 hours. Extraordinarily, the elastic factor retention rate of the physical gel (0.8% SMPT+0.5%PHCA) is 78.9% , indicating that the physical gel fracturing fluid can maintain strong elastic fluid characteristics undergo the Temperature-tolerance and shear-resistance test at 150℃. Activation energy data of Arrhenius equation η= A e(－ Ea/RT) shows that PHCA can lower the activation energy and constraining the degradation of SMPT, which indicates that PHCA is able to enhance the structural stability of SMPT solution.
Abstract: Hydraulic fracturing is the core technology for the more and more prevailing development of unconventional hydrocarbon such as shale gas. Multistage fracturing has always been used in the development of unconventional hydrocarbon reservoirs. Study on the flowrate distribution in each level of fractures during fracturing has seldom conducted, although the understanding of the flowrate distribution is very important to the understanding of fractures and to the design of fracturing program. An apparatus for experimenting effective sand transport in multistage fractures was developed to study the flowrate distribution in multistage fractures. Using this apparatus, several factors, such as viscosity of fracturing fluid, particle size of proppant, injection rate, sand concentration etc., were studied for their effects om the flowrate distribution of fracturing fluid in multistage fractures. It was found in the study that flow rate was decreasing along the fractures in different descending stages. 64.63% of the flow rate is in the master facture, 22.14% in the first level fractures, and the rest in the second level fractures. The distribution of flowrate in different levels of fractures is also affected by the total flowrate; the higher the total flowrate, the higher the flowrate distributed in the master fracture and the lower the flowrate in the sub-fractures. Other factors, according to their level of importance, are the particle size of proppant, viscosity of fracturing fluid and sand concentration. The study gives birth to a method of evaluating the pattern of flowrate distribution in multistage fractures and reveals the pattern of flow rate distribution in each level of fracture, providing a basis on which the properties of fractures can be understood and fracturing program can be optimized.
Abstract: Acid fracturing flowback fluids produced in Bohai oilfield, after simple treatment, were reinjected into the formation. The fracturing flowback fluids always caused the injectors to be blocked because of the existence of solid suspended matter in the fracturing flowback fluids. Laboratory experiments were conducted for the suspended solid matter on three fracturing flowback fluid samples taken from oil wells in Bohai oilfield. The effect of pH on the content of suspended solid matter in the acid fracturing flowback fluids was analyzed by changing the pH value of the fracturing fluids. The experimental results showed that the content of the suspended solid matter in fracturing flowback fluids from different wells and the content of suspended solid matter in the fracturing flowback fluid from a single well in different time of flowback are quite different. pH value plays an important role in the content of the suspended solid matter. Large amount of Fe(OH)3 precipitate is produced in acid fracturing fluid neutralized with bases. Dynamic displacing test through sandpack tube showed that de-oiled acid fracturing flowback fluid with pH 1 – 2 does not cause obvious block in the sandpack tube. It is thus understood that in field operation, the acid fracturing flowback fluid should not be neutralized with bases. If HCl is used to reduce the pH value of the fracturing flowback fluid, the content of the suspended solid matter in the fracturing fluid can be effectively decreased, hence reducing the risk of near-wellbore blocking in injectors.
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