Abstract: A testing device was developed for the measurement of the rheology of aphron drilling fluids. This device has the capacity of simulating downhole temperatures to 100 ℃ and downhole pressure to 20 MPa. A procedure for the testing of the HTHP rheology of aphron drilling fluids is established. A newly prepared aphron drilling fluid is tested using this device, showing good shear thinning property. Foam quality greatly affects the rheology of the aphron drilling fluid. Pressures, on the other hand, do not obviously affect the rheology of the aphron drilling fluid because of its high pressure resistance. Temperatures greatly affect the viscosity of the liquid phase, thus plays great role in determining the rheology of the aphron drilling fluid. Types of gases have little effect on the rheology of the aphron drilling fluid. In field application, the rheology of the aphron fluid can be adjusted by changing the amount of foamers and agitation speed.
Abstract: An ultra-high temperature water base drilling fluid was prepared with high temperature filter loss reducer MP488, high temperature rheology stabilizer CGW-6 and high temperature filter loss reducer HTASP-C with good salt tolerance. The drilling fluid, having density of 2.3 g/cm3, was able to tolerate salt (NaCl) contamination to saturation, and percent recovery of shale sample in hotrolling test of was 94.1%. It also had good suspension capacity and tolerance to clay contamination. This drilling fluid was suitable for use in high temperature (260 ℃) well drilling, with its density being adjusted between 2.0 g/cm3 and 2.5 g/cm3.
Abstract: Well Shenping-1 is the first horizontal exploration well having oil shale and argillaceous dolomiteinterbeds reservoirs. The existence of oil shale presents drilling difficulties such as borehole instability, well path control difficult in reservoir drilling, environmental issue and low ROP, to name but a few. A whole oil base drilling fluid was developed for use on Well Shenping-1. It has a density of 1.55 g/cm3 and temperature resistance to 150 ℃. As a whole oil mud, it has good rheology, inhibitive capacity, plugging capacity, contamination resistance, lubricity and high temperature stability, thus is able to control the swelling and sloughing of the oil shale when in contact with water. Shenping-1 had an average ROP 1.6 times that of the wells drilled nearby, and time efficiency of drilling was increased by 30%.
Abstract: A water base drilling fluid for use in shale gas drilling was developed, and the effect of XAN-YZ, a shale stabilizer, on the rheology, inhibitive capacity and sealing performance of this drilling fluid was studied. When treated with 2% XAN-YZ, polymer sulfonate drilling fluid has improved shear thinning performance, reduced rate of swelling of shales by 40%, and increased percent recovery of shale cuttings in hot rolling test by 16%. Pressure bearing capacity of the formation drilled with this drilling fluid is increased from 2 MPa to 5 MPa. XAN-YZ generates dense mud cakes on the borehole wall, thus instantly heals and seals the fractures, beddings and pores found in shale formations, and increases the pressures for filtrates to penetrate the shale formation from 2 MPa to 15 MPa. Laboratory study shows that the optimum treatment of XAN-YZ in polymer sulfonate drilling fluid is 2%. This study provides a new technical clue and means for shale gas drilling with water base drilling fluids.
Abstract: A new shale stabilizer, DLF-50, was developed for use in the drilling operations in Jidong area, where micro-fractures and beddings are developed in the brittle Tertiary formations such as the Dongying formation and Sahejie formation. The DLF-50 was synthesized with AMPS, methacrylic acid (MAA), n-dimethylacrylamide (DMAM), a cationic monomer, a nano modified asphalt, and a dispersant. DLF-50 has good filtration control capacity even at 150 ℃. In field applications of DLF-50 in Well Ze10-108x and Well Ning93x, gauge holes were drilled, with no drag and resistance ever met during tripping, and no borehole collapse and cave-in ever encountered in long open hole drilling.
Abstract: Three new filtrate reducers, REdul-200, JNJS-220 and CPF were evaluated against conventional filtrate reducers, such as SMP-1, SMP-2, SMP-3, PSC-2 and SPNH, for their mechanisms of action in reducing high temperature filtration. Study on the particle size distribution of the drilling fluids treated with these filtrate reducers shows that Redul-200 is a mixture of polymer and inert solid particles, JNJS-220 contains submicron solid particles, while CPF contains solid particles that have wider size distribution (from submicron to a hundred microns). Field application shows that the new filtrate reducers have better filtrate reducing performance and better rheology than the conventional filtrate reducers mentioned above.
Abstract: A product, FPS, is synthesized with used foam styrene, butyl methacrylate and acrylamide using emulsion polymerization. FPS has particle sizes distributed between 0.1 μm and 10 μm, and is aimed at sealing and plugging micro-fractures in borehole walls during drilling. FPS is stable at temperature up to 180 ℃. Drilling fluid treated with FPS at concentration of 2% has good mud cakes, and reduces the filter loss of fresh water drilling fluid from 45 mL to 13.6 mL, and the filter loss of polymer sulfonate drilling fluid from 12 mL to 4 mL. FPS has particle sizes that are compatible with the sizes of micro-fractures and quickly forms a film in the nearwellbore zones. FPS has better performance as a sealing and plugging agent than sulfonated asphalt.
Abstract: This paper discusses the chemical principles of aluminum complex as chemical sealing agent. In laboratory studies, an aluminum complex, PF-ChemSeal, was evaluated using SEM for its ability in sealing pore throats and micro fractures of shales. PF-ChemSeal precipitates on the surface of shales and borehole walls to form a dense layer of aluminum complex. In dynamic pore pressure transmission studies, the semi-membrane efficiency of shales is increased to higher than 80% with the use of PF-ChemSeal. The content of PF-ChemSeal in drilling fluids can be monitored by measuring the concentration in drilling fluids of fluorine ions. PFChemSeal has been used in the Block CFD in Bohai Bay, and is well compatible with other water base mud agents. Gauge holes have been drilled with PF-ChemSeal treated muds. PF-ChemSeal minimizes the transmission of pore pressure in shales, hence making the shales more stable.
Abstract: Air base drilling fluids are suitable for drilling pressure depleted formations and wells with serious mud losses, but water cut restricts the use of this technology. To solve this problem, a synthesized water absorbent is used to carry water out of hole, and the amount of the water absorbent is calculated based on a computational model. A testing device simulating the water carrying process was developed for predicting the amount of the water absorbent suitable for a certain range of the volume of water cut. Laboratory study shows that the computational model can be used to accurately predict the amount of water cut. The reusable water absorbent has the properties of fast absorption, high absorption capacities, and resistance to salt, acid and alkali. Temperature and pressure have small effect on the performance of the water absorbent. This new device is capable of simulating water cut of different volumes, and compared with previous devices, this device is smaller and is easy to operate.
Abstract: A new clay-free drill-in fluid, UltraFLO was developed based on the analyses of the advantages and disadvantages of conventional drill-in fluids. UltraFLO has components that are all liquefiable. When used with simple latent acids in well completion, all mud cakes can be made liquid. UltraFLO remains stable at temperatures as high as 140 ℃, and can tolerate drill cutting contamination to 15%. Permeability recovery of cores contaminated by UltraFLO drill-in fluid reaches 89%, and 96% after treatment of the cores with latent acids. Filed application of UltraFLO shows that this drill-in fluid has good inhibitive capacity and lubricity, and is easy to use. Three wells drilled with UltraFLO drill-in fluid had production rates beating estimates.
Abstract: Filtrates of drilling fluid cause damage to low permeability sandstone gas reservoir, usually by water block, and sometimes by plugging by solid particles, retention of adsorbed polymer on the surface of pore throats, and water sensitive formation clays, all resulting in reduced rate of production. A flushing fluid, NDF-1, was developed to solve these problems. NDF-1 reversed the surface of the reservoir rocks from strong hydrophilicity to weak hydrophilicity, thus minimized the effect of capillary force and entered into the interior of some solid particles to disintegrate and remove solid blockades. Laboratory study showed that NDF-1 remarkably recovered permeability of rocks impaired by DIF damage, with percent recovery of permeability by 133.45%. Well CB3-3, treated by NDF-1, had gas production rate increased by 35.71% during well test.
Abstract: Calcium chloride workover fluid was modified through optimization of additives used in the workover fluid, such as scale inhibitor, corrosion inhibitive cleanup additive, swelling inhibitor and weighting agent, in an effort to solve the problem of scaling caused by calcium chloride workover fluid and sodium bicarbonate formation water. As a result of the modification, a calcium chloride solids-free workover fluid of 1.20-1.55 g/cm3 was developed. By treatment with BH-1, a scale inhibitor, the workover fluid is compatible with sodium bicarbonate formation water. It is highly efficient in clay inhibition, and has rates of corrosion to tubing steel that are equivalent to fresh water. This workover fluid has surface tension that is less than 43.8% that of fresh water, and freezing point between -10℃--55℃. It is compatible with crude oil, and is suitable for use in wells having sodium sulphate water, sodium bicarbonate water, calcium chloride water and magnesium chloride water. This workover fluid had been successfully applied in four wells.
Abstract: The so-called API's “two-point” method for rheological calculation often produced big errors in the calculation results which are often different than the data collected in field operations. A modified calculation method is presented based on the principle of the “two-point” method, combining the calculation method for shear rate of fluid near the wall of pipes. Data of laminar flow of two drilling fluid samples, A and B, were collected in laboratory experiments and used to verify the accuracy of the modified method. The verification shows that the modified method is more accurate than the API's method in calculating pressure drop of laminar flow. For example, Bingham rheological parameters of the fluids A and B calculated with the modified method were used to calculate the pressure drops in pipe laminar flow, the calculation errors were 17.61% and 40.19% less than the errors generated by the old “twopoint” method, respectively.
Abstract: Ultra high density cement slurries always have rheology and stability that do not satisfy the needs for field operation. In laboratory studies, reduced iron powders and ground hematite was used in an effort to obtain a cement slurry with ultra-high density. This cement slurry was further treated with silica fume and micro silica to improve its high temperature stability. The principles behind these experiments are the so-called “close-packing of three different particle sizes” model. The prepared cement slurry has temperature stability of 200 ℃ and density of 2.82 g/cm3. In laboratory evaluation, it shows satisfactory anti-channeling capacity and good rheology, showing that the model is reliable and feasible in designing ultra-high cement slurries.
Abstract: The effect of the concentration of fly ash and micro silicon powder on the compressive strength of set cement at middle and high temperatures was studied. At elevated temperatures (≥125 ℃), micro silicon powder (used as stabilizer in cement slurry) hindered the normal increasing of the compressive strength of the fly ash cement slurry. A new high temperature enhancer was developed for use in low density fly ash cement slurry to maintain its high temperature stability and to solve the abnormal development of the strength of the said cement slurry. Using this enhancer, cement slurries having density of 1.50-1.60 g/cm3 were developed. These slurries had good sedimentation stability, low filter loss, changeable thickening time, high compressive strength of set cement, and good compressive strength development at the top of cement slurry column. The static gel strength of the cement slurry had transition time of 18 min at 130 ℃, satisfying the needs for well cementing at higher differential temperatures, such as 85-130 ℃.
Abstract: High pressure offshore wells with low porosity and low permeability reservoirs always encountered gas channeling during wait-on-cementing (WOC) and cement sheath breakdown after fracturing. A new cementing slurry with enhanced toughness and antichanneling capacity was developed to deal with these problems. The preparation of this new cement slurry was based on the numerical analysis of the properties of set cement necessary for fracturing operation, and other improvement such as the use of latex, fiber and expansion agent. The set cement thus had elastic modulus reduced by 50% and tensile strength increased by 10%, and had improved anti-channeling capacity. This cement slurry formulation had been successfully used in well cementing in Donghai block, satisfying the need for gas channeling prevention and fracturing operation.
Abstract: The Benxi Formation in the Block 224 in Changqing Oilfield is mainly unstable mudstones and coal beds which always collapsed during drilling with mud density of nearly 1.6 g/cm3. The liner string commonly used had a diameter of 244.5 mm, making well cementing difficult because of large annular space and difficulty in flushing and displacing, and cementing quality of the set cementing poor. Meanwhile, the volumes of gases injected into and produced from a single gas storage well were huge, causing the cement sheath to be broken by the action of cyclical stresses, and hence annular channeling and pressure anomaly. To solve these problems, a high performance high density flushing spacing fluid and a cement slurry with enhanced toughness were developed and were applied successfully in the cementing of the φ244.5 mm liner in the Well Jingping22-4-2 in Block Shaan224, with 95.46% of the cementing job acceptable and 79.05% high quality. Subsequent injection and production of gases were operated without a hitch.
Abstract: Acids have strong corrosion to cement; different acids corrode cement in different mechanisms. The solution and dispersion of set cement in hydrochloric acid and hydrofluoric acid were studied by static soaking of set cement in these acids. Using SEM, polarized light microscope and X-ray energy spectrometer, the surface composition and textures of set cement being corroded by acids can be measured. These studies helped understand the cleansing of cement scales with acids. When dissolved in hydrochloric acid, the residue of cement was mainly SiO2, and when dissolved in hydrofluoric acid, the residue became CaF2. Hydrofluoric acid dispersed ball-shaped cement remarkably, and can damage the adhesion of cement, producing crystal defect in cement which accelerated the disintegration of set cement. This study will play important roles in the preparation of cleansing fluid and in fast cleansing of set cement remained in containers and pipes.
Abstract: Acidification fluid formulation and acidification technology are studied for the best results in the acidification of thick highly inhomogeneous sandstones. It is concluded that for reservoir formations with high shale content and that are poorly cemented, the concentration of the prepad acids shall be reasonably higher (for instance, the concentration of HCl shall be increased to 15%), and the main acid (for acidification) HF shall have its concentration reduced to, for instance, 1%. Slabbed cores in combination with SEM can be used to determine the damaging depths, providing clues for the amount of acids to be used in acidification. For thick porous reservoirs, a combination of packer, perforation with variable intensities and diverting acids can be used in reservoir reformation. For reservoir formations with developed fractures, high flowrate, large amount of fluid and high pump pressure together can be used in eliminating deep plugging of the reservoir.
Abstract: Six types of drag reducers were studied for their solution viscosities and drag reducing effects at different concentrations and in pipeline flow. The study shows that the water solutions of these drag reducers have power law flow patterns, and the drag reducing ratios increases with the increase of the concentrations of these drag reducers, if the concentrations are in certain ranges. Viscosity of the solution and ion characteristics have no obvious effect on the drag reducing ratios of these drag reducers. At the same concentrations, drag reducers having molecular weight (MW) greater than 1000,000 have almost the same drag reducing ratios. The main factor affecting the drag reducing performance is the molecular structures of the reducers. Drag reducers with low MW and long molecular chains, those with branched and long molecular chains, and those with flexible, helical molecular structures have drag reducing performances that are much more stable. Long chain drag reducers with branched chains dissolve quickly in water and have good drag reducing performance in a wide range of Reynolds numbers. Drag reducers with low MW are easy to degrade and hence impose very slight damage to the reservoirs. These drag reducers are suitable for use in large scale shale reservoir fracturing with slippery water fracturing fluids.
Abstract: Liquid guar gum is developed for use in continuous mixing fracturing. Laboratory study shows that this liquid guar gum is cost effective and is less contaminant to the reservoirs in contact. The liquid guar gum has good dispersion capacity and is an instant polymer. The rate of addition of the liquid guar gum can be precisely controlled when mixing fracturing fluid. In the mixing process, the liquid guar gum can reach 80% of its viscosifying potential in just 5 min, and no “fish eyes” are found in the fluid mixed. This liquid guar gum has been successfully applied in the Well Su76-12-27X in Suligearea.
Abstract: A non-crosslinking vegetable gum fracturing fluid XG-1 was developed based on the concept that xanthan gum (XG) forms rod-shaped double helix polymer in water solution. The fracturing fluid treated with 0.5% XG-1 had apparent viscosity (AV) over 70 mPa·s, and over 40 mPa·s at 50-100 ℃ because the AV of the fracturing fluid decreased with temperature. When pH of the fracturing fluid was maintained between 2 and 12, the AV would be maintained at about 60 mPa·s. Fracturing fluids prepared with 20% KCl and 20% CaCl2 both had AV greater than 40 mPa·s, and both had good salt tolerance. When the AV of the fracturing fluids were greater than 40 mPa·s, settling velocity of the proppant would be greater than 0.014 mm/s, and the gel-broken fluid had viscosity greater than 5 mPa·s, with its surface tension similar to that of guar gum fracturing fluids. Fracturing fluid treated with 0.5% XG-1 had residue content of 90 mg/L after gel-breaking, far less than that of the guar gum fracturing fluids at the same viscosifier concentration. This fracturing fluid can be used in the fracturing operation of medium- to low-permeability reservoirs with few natural fractures.
Abstract: Welan gum is a high molecular weight water soluble exopolysaccharide produced through fermentation of carbohydrates by alcaligenes. Studies show that welan gum is soluble readily in water to form solution whose viscosity increases as the concentration of welan gum increases. The apparent viscosity of the welan solutiondecreases shear rate increases, and the shear stress, in the meantime, increases, showing a typical pseudo-plastic behavior. At low shear rate, the welan solution has high apparent viscosity. Guar gum solution retains its viscosity at neutral condition, and loses its viscosity in acidic or basic environment. Contrary to the guar gum, welan gum solution maintains most of its viscosity at pH range of 2-12. Moreover, welan gum has better temperature stability than guar gum. Unlike other polysaccharides, welan gum forms a network structure that is free from the effect of high valence ions. Welan gum will be a new ideal viscosifier for use in well fracturing.
Abstract: Conventional solid-liquid separators commonly used in China are not able to efficiently deal with high flow rates sandliquid mixtures with high sand content. A new spiral desander was recently developed to tackle this problem. The design of this new desander involved the establishment of a mathematical model based on the Bernoulli equation to characterize the structure of the desander, the analyses of the data of the model using MATLAB® software to determine the optimum structural parameters, the setup of a three-dimensional model based on the structural parameters, and the simulation of the flow field inside the desander using the simulation software, FLUENT®. Comparison of theoretical calculations and simulation results showed that there were very few differences between the two, proving the validity and feasibility of the design. Simulation of the flow field inside the desander verified the feasibility of separating solid-liquid using spiral desander, and provided a theoretical basis for manufacturing spiral desander.
Abstract: Large amount of fracturing fluids recovered during fracturing jobs in oilfields in northeast China imposed serious contamination to the environment and the cost spent in the purification of the fluids was high. A portable waste water disposal equipment was developed in an effort to reuse these fluids. A used clear fracturing fluid and a used guar gum fracturing fluid were disposed of with this equipment, and the produced fluids were analyzed with a laser particle size analyzer (Model: Master sizer 2000), showing that more than 99% of the particles in these fluids had been removed, while large amount of calcium and magnesium ions were found in the fluids after water analyses. Fracturing fluids used in the Well Bei201 had borate ions that were difficult to remove and reacted with HPG base fluid to form a viscous gel. The calcium and magnesium ions in the fracturing fluids caused the CMG to lose its function as a thickening agent. Based on these analyses, an optimum fracturing fluid formulation was developed using the reused disposed fracturing fluid:0.5%BCG-1+0.2%B-43+0.3%BCG-5+0.1%B-13+0.4%B-55, which was a non-crosslinking fracturing fluid. The new formulation had viscosity greater than 30 mPa·s after shearing 120 min at 120 ℃ and 170 s-1, settling speed of falling ball less than 0.324 mm/s, viscosity of the gel-broken fluids less than 5 mPa.s, and residue content of the gel-broken fluids less than 30 mg/L.
Abstract: Micro emulsion is a stable isotropic thermo-dynamic system spontaneously formed with oil, water and surfactants. Micro emulsion can remarkably reduce the interfacial tensions between solids and liquids, and has good solubility enhancement. Micro emulsion has found wide application in oil well cementing. This paper discusses the phase behavior of micro emulsion and studies the functioning mechanism of micro emulsion in oil dirt cleaning, providing a theoretical guideline for the field application of micro emulsion.
Abstract: The relief well, Wen23-6J, for the Well Wen23-6X is the first relief well drilled with the aid of SDI's magnetic range correction technology, and will greatly help in building a working gas storage of 3.9×108 m3 (active storage of 7.93×108 m3). The Well Wen23-6X is an accidental well drilled in 2005, with 2,300 m of fish left in it. Long time of contact of borehole wall with drilling fluid makes it difficult to (even with SDI's advanced technology) detect the well path with no fish in it when drilled to 2,588m. The newly drilled hole only met with the old hole at five depths during drilling. 73 m3 of cement slurry was injected in 8 times into the hole to the meeting points. To ensure an effective sealing of the hole, a fixed direction–fixed tool face orientation perforation technology was applied the first time after the cementing of the relief well. Ultra-fine cement slurries were squeezed into #34 and #29 sandstones. Negative pressure (37.84 MPa) testing shows that the plugging of the well is successful and gas storage can be built around the relief well.
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