Abstract: Low damage environmentally friendly water-free fracturing fluids are becoming the hot spot of research and application because conventional water based fracturing fluids have imposed unprecedented threats to the environment and water resources. This paper, based on the examination of relevant literatures of China, mainly introduces the composition, technical advantages and shortages of water-free hydrocarbon based fracturing fluid. Investigation and survey of literatures showed that water-free hydrocarbon based fracturing fluids, which are prepared with dialkyl phosphate as gelling agent, tri-valence metal ions as crosslinking agent and sodium acetate and sodium carbonate as gel breaker, are able to be used in fracturing reservoirs of 130℃ or less, and problems encountered in fracturing unconventional shale reservoirs, such as consumption of large amount of water, difficulties in dealing with flowback fluids and extensive reservoir damage, can be effectively resolved. Water-free hydrocarbon based fracturing fluids have technical advantages and broad application prospects in environmentally and efficiently developing oil and gas reservoirs, safety issue and cost are two big hindrances to large-scale application of them though.
Abstract: High temperature and calcium contamination are always encountered in deep well and ultra-deep well drilling. To address the high filtration rate problem caused by high temperature and calcium contamination, PASV, a high temperature calcium resistant filter loss reducer has been developed with bromide salt of 1-vinyl-3-ethyl imidazole (VeiBr), which is a high temperature stable ionic liquid, 2-acrylamido-2-methylpropane sulfonic acid (AMPS), which is a calcium resistant chemical, and acrylamide (AA) in an optimized mass ratio of VeiBr:AA:AMPS=0.53:1:2, at which the reaction product (PASV) has the best filtration control capacity. In laboratory experiment, PASV showed excellent property at high temperatures; it began to decompose at 290℃, satisfying the needs of drilling at almost all temperature conditions. A drilling fluid sample containing 40,000 mg/L calcium ions had its filtration rates before and after aging at 150℃ reduced to 5.2 mL and 8.6 mL, respectively when treated with 2% PASV, indicating that PASV has excellent filtration control ability. Mechanisms of PASV as a filter loss reducer demonstrated that PSAV molecules are adsorbed on the surface of clay particles through ionic bond and hydrogen bond, thereby shielding the electric neutralization and flocculation of clay particles by Ca2+ ions. The adsorption of PASV molecules on the surface of clay particles promots the dispersion of clay particles and improves the quality of mud cakes, hence to reduce filtration rate.
Abstract: Drilling fluids for deep well drilling should have the ability to resist the negative effects of high temperatures and salt and calcium contamination. A new drilling fluid filter loss reducer, PAANS, has been developed to satisfy the needs as mentioned above. PAANS was synthesized through enzymatic reaction, with monomers such as 2-acrylamide-2-methylpropane sulfonic acid (AMPS), acrylamide (AA), N-vinyl pyrrolidone (NVP) and sodium 4-hydroxybenzenesulfonate (SHBS). Catalyst used in the reaction was horseradish peroxidase (HRP). PAANS has benzene ring in its molecules. Another reference polymer, PAAN was also synthesized at the same reaction conditions, with no benzene ring in its molecules. The molecular structure of the two polymers was characterized with 1H NMR. Rheology and filtration test results showed that, the properties of a drilling fluid sample treated with 2.0% PAANS and aged at 220℃ for 16 h, were as follows:apparent viscosity=16.5 mPa·s, plastic viscosity=10.5 mPa·s, yield point=6.0 Pa, API filtration rate=12.4 mL, and HTHP filtration rate=24.0 mL. The PAANS treated drilling fluid had the ability to resist salt contamination to saturation and calcium contamination to some extent. Obviously, the performance of the PAANS treated drilling fluid is superior to the performance of the PAAN treated drilling fluid. Experiments on adsorption capacity and particle size distribution of PAANS, and mud cake microstructure have revealed that the mechanisms of filter loss control by PAANS is because there are benzene rings distributed on the molecular backbones of PAANS, thereby forming a rigid molecular structure.
Abstract: Clays used in high density saturated drilling fluids for drilling gypsum, salt formations and formations with high-pressure brines have some drawbacks, such as formation damage by the invasion of clay particles, and progressive gelling of the drilling fluids caused by uncontrollable viscosity uprising at elevated temperatures and overuse of sulfonates. Progressive gelling of drilling fluids with clays usually cannot be controlled by rheological optimization. To resolve this problem, a filter loss reducer, BH-HSF, for high density clay-free saturated drilling fluids has recently been developed through synthesis of modified starch and other polymers. BH-HSF is able to develop an "interpenetrating polymer network" in water solution, and performs well at 150℃ and Ca2+/Mg2+ concentration of 4,000 mg/L. High density clay-free saturated saltwater drilling fluids treated with BH-HSF have API filtration rate of less than 4.0 mL. They have good capacity for suspending weighting materials, and no weighting materials settlement has ever occurred after long period of standing. Deterioration of the rheology of BH-HSF treated drilling fluids can be controlled by rheological optimization. BHHSF has properties that are equivalent to HT-Starch (a well-known drilling starch with advanced performance) and is well compatible with other drilling fluid additives.
Abstract: The adsorption behavior of three lubricant base oils on the surface of drilling tools (iron) has been studied with molecular simulation. Monte Carlo simulation results from the studies showed that triglyceride esters of C18 fatty acids have space deformation ability. The adsorption energy of triglyceride esters of C18 fatty acids on the surface of iron is -48.7352 kJ/mol, about two times of the adsorption energy of n-stearic acid methyl ester and of stearic acid methyl esters. Dynamic simulation results showed that n-stearic acid methyl ester and stearic acid methyl esters form a monomolecular layer on the surface of iron, the thickness of which is ca. 0.35 nm. The thickness of the film formed by triglyceride esters of C18 fatty acids on the surface of iron is ca. 1.5 nm. Triglyceride esters of C18 fatty acids have high adsorption energies on the surface of iron, and are able to form thick oil films, meaning that they are superior to n-stearic acid methyl ester and stearic acid methyl esters as a lubricant.
Abstract: Centrifuge is a common equipment for field drilling fluid cleaning and is a solids control equipment with steady solids control efficiency. Two models of centrifuge, LW355 and LW450, are presently commonly used in field operations. For high rate of treatment, model LW600 is also used. Whatever the model is, the separation efficiency and the solid composition of the down-flow of the centrifuge do not vary much. This is because for a fluid with certain density and viscosity, an ideal "cut point" exists for the centrifuge to deal with. The composition and properties of a drilling fluid is always changing and in maintenance in field operations, the ideal "cut point" is changing accordingly, but most centrifuges presently used do not have the ability to automatically regulate its "cut point" to the ideal value. Hence, the composition of the solids in both down-flow and overflow of the discharge should be analyzed continually to monitor the real-time treatment efficiency of the centrifuge and to adjust the separation efficiency to an ideal state as far as possible based on the solids composition analyses. Analyses on the composition of down-flow solids gathered from centrifuges used in oilfields in China showed that there is an obvious difference between the separation efficiencies for high density solids and low density solids. This is because when a centrifuge is in operation, change in the feed state of the centrifuge is continuously changing, resulting in random change in the "cut point" of the centrifuge. A systematic analysis on the solids composition of the discharge of the centrifuge is helpful to advancing the technology and improving the separation efficiency of centrifuge.
Abstract: The quality of bentonite not only affects the performance of the drilling fluids made; it also affects the compatibility of the bentonite slurry with other mud chemicals. It is economically unreasonably to formulate drilling fluids with bentonite of poor quality because too much bentonite and chemicals will be consumed to formulate a drilling fluid of the same properties. Property differences between several drilling grade bentonites, OCMA clays and naturally obtained sodium bentonite, artificial sodium bentonite have been studied in laboratory under room temperature and high temperatures (120, 150and 180℃). Problems that may arise in field use of drilling grade bentonite and OCMA clay were investigated. It has been shown that the technical indices in bentonite evaluating standards currently in use are not able to meet the requirements of evaluating the bentonites in use presently. The paper further suggests that apparent viscosity of bentonite suspension being aged at elevated temperatures should be used as a criterion to control the quality of drilling bentonite.
Abstract: To find out a microbial strain for effective degradation of sulfonate drilling fluid, experiments were conducted using drilling fluid sludge from Kelamayi Oilfield as the source of microbe and sulfonated asphalt as the sole carbon source for concentration, acclimation, isolation and purification. The species of the microbe was determined with physiological biochemistry technology and molecular biotechnology. The degradation behavior of the microbe was studied through single-factor experiment and orthogonal experiment. A microbial strain that is able to effectively and efficiently degrade sulfonated asphalt was found through these experiments, and was named X2, which is an Oceanobacillus (in ocean sediments) determined with physiological biochemistry and molecular characterization. Single-factor experiment showed that the best P-source for X2 to grow is KH2PO4, and the best N-source is NH4NO3. Orthogonal experiment showed that the optimum growing conditions for X2 are as follows:36℃, pH 7.8, 1% salt and inoculum concentration of 10%. The optimum degradation conditions for X2 are as follows:36℃, pH 8.2, 0.9% salt and inoculum concentration of 12%. The rate of degradation at these conditions is 59%-71%. The Range of the pH values is highest and is thus a key factor affecting both the growth of the strain and the COD for X2 to degrade. The experimental results have provided an effective theoretical basis for degrading waste drilling fluids.
Abstract: Formations drilled in shale gas drilling are full of micro fractures and are brittle, and are therefore easy to hydrate and slough. Oil base drilling fluids and synthetic base drilling fluids have been commonly used in shale gas drilling, and are effective in preventing borehole wall sloughing and pipe sticking. However, when drilling into a broken belt or into formations with abnormally developed fractures, large amount of sloughing and severe borehole wall collapse still happen even oil base drilling fluids are used. To address borehole wall collapse and mud losses when drilling broken formations, the borehole wall should be strengthened promptly and effectively. A drilling fluid treated with two borehole wall strengthening agents, YH11 and BT100, was tested for its capacity to strengthening borehole wall. The test results showed that this drilling fluid formulation is suitable for shale gas drilling. The density of this drilling fluid is adjustable in a range of 1.14-1.50 g/cm3. It has strong inhibitive capacity, and is capable of preventing mud losses by drilling at low densities. Good filming and sealing performance of the drilling fluid helps resolve the problem of stabilizing formations with low pressure bearing capacity. Minimizing of downhole troubles and downhole safety insurance help enhance rate of penetration. Both laboratory experiment and field application showed that YH11 and BT100 are able to strengthen borehole wall by promptly cementing the broken formations and plugging the fractures. Cementing and plugging of the formations with YH11 and BT100 greatly reduce the porosity and permeability of the formations, effectively restraining the transfer of hydraulic pressure of mud column into the pores of formation and the invasion of mud filtrates into the depth of formation, hence minimizing loss of pressure supporting the borehole wall. The use of YH11 and BT100 has double effects of preventing borehole wall collapse and mud losses.
Abstract: Severe borehole wall destabilization and pipe sticking caused by borehole wall collapse have long been encountered in drilling the Shawan formation-Ermeishan basalt formation in southwest Sichuan Province. A drilling fluid with high inhibitive capacity and plugging ability has been formulated based on the analyses of the mechanisms of borehole wall instability and field operations. In laboratory evaluation of the drilling fluid, the percent recovery of shale samples tested with the drilling fluid was 99.98%, the HTHP filter loss was 3.6 mL, the HTHP water filter loss was 4.8 mL, the HTHP filter loss tested on a sand bed was 4.4 mL. A plugging slug used with the drilling fluid and a technique of using the plugging slug was also designed. The formulation of the drilling fluid is:(0.5%-2.0%) bentonite + (0.5%-1.5%) PAC-LV + (5%-6%) SMP-3 + (2%-3%) JNJS-220 + (0.3%-1.5%) NaOH + (1%-3%) FT + (0.1%-0.3%) poly glycol + (0.4%-1%) CQ-SIA + (6%-8%) WND + (5%-10%) organic salt + 3% ultrafine calcium carbonate + barite. It was considered practical and feasible that mud loss control while drilling should be strengthened and the adhesive ability and viscoelasticity of mud cakes be improved. High quality mud cakes protect the borehole wall from being washed and keep drilling fluid out of borehole wall. This will mitigate secondary damage of borehole wall by downhole mechanical collision, drilling fluid washout and pressure surge.
Abstract: Well JY2-5HF, completed at depth of 5,965 m, is an appraisal well drilled in Fuling shale gas feld, Chongqing, by Sinopec. The length of the horizontal section of this well is 3,065 m. The second interval of this well penetrated shale formations in its middle and lower sections and is at risk of borehole wall sloughing, pipe sticking and mud losses. An anti-sloughing drilling fluid, BH-200, formulated with synergetic additives, such as shale inhibitor BT-200, K-HPAN, KCl, a wellbore stabilizer, an emulsifed asphalt, a non-penetration additive, polyglycol, a multi-function solid lubricants and QS-2, was used to drill the well. The horizontal section of the well required that the drilling fluid should have good physical and chemical wellbore stabilizing capacity, good lubricity and good suspending capacity. An oil base mud, with O/W of 90:10 (26% CaCl2 solution) and electric stability of at least 900 V, was used to drill the horizontal section. Field operations showed that the drilling fluids used well satisfed the needs of downhole and drilling engineering. Rotary steering and oil base drilling fluid are suitable for long horizontal drilling in shale gas wells. Formation pressure coeffcient measured after fracturing was generally higher than the pressure coeffcient during drilling by 0.1-0.2, and it is thus advised that this value be deducted when designing the density of a drilling fluid.
Abstract: Drilling fluid invasion during drilling in tight sands gas reservoirs causes serious formation damage problem. Using core analysis and core flow experiment technologies, main damage mechanisms were determined for the tight sands gas reservoir in Block Linxing. Technical difficulties in field drilling fluid operations were summarized and analyzed, and a drill-in fluid for the protection of the reservoir was formulated based on optimization. Laboratory study showed that the rocks in the tight sands gas reservoir in Linxing have medium-coarse sand structure, compact cementation, fine pore throat and sensitive clay minerals. Several kinds of formation damage are found in the reservoir rocks, such as serious water block damage, moderately strong water sensitivity and stress sensitivity damage (critical pressure is 7.0 MPa), moderately weak flow rate sensitivity (critical flow rate is 0.75 mL/min), salt sensitivity (critical salinity is 7,500 mg/L), sensitivity to alkalinity (critical pH value is 10.0) and sensitivity to mud acid. Technical difficulties found in Linxing include formation damage, mud losses, wellbore collapse, high torque and drag, and hole cleaning. The optimized drill-in fluid has good plugging capacity and low surface tension of filtrate (23.3 mN/m), and is thus able to minimize the invasion of particles and to weaken water block effect. The percent recovery of permeability of reservoir rocks was raised to 91.3% of the original value, demonstrating the reservoir protection capacity of the drill-in fluid. Field application of the drill-in fluid showed that the optimized drill-in fluid met the needs of drilling in complex formations or horizontal drilling.
Abstract: Thermal recovery is presently the main method of producing heavy oil in Bohai oilfeld where heavy oil reserves are abundant. Drilling fluid technology aimed at reservoir protection in thermal production well has been developed in such a special thermal development environment to make the full use of the nonconventional heavy oil characteristics and the high temperature thermal injection technique, and to cut the operation cost. The thermal production heavy oil well Lvda5-2N in Baohai oilfeld is taken as an example in this paper. In developing a modifed drilling fluid suitable for drilling a thermal production horizontal heavy oil well, the unique physical properties of the reservoir were taken into account and the potential formation damage factors-all kinds of sensitivities-were analyzed. Selection of additives with strong inhibitive capacity, evaluation of thermal degradation of additives, optimization of the mud weight, optimization of plugging agents and evaluation of reservoir protection have all been performed through laboratory experiments. The drilling fluid developed has strong inhibitive capacity and good compatibility with formation fluids. The degradation product of the drilling fluid at high temperature is black carbon. The permeability recovery of a core flooded with this drilling fluid is greater than 85%, indicating that the drilling fluid has good reservoir protection capacity. Using this drilling fluid, the cost was reduced by 40%.
Abstract: The reservoir formations in MFM sub-block of the block Ayacucho in the Orinoco heavy oil belt, southeast Venezuela, are characteristic of shallow depth of burial, low pressure, high porosity and low bottom hole temperature. Wells drilled in this block were mostly horizontal wells with long intervals. In previous drilling practices, water base polymer muds mixed with oil were commonly used, resulting in downhole troubles such as over-pull and resistance during tripping, and pipe sticking etc. A weak gel micro foam drilling fluid formulated with a flow pattern optimizer and a foaming agent has been developed in place of the water base polymer muds previously used. This weak gel micro foam drilling fluid has a density between 0.85 g·cm-3 and 1.00 g·cm-3. The low-shear-rate viscosity of the drilling fluid after being aged at 120℃ is at least 40 000 mPa·s. With this drilling fluid, problems found in the past, such as over-pull and resistance during tripping and pipe sticking, were effectively resolved. Application of the weak gel micro foam drilling fluid on the well MFM-62 and the well MFM-65 was successful; the horizontal sections of the two wells were successfully drilled, with no downhole troubles occurred. Time spent drilling the horizontal sections was reduced from 12 d to 4 d. Daily oil production rate was 90 t, 40% higher than that of the adjacent wells.
Abstract: Severe mud losses, coexistence of blowout and mud loss and difficulty of drilling are problems associated with narrow safe drilling windows found in Moxigaoshiti and Xiadongchuan, Sichuan, and were all overcome thanks to the use of precisely managed pressure control drilling technology. In managed pressure control drilling, lack of effective and safe process control techniques during tripping and well completion also resulted in severe mud losses and high risk of well control. To resolve these problems, a brittle and drillable gel slug separating technology has been presented based on inorganic hydraulic cementing theory, close packing theory and strengthening through solidification theory. By selecting the best additives and optimizing, a gel slug-forming working fluid was prepared. Evaluation of the working fluid showed that it has good initial mobility and stability. The 40 Bc thickening time of the working fluid is manageable in 0.5-4.0 h. It functions normally at 150℃, and is resistant to contamination from drilling fluid. The gel slug, after becoming hardened, has compressive strength of 8.02 MPa. When bonded with the surfaces of the casing, the bond strength can be 1.45 MPa/m2. The hardened slug itself has good cementing performance, with gas containment capacity of no less than 2.69 MPa/m under pressure. Thus gel slug, after hardening, has drillability of grade 1, and can be drilled out with drill bit.
Abstract: In large-scale natural gas and shale gas development, disadvantages of silicate oil well cement, such as brittleness, shrinkage on hardening, especially the vulnerability of set cement to mechanical failure during staged fracturing operations, damage the integrity of cement sheath and result in sustained casing pressure (SCP). One way to improve the job quality of well cementing is to develop new cementing materials having good mechanical properties, strong cementing capacity and characteristics of not shrinking after solidification.Using interpenetrating network (IPN) structure design principle, a new magnesium oxysulfate resin cementing material has been developed through selection of thermosetting resin and magnesium oxysulfate framework material. This material has density between 1.1 g·cm-3 and 1.8 g·cm-3, 24 h compressive strength greater than 14 MPa and elastic modulus between 2 GPa and 4 GPa. It has excellent sealing ability resistant to the damage of cement sheath integrity. Laboratory experiment and field application results showed that this magnesium oxysulfate cementing material can be used to partly replace oil well cement in sealing reservoir formations, removing SCP and well abandonment. It provides a new and economically efficient preventive method for resolving SCP problem prevailing in oil and gas fields.
Abstract: The development of unconventional petroleum is demanding more and more rigorous requirements on the job quality of cementing ultra-deep wells, complex wells and shale gas wells. Most of the cementing materials cannot satisfy these requirements and study should be done to find out new cementing material for field application or improvement of the performance of set cement. A carbon nanotube (CNT) dispersion has been developed with good stability for use in cement slurry. Laboratory experiments on cement slurries treated with the developed CNT, such as compressive strength test, flexural strength test, uniaxial/triaxial mechanical properties test and micro structure determination, were conducted to determine the treatment concentration of the CNT, to understand the dispersing effect of the CNT, and to analyze how CNT affects the mechanical property of set cement. It was found, through these experiments, that addition of 0.05%-0.1% CNT in cement slurry enhanced the compressive strength and flexural strength of set cement, and the effects of CNT on the two strengths were increasing with time. CNT was found to be able to reduce the elastic modulus of set cement and to improve the toughness of set cement by increasing its plastic deformation. Mechanisms in which the CNT increases the strength and toughness of the micro structure of set cement are pulling, bridging, nano-inductive effect and network filling effect. Dispersed CNT has good compatibility with cement slurry.
Abstract: Micro-fractures developed inside set cement in an oil or gas well seriously affect the isolation integrity between borehole wall and casing string, thereby shortening the life of the well. Self-healing of micro-fractures in set cement is an effective way of resolving this problem. Studies on the mechanisms of expandable self-healing agents have seldom been conducted until now and the self-healing mechanisms lack theoretical support. This paper presents fill factor as an indicator to evaluate the self-healing of set cement, builds a mathematical model describing the sealing of micro-fractures in set cement by expandable self-healing agents, and explains main factors affecting the self-healing of set cement. A simple quantitative method for simulating the micro-fractures developed in set cement was designed based on Brazilian disk test. Several self-selective healing agents were evaluated for their self-healing ability using set cement micro-fracture self-sealing evaluation device, verifying the relationship between the self-healing effect and the amount of liquid adsorbed by self-healing agent, concentration of self-healing agent, as well as the width of micro-fracture. It was found that the selfselective healing agent, when mixed with water, had critical self-healing fill factor of 0.473, and the healing agent is, at most, able to seal fractures of 234 μm in width. The self-selective healing agent when mixed with oil, had critical self-healing fill factor of 0.490, and it is, at most, able to seal fractures of 150 μm in width. The studying results lay a theoretical foundation for the use of expandable self-healing agents in sealing micro-fractures developed inside set cement.
Abstract: Tarim Oilfield has done a lot of work to optimize the casing program of development well and appraisal well in block LN to achieve "fast, cost saving and efficient" drilling. Reduced number of casing strings result in long open hole section with cementing difficulties such as HTHP, large temperature difference and coexistence of multiple formation pressures, which in turn impose more rigorous requirements on the properties of cement slurry. Based on the difficulties encountered in the past in cementing long lowpressure open hole section in which mud losses are easy to occur, and the well cementing techniques commonly used in block LN, laboratory experiments were conducted to evaluate the adaptability of BX cement slurry to the practical situation in that area. It was found that BX cement slurry had high initial consistency, strong thixotropy and good anti-channeling capacity, and was thus compatible with the geologic nature of the block LN. The cement slurry, during WOC, was able to prevent mud losses from occurring. The cement slurry was designed to have two densities and two thickening times, effectively reducing the liquid head of cement slurry, and in turn reducing the risks of lost circulation during operation. With this technique, the job quality of well cementing has been improved and the needs for cementing long low-pressure open hole section have been satisfied.
Abstract: The Shahejie Formation of the No.5 structure in Jidong Oilfield is a complex lithologic gas reservoir, the lithology of which is mainly basalt and volcaniclastic rocks. The reservoir, which has poor physical properties (porosity in a range of 0.04-0.4 mD) is buried in depths between 4,781.6 m and 5,200 m, with formation temperature between 170℃ and 180℃. The reservoir has previously undergone fracturing operation in the φ139.7 mm casing, with flowrate of 2 m3/min and pressure of 70 MPa. The pressure after stopping pumping was 61 MPa, and the operation was failed. From laboratory experiments (total analysis, Xray diffraction analysis, acid dissolution, ground stress and natural fracture identification) it was determined that natural fracture is developed in the reservoir and the fillings of the fractures are mainly acid-soluble minerals. Based on these analyses a technique of using pre-pad acid fracturing followed by fracturing operation was presented to improve the production of the reservoir. Using a high temperature organoboron low residue guar gum fracturing fluid (functioning at temperature up to 170℃), a thickened acid, combined with other measures such as optimized perforation method, increased compressive strengths of the surface equipment and plugging natural fractures with selfdegrading filter loss reducing materials etc., the fracturing operation was successfully performed in deep wells penetrating the fractured volcanic rock reservoirs in the No. 5 structures in Nanpu area. The well with failed fracturing operation previously was fractured again with flowrate of 5 m3/min and the maximum pressure of 74 MPa. Total amount of sand added was 60 m3, and the fracturing operation was successfully performed. The technology described above was used on 3 wells in Nanpu area.The maximum amount of sand added in a single well was 125 m3, and the maximum casing pressure was 85 MPa. The well NP5-A, after fracturing operation, was flowing with a φ6.35 mm choke, and the daily gas production output was 10.7×104 m3.
Abstract: The Ordovician carbonate reservoir in the Yangshuiwu buried hill structure in Langgu sag is characteristic of deep burial, high temperature, compact lithology and high inhomogeneity etc., making it difficult to effectively stimulate the reservoir for high and stable production. Studies on "staged injection of acids for fracturing, temporary plugging with fiber (particles) for diverting and sand injection for acid-fracturing" have been conducted to address these problems. The studies gave birth to three choice stimulation fluids, which were "high temperature neutral crosslinking fracturing fluid, high temperature clean self-diverting acid and low-friction slick water", and a temporary plugging for diverting (spherical agent) technology. The well AT3, after applying these stimulation fluids and technology, produced 50×104 m3 gas and 35 ton oil daily, realizing the objectives of uniform acidizing, complex fracture network construction, communication of favorable pay zones located far apart and improvement of vertical producing degree and conductivity of artificial fractures, and satisfying the requirements of large-scale volumetric acid fracturing of similar reservoirs.
Abstract: In fracturing operations, timingof gel breaking plays a great role in the enhancement of oil recovery. A poly(vinyl acetateacrylamide) (P(Vac-AA))core-shell microsphere coated with ammonium persulfate ((NH4)2S2O8) has been synthesized as a gel breaker through inverse emulsion polymerization. Laboratory experiments have been done to compare the changes of the viscosity and pH value of polyacrylamide solution when the microsphere and ammonium persulfate were used as gel breaker respectively. Experimental results showed that the viscosity half-life of polyacrylamide solution, which was only several minutes when ammonium persulfate was directly used as gel breaker, was extended to 1 h when the microsphere was used as gel breaker. Meanwhile, the use of the P(Vac-AA) microsphere also slowed down the pH decrease of the polyacrylamide solution and reduced the magnitude of the pH decrease, indicating that the core-shell structure inhibited the rate of hydrogen ion generation by oxidative degradation of polyacrylamide in the solution. It is thus understood that by delaying its swelling action, the microsphere slowly releases ammonium persulfate, reducing the free radical oxidative degradation rate of polyacrylamide in aqueous solution.
Abstract: Reservoir acidization and fracturing are two common stimulation measures used to enhance the productivity of low porosity low permeability wells. Offshore gas fields have less reservoir stimulation measures because of limitations in well completion method, job cost and safety. To improve the productivity of the high temperature low porosity low permeability gas field in Wenchang, a new completion stimulation fluid suitable for directional well and horizontal well has been developed. This stimulation fluid has the abilities of acidization, gel breaking, porosity improvement and anti-water blocking. Percent acid solubility of the stimulation fluid for formation solids is between 7.70% and 12.99%. This stimulation fluid is capable of in-depth acidizing and effectively reducing capillary pressure and enhancing cleanup of acidizing residues. Laboratory experimental results showed that the permeability of a rock sample contaminated by the stimulation fluid was resumed by more than 90%, and the permeability recovery of the rock sample was steady after second contamination by the stimulation fluid. Application of the stimulation fluid in Wenchang gas field gave birth to a production rate that is 1.7 times of the allocated production rate of each well, substantially releasing the productivity of the high temperature low porosity low permeability wells and providing a clue for the development of similar low permeability offshore gas fields.
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