Abstract: As the petroleum exploration and development are proceeding and extending to deeper, complex formations, nonconventional reservoirs and offshore exploration and development, the well cementing is becoming more and more difficult. More and more rigorous requirements are imposed on the long time airtightness of cement sheath, and the development of new cementing fluids is facing new challenges. This paper discusses the progress made in recent years about the functional cementing fluids, such as cement slurries for long intervals with large temperatures differences, cementing slurries with good toughness, corrosion inhibitive cement slurries, cement slurries for heavy oil thermal recovery wells, self-healing cement slurries, cement slurries for wells in deep water area, and the functional pre pad fluids. Based on the challenges encountered in cementing wells with complex problems, the studies to be performed on new cementing materials and functional cementing fluids in the future are presented in the paper.
Abstract: Slick water fracturing fluids and linear colloid fracturing fluids, though widely used in shale gas stimulation jobs, have deficiencies such as poor sand carrying capacity, difficulties in the treatment of the flowback fluids, and damage to the productivity of reservoirs, etc. Based on the analyses of the problems found of the fracturing fluids presently in use, it is concluded that after understanding the mechanism of the damage of shales by softening, the field operation and laboratory study data should be reviewed, and those wells with failed fracturing jobs can be re-fractured. By summarizing the newly developed fracturing fluids, it is understood that formulation of fracturing fluids with produced water is prospective in the future for energy saving and waste disposal. Foam fracturing fluid is a kind of fracturing fluids that can be formulated with less amount of water. Ultra-low concentration polymer fracturing fluid, hydrophobic association polymer fracturing fluid and star polymer fracturing fluid will be widely used in the future. A water saving SRV fracturing program for shale gas stimulation is presented based on data survey, and it is suggested that the flowback fluids be purified and treated in accordance with the type and application of the fracturing fluid formulated with the liquid from the used fracturing fluids, thus reducing the treatment cost of the flowback fluids.
Abstract: The target zone of the block B in Tarim Basin is the Cretaceous Bashijiqike Formation. The depth of the wells drilled is greater than 6,000 m, and the reservoir rocks are tight, with porosity ranging from 1.0%to 9.4%, and permeability from 0.011×10-3 to 8.56×10-3μm2. The porosity has poor relationship with permeability. The highly heterogeneous reservoir rocks have poorly developed pores, low permeability, developed fractures, high capillary forces, high clay contents, and are very easy to be affected by water blocking during well completion and fracturing. Analyses of water blocking based on the geological features of the reservoir rocks in this area indicate that the capillary water accounts for almost half of the volume of the pores, leading to highly difficult gas flow in the porous media. Using the Model SRT-II low permeability sensitivity tester, formation damage by water blocking is macroscopically analyzed through core flow experiment. Using NMR transverse relaxation time spectrum, formation damage by water blocking is microscopically analyzed. The analyses show that water blocking caused the permeability of the reservoir rocks to be reduced by 99%, and more than 90%of the water blocked in this area, mainly in the 0.01-250 nm pores. Based on the research, water blocking remover SATR0-1 and HUL were chosen and their performance studied through capillary imbibition, NMR examination, and permeability experiments. It was concluded that SATR0-1 and HUL can effectively reduce capillary forces and invasion depths by imbibition, and are helpful to liquid flowback through micro pore throats.
Abstract: The #15 coal seam buried shallow in the Sihe coal mine in the south of Qinshui Basin has high content of coal bed methane (CBM) and is thus prospective in CBM mining. The #15 coal seam has a complex structure and its top and bottom are both limestone rich in water. In-seam drilling in the #15 coal seam has been encountering problems such as difficulty in cuttings carrying, borehole wall collapse, lost circulation and drilling fluid contamination to the coal seam. A degradable polymer drilling fluid has been developed to deal with these problems. The polymer drilling fluid was evaluated in laboratory through suspension of coal fines, simulation of borehole wall stabilizing with coring, viscosity attenuation and test on permeability return. The results have proved that the polymer drilling fluid has good cuttings carrying capacity and strong inhibitive capacity, mitigating borehole washout. Using bio-enzyme, formation permeability impairment of the target zones by drilling fluid can be reduced from 50%to 25%. This polymer drilling fluid has been tried in the platform X-2, the first industrial CBM drilling platform, with its properties as these: density 1.01-1.03 g/cm3, FV 35-40 sec, API Fl less than 15 mL, and pH 8-10. Addition of bio-enzyme reduced the viscosity of the drilling fluid by 40%. 900 m footage in the coal bed has been successfully drilled with this degradable polymer drilling fluid.
Abstract: The lithology of the Shasan reservoir formations in Luojia, Block Bonan is mainly shales that are thick and widely spread. The shales are rich in organic carbon and oil and gas. Borehole instability has been encountered during horizontal drilling because of the developed fractures in those formations, the anisotropy of the formations, and the hydration of the formation rocks. Conventional models prognosing the collapse pressure of the formations cannot be used to calculate the collapse pressure. Those models that only consider the weak planes have no thought for the effect of intermediate principal stress on the strengths of rocks, and the prognoses are generally not done satisfactorily. Mineral composition and fracture distribution have been examined about the shale samples taken from Luojia, and based on the weak plane strength theory, a more accurate prognosis model, which takes into account the effects of triaxial stress, has been established for the prediction of collapse pressure. The application of the model shows that for wells penetrated the shale formations, borehole stability cannot be realized through only higher mud weight. Carbonate formations with higher original strengths and low porosity are not uncommon in this area. If managed pressure drilling (MPD) is used with bottom hole pressure slightly lower than formation pressure, the strength of the rocks can be increased, and hence the stability of the borehole wall. This, in turn, will help reduce drilling cost and increase ROP.
Abstract: Tight sandstone gas reservoirs have special characteristics that make them quite prone to damage, which is very difficult to remove, during drilling. The dry gas reservoir in the Block Linxing, for example, is such kind of reservoirs, with low porosity, low permeability, low abundance, and no sulfur. To protect the reservoir from being damaged, two plugging agents, Micro-ball and CARB, have been used in the drill-in fluids to reduce the API filter loss to less than 5 mL. The Micro-ball is a high molecular weight polymer nano material able to penetrate into the pores in the reservoir formations to form interior mud cakes with ultra-low permeability, thereby to temporarily plug the micro pores. CARB is an acid-soluble inert spherical material with wide range of particle size distribution. CARB has particle sizes greater than the sizes of the pore throats in the reservoir formations, and are thus able to mud cakes on the surface of the formations. CARB has good plugging capacity and forms mud cakes that are easy to remove. The horizontal well LXxx5- 1H, completed with open-hole fracturing, was drilled with this drill-in fluid, which had good inhibitive capacity (shale cuttings percent recovery in hot rolling test is greater than 93%) and good plugging capacity. The improved lubricity of the drill-in fluid helped solve the problems of being unable to exert WOB during horizontal drilling, and balling of BHA. The drill-in fluid is resistant to contamination, has stable property which is easy to maintain, and good flow pattern. The drilling operation has been successful, and the gas production rate obtained after fracturing job is highly satisfactory.
Abstract: The reservoir formations in the Block Barua, west Venezuela, are characteristic of multiple interbedded mudstones and sandstones, unconsolidated sandstones because of poor cementation, borehole wall collapse and frequent mud losses, high temperatures and poor reservoir physical properties. A drilling fluid named BH-ELASTICO-HTHP has been developed based on the "fluid casing concept" to try to maintain borehole stability during drilling and to minimize skin contamination of the reservoir formations. The BHELASTICO- HTHP drilling fluid has high viscosity and low gel strengths, and can be used to stabilize borehole wall and reduce skin factors when treated with dolomitic CaCO3 as a temporary plugging agent. The low-shear-rate viscosity of the BH-ELASTICO-HTHP drilling fluid helps clean the borehole. As a high temperature drilling fluid formulation, with its main additives easy to degrade, this drilling fluid is suitable for use in drilling formations with low pore pressure, low permeability, and unconsolidated formations. The application of this drilling fluid in the well MGB-0066 demonstrates that the BH-ELASTICO-HTHP drilling fluid has strong mud loss controlling capacity and shale inhibitive capacity; it helps protect reservoir formations from being damaged and is environmentally friendly. The well MGB-0066 has actual oil production rate 30%more than that of the offset well. The use of the BH-ELASTICOHTHP drilling fluid realized safe drilling and enhanced production. The "fluid casing concept" will help in designing drilling fluid formulations for use in old oilfield or in reservoirs with poor physical properties.
Abstract: Shale drilling is always faced with these problems such as borehole wall instability, high friction and drag and borehole cleaning etc. resulted from shales with developed beddings and fractures, and shale hydration. A hydrophobic nano SiO2 was selected as a plugging agent used to reduce water invasion into the fractures in shales, and hence to inhibit the shales from hydrating and swelling. The effects of different nano SiO2 on brine drilling fluids have been studied through laboratory experiments on regular mud property and SEM analyses. It was found that ① the hydrophobic SiO2 has strong hydrophobicity and adsorbability; the SiO2 powder can form a barrier to water invasion by adsorbing onto mud cakes, thereby effectively reduces the filtration rate. ② the solid hydrophobic SiO2 at 1%- 3%reduces the filter loss by 48.7%, while a hydrophobic SiO2 suspensions reduces the filter loss by 41.67%, but the solid hydrophobic SiO2 tends to agglomerate, thus losing the nano features.③ at 180℃, drilling fluid treated with 25%NaCl and 3%hydrophobic SiO2 suspensions has filter loss of 8.2 mL. At room temperature to 180℃, the water activity of drilling fluids treated with the hydrophobic SiO2 is 0.815 - 0.849, and the percent swelling of shale cores is about 4%, meaning that the SiO2 has strong inhibitive capacity. The coefficient of friction of drilling fluids treated with the hydrophobic SiO2 is 0.11 - 0.12, meaning the SiO2 treated drilling fluids have good lubricity. With all factors such as filter loss, stability and cost efficiency considered, a drilling fluid containing 3%hydrophobic SiO2 suspension and 25%NaCl is the optimum formulation.
Abstract: A modified nano SiO2 with core-shell structure was prepared through sol-gel method, using tetraethoxysilane (TEOS) as the source of Si, ammonia water as catalyst, water as accelerant, and phenylethylamine propyl trimethoxy silane as surface modifier. The molecular structure of the SiO2 was characterized through FT-IR, PSDA and TEM, and the modified SiO2 was compared with nonmodified SiO2 as to the particle size distribution and microscopic morphology in the filtrate of drilling fluid. Several nano SiO2 additives were evaluated by testing their capabilities to plug nano fractures on a simulator, and the mechanism of nano-dispersion of these SiO2 additives in drilling fluids was discussed. Compared to non-modified SiO2, the modified SiO2 shows nano-dispersion in drilling fluids, and can effectively plug the nano-sized fractures. At a concentration of 3.0%, 99.21%of the nano-sized fractures on the simulator were plugged.
Abstract: Methods for evaluating the performance of drilling fluids plugging fractures in hard and brittle formations have been surveyed and four methods were chosen for comparison based on the characteristics of hard and brittle shales. It was found that the HTHP filter loss can be used to characterize the osmotic property of mud cakes. The HTHP sand bed and permeability plugging tester (PPT) methods can be used to evaluate the capability of drilling fluids to plug the fixed fractures or pore throats with sizes in nanometer ranges, but they are not suitable for evaluating the performance of nanometer plugging agents, nor can they be used to evaluate the performance of plugging agents to plug fractures or pore throats that have changed during the interaction between drilling fluid and shales. The pressure transmission experiment, on the other hand, canbe used to evaluate the performance of all kinds of plugging agents to plug the fractures or pore throats in hard and brittle rocks, it is also used to test the performance of these plugging agents in plugging fractures or pore throats with sizes changed by the reaction of drilling fluid with shales.
Abstract: Drilling fluid rheology is an important property of drilling fluid, the measurement of which in automatic drilling needs to be automatic. A new method of online real-time measurement of drilling fluid rheology has been proposed through the analyses of the status-quo and the problems encountered in field operation of rheology measurement. In this paper the principles of the new method are discussed, and a measurement scheme is proposed. The designed measurement apparatus was evaluated in laboratory, demonstrating the feasibility of the new method and the measurement scheme.
Abstract: 11 exploration wells have been completed in the Block Dabasong, the second and the third intervals of which were drilled with polymer sulfonate drilling fluid containing potassium and calcium salts. Tight hole, borehole wall collapse, mud losses,well flow, over-pull and sticking while tripping, and mud contamination etc. have been frequently encountered during drilling. To solve these problems, studies have been done to improve the properties of the polymer sulfonate drilling fluid used. A shale encapsulator and amine based inhibitor were used to improve the inhibitive capacity of the polymer sulfonate drilling fluid. The improved drilling fluid formulation was used to drill the well Datan-1, and was proved successful in solving the problems caused by the easy-to-hydrate-andswell Cretaceous and Jurassic gypsum-containing shales. Borehole instability and mud losses encountered in drilling the Xishanyao formation and the Badaowan formation were solved by the drilling fluid improved in inhibitive capacity and plugging performance, and by using more appropriatemud weight. Using a combination of NaCl and KCl, the percent recovery of shale cuttings was increased from 91.6%to 97.5%, and contamination tolerance of the drilling fluid was increased from 5%to 10%. Using well formulated LCM slurries and near-balanced drilling, possible mud losses can be prevented. Compared with offset wells, the well Dashen-1, which had larger hole sizes, had average ROP increased by 35.48%, and the monthly drilling rate was 1105.86 m per rig, 51.2%higher than that of the well Da-1, 28.1%higher than that of the well Da-9, and 48.12%higher than that of the well Da-10. No drilling problems were experienced during drilling, and the wireline logging and casing running were conducted with no delays.
Abstract: The Dongfang1-1 gas field is the largest offshore gas field in China. Complexity of the formations plus a long time of production, result in depleted formation, and mud losses (at overpressure), well flow and pipe sticking are thus risks that might be encountered in the 311.15 mm interval. Presently the drilling fluid used in the Dongfang1-1 gas field is Plus/KCl, which is weak in inhibitive capacity and mud loss control. PF-LSF, an amine based silanol, and PF-HWR, a wetting alteration agent, are introduced into the Plus/KCl fluid to double the drilled cuttings tolerance of the fluid. PF-LSF and PF-HFD, plugging agents selected through extensive laboratory studies, are added into the fluid to improve its performance of mud loss control, and the barrier to mud losses generated by these plugging agents also enhance the resistance of weak formations to pressure, which is beneficial to safe operation in similar blocks and formations.
Abstract: Waste motor tires, which are seldom reused in China, can be used to make lost circulation materials (LCM) because of their advantages such as good flexibility, capability to plug when swelling, and stable physical and chemical properties. Waste tires were first ground to powders of different sizes and the rubber powders were then tested for their capability in lost circulation control. The evaluation results demonstrate that the rubber powder LCM XJ-1, has the minimum pressure required for plugging, which is 2.8 MPa, and a breakthrough pressure of 3.6 MPa. Use XJ-1 alone, fractures of 0.51 mm in size can be plugged. When used with other LCMs, fractures of about 23 mm in size can be plugged, and the pressure bearing capacity can be as high as 4 MPa. The rubber powders retain their stability at high temperatures to 135℃. As a cheap and environmentally friendly lost circulation agent, rubber powders can be used to control severe mud losses.
Abstract: The airtightness of cement sheath under alternating loading and unloading was studied using self-developed experiment facilities, and the mechanism of airtightness failure of cement sheath under alternating loading and unloading was understood based on the experimental results. Under the action of lower alternating pressure inside the casing, the time for the cement sheath to fail can be long; the action of high alternating pressure, on the other hand, will soon break down the airtightness of the cement sheath. This indicates that low pressure inside the casing string imposes low force on cement sheath which still retains its elasticity, and elastic deformation takes place in the cement sheath under alternating loading and unloading. Under the action of high stresses, on the other hand, the intrinsic micro fractures and deficiencies inside the cement sheath begin to connect with each other, and both elastic deformation and plastic deformation take place inside the cement sheath. As the alternating goes on, the plastic deformation becomes accumulated, to the extent that the plastic deformation does not vanish after unloading. Differences in the deformations of casing string and cement sheath at the interface result in a tensile stress, which, when exceeding the cementation strength at the interface, will cause the airtightness of the cement sheath to fail. This is the so-called low cycle fatigue failure of the airtightness of cement sheath under the action of alternating loading and unloading. Higher internal pressure in the casing string results in higher induced stress inside the cement sheath, larger plastic deformation, higher residual strain and tensile stress at the interface after unloading, and, the less of the number of cycles required to cause the airtightness of the cement sheath to fail.
Abstract: In commenting the long, low temperature wellbore with shallow gases in Daqing, the low density cementing slurries used had long final setting time, slowly developing gel strengths, high filter loss, and poor anti-channeling performance. All these factors contributed to channeling in annular spaces and bubbling outside the casing string, indicators of poor cementing job. In studying the low density low temperature anti-channeling cement slurry, the cement slurry was treated with a compound early strength agent, a polyacrylate filter loss reducer and a dispersible polymer anti-channeling agent, all being used to improve the overall performance of the slurry. At low temperatures, the setting time was shortened by 50%, the early strength increased by 46%, permeability reduced by 50%, and the bond strength of the interface enhanced by 47%. The cement slurry formulation has been used in 18 wells, and 11.1%of the cementing jobs were of excellent quality, bubbling outside the casing string was reduced by 1.6%. The use of the low density low temperature anti-channeling cement slurry improved the quality of the cementing jobs.
Abstract: The well Keshen-905 is an appraisal well drilled in the middle of the block Keshen-9, Keshen gas field, the fourth interval of which was going to be cemented with liner string. The well is 7,368.2 m in depth, and has bottom hole static temperature of 164℃ and pressure of 180 MPa. Well flow and mud losses have been encountered during drilling. Narrow annular space and small difference between the formation pressure and the pressure at which mud loss will occur all contribute to lost circulation during well cementing. To ensure the quality of well cementing and prevent lost circulation, plug flow was adopted in the whole process of cementing. In field operations, cement rheology was designed and plug flow calculated. The cement slurry was designed to be used at high temperature and have salt contamination tolerance, and high density (2.58 g/cm3). A flushing spacer compatible with drilling fluid was used. Monitoring of pump pressure and the volume of cement slurry returned showed that no lost circulation had ever happened during cementing. 99.2%of the hole cemented had job quality passed the requirements.
Abstract: In heavy oil thermal recovery, the high temperatures, 300℃, for instance, will deteriorate the strengths of set cement, and generate over high interior pressure inside the cement sheath because of the difference between the swelling capacities of the casing string and cement sheath. The strength deterioration and the over high interior pressure are the main factors contributing to damage to the integrity of the airtightness of the cement sheath. Several methods can be used to maintain the airtightness of the cement sheath, for example, controlling the strength deterioration of the set cement at elevated temperatures, or adding admixtures to the thermal expansion cement to improve the expansion behavior. Factors affecting the coefficient of thermal expansion of a set cement, the main parameter characterizing the thermal expansion behavior of the set cement, have been studied by adding various admixtures into cement slurries at different temperatures. Mechanisms of these factors affecting the coefficient of thermal expansion have also been investigated. It was found that some admixtures, such as silica powder and hollow micro spheres, reduce the coefficient of thermal expansion of set cement to varying degrees, while other admixtures, such as latex and carbonaceous materials can increase the coefficient of thermal expansion of set cement. Carbonaceous materials, as industrial waste, are cheap and their use in oil well cement not only reduces the cost of well cementing, but also improves the thermal expansion behavior and the airtightness of set cement, thereby prolonging the lifespan of a thermal recovery well.
Abstract: Geological factors affecting the cementing job quality and heavy oil production in block Faja, Venezuela, include: unconsolidated sandstone formations that are easy to collapse, associated gases, formation, heterogeneity that is disadvantageous to subsequent heavy oil production, long production time that imposes rigorous requirements on the mechanical integrity of cement sheaths. A high temperature anti-channeling cement slurry with enhanced toughness has been developed to solve these problems. Laboratory evaluation demonstrated that the cement slurry had good thickening performance, filtration behavior and sedimentation stability. The cement slurry had UCA transition time that is less than 20 min, and good anti-channeling performance. The elastic modulus of the set cement was greatly reduced to 2.6 GPa, the tensile strength was greater than 1 MPa, and the coefficient of heat transfer is 0.65 and 1.13, meaning that the set cement had good thermodynamic property. The set cement, after aging 5 d at 315℃, was not decreasing. All in all, the cement slurry has the potential to satisfy the needs for steam flooding, and is worth applying in other areas.
Abstract: An eccentric mechanical vibration cementing technique was used in Changqing oilfield in an effort to improve the cementing job quality of the injector wells. Cementing slurry was evaluated after vibration on a ZD-34 model electric vibrator as to its compressive strength, bond strength, thickening time, initial setting transition time, final setting transition time, and permeability. The evaluated cement slurry was then used in filed operations. The laboratory study showed that the thickening time of the cement slurry after vibration was reduced by 25%-30%, the initial and the final setting transition time reduced by 30%-50%, the 24 h strength of the set cement increased by 10%-14%, the bond strength increased by 11%-16%, and the permeability reduced by 33.3%-43.9%. This technique has been used in 5 wells in the block Wupu in Changqing oilfield, and the oil zones and water zones in these wells are well separated, with the rate of excellent well cement jobs increased by more than 20%. The laboratory experiments and the field applications all demonstrate that the eccentric mechanical vibration cementing technique can effectively enhance the quality of well cementing, and is prospective in future cementing operations.
Abstract: In improving the tight marlstone reservoir in Shulu sag, problems such as high operation pressure, short improving distance and low conductivity have been frequently encountered. A newself-diverting acid formulation was developed for use in stimulation jobs to try to solve the problems as described above. Evaluation of the viscosity, elasticity, rheological and gel-breaking performances of the self-diverting acids was performed through laboratory experiment. Communicating of fractures in the reservoir formations by acids was conducted through core flow experiment. The evaluation demonstrates that the self-diverting acid causes low damage to reservoir formations, the gels are easy to break, and the acid is evenly distributed. When the residue acid had its concentration decreased to 5%, the viscosity of the acid can be 96 mPa²s. The acid can go laterally to make the natural fractures communicated extensively, satisfying the needs to improve the marlstone reservoir. Comparison of the conductivities of the fractures using different improvement techniques resulted in a volumetric stimulation model suitable for marlstone reservoir improvement, a model integrating diverting acid fracturing and fracturing with sand. This technology has been used in the improvement of three wells (15 segments), obtaining stable daily production rate that is 10 times of the old wells.
Abstract: Acid-corroded wormholes generated in acid fracturing of carbonate rocks play an important role in flow channel communication. A quantitative characterization of the surface of the fracture planes before and after acid corrosion has not yet been found. The acidcorroded wormholes can be quantitatively characterized with a 3D laser scanner which scans the surface of the fracture planes before and after filtration of acid and numerically processes the data obtained. Studies show that the isogram and the 3D plots of the fracture planes give a clear picture of the acid-corroded wormholes. The dimensions of different spots in a wormhole can be obtained from the isogram and 3D plots of the fracture spacings. The number and the proportion of the cloud points of the different spacings in acidcorroded wormholes can be obtained from the matching histogram of the fracture planes and the histogram of the spacing distribution of the fractures. Using these data, the volume of the acid-corroded wormholes can be calculated, providing guidance to acid fracturing design.
Abstract: The clay stabilizer used in slick water fracturing fluids has the following problems such as poor compatibility, high consumption, poor inhibition to clay swelling and difficulty in solution making in field operations. A new cationic clay stabilizer, SRCS-1, has been developed to try to solve the aforesaid problems. SRCS-1 has good compatibility with the anionic polymer drag reducers used in slick water. The percentage of clay cores swelling tested with 0.3%SRCS-1 is 68.2%, better than those clay stabilizers collected from operation fields. The swelling inhibition mechanism was analyzed by measuring the surface tension, ζ potential and particle size distribution. SRCS-1 has been used in the slick water fracturing in the well Kongshen-1 in Xinjiang, and the water solution was prepared very easily and fast. The SRCS-1 had good compatibility with other additives used, and good inhibitive capacity. The slick water made had stable properties and the fracturing jobs were successful.
Abstract: In segmented fracturing of horizontal wells, gels of the fracturing fluids are often broken too early for the fluids to function properly. To solve this problem, two micro capsule gel breakers, MCB-1 and MCB-2, with different capsule cloths have been synthesized through emulsion polymerization, using ammonium persulfate as the core. The active contents, percent of encapsulation, rates of release and gel breaking retardation have been measured in laboratory experiments. The active contents of MCB-1 and MCB-2 are 38.56%and 39.69%, respectively, and the rates of encapsulation of MCB-1 and MCB-2 are 83.85%and 85.89%, respectively. Compared with the commercially available encapsulated gel breakers, MCB-1 and MCB-2 have comparatively slow release rates. The experiments also show that MCB-1 and MCB-2 gradually reduce the viscosity of the fracturing fluid in 4 hours, and the viscosity of the fracturing fluid after gel breaking is less than 10 mPa²s, indicating that the synthesized micro capsule gel breakers are effective in slowing down gel breaking, and the impairment of formation permeability caused by these gel breakers is less than 12%.
Abstract: Deep water and HTHP have been two challenges encountered in the exploration and development operations in the west of South China Sea, and low temperature at the seabed and high temperature at the wellhead are difficulties that must be dealt with in offshore well testing. Study on the heat retaining test fluids has not been found presently in China. Through the construction of the heat transfer prediction model used in gas well testing, sensitivity analyses were performed to those factors of the test fluids affecting the temperature field in the borehole of deep water and HTHP gas wells, and a method of adjusting the temperature control capability of a test fluid was established. The maximum temperature prediction error of the model is only 3.4℃. Using this model and the method, a test fluid with adjustable temperature control capability and controllable wellhead temperature was developed. The test fluid has shear stress greater than 4 Pa, and has been successfully applied in an offshore deep gas well in the west of South China Sea. The measured wellhead temperature during well testing is 16.5℃, while the calculated wellhead temperature is 18℃, and the temperatures measured at the different places in the wellbore are very close to those calculated. Test of the well has been successful, giving gas production rate of 100×104 m3/d.
Abstract: A completion fluid treated with acid chelating agents has been specially developed for use in Bozhong. In laboratory studies, the percent solution rate of the completion fluid to the oil sand taken from Bozhong was 3.62%at 60℃. At a mass ratio of 1∶1, reaction of the completion fluid and the oil sand for 72 hours resulted in a pH of 6.98. Percent reduction of swelling of the 28-2S sand cores was 88.7%. In permeability experiments, the permeability return of the oil sand tested with the completion fluid was 127.6%. The chelating capacity of the completion fluid was 110.15 mg/g to ferric ions, and 878.3 mg/mL to calcium ions. The corrosion rate of the completion fluid satisfied the needs for field operation. Oil production rate has been enhanced using the completion fluid as a perforation fluid.
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