Abstract: Formation damage of varying degree during oil and gas exploration and development generally results in reduced production rate or even kill a reservoir. Drilling fluid, as the first foreign fluid comes into contact with reservoir always causes greater formation damage. To mitigate or avoid formation damage caused by drilling fluid and enhance production rate of a single well, plenty of studies have been conducted by scholars at home and abroad for almost half a century. Three generations of drilling fluid technologies capable of protecting reservoir from being damaged have been established, they are "shielding and temporary plugging", "fine temporary plugging" and "temporary plugging with physio-chemical film". These technologies have greatly economically improved the protection done to reservoirs. The progresses made in reservoir protection, although great, still do not satisfy the pursuit of petroleum engineers of "ultra-low" formation damage, especially with great efforts made in developing nonconventional complex, ultra-deep and ultra-deep water reservoirs, the reservoir protection technologies previously prevailing are becoming unsatisfactory. To better protect reservoirs from being damaged, bionics has been introduced in the reservoir protection drilling fluid theory. The wide application of this new theory in large oilfields helps reach the goal of "ultra-low" formation damage, symbolizing the establishment of the fourthgeneration of reservoir protection drilling fluid technology. Theoretical basis, implementation program, laboratory evaluation and field application and advantages and disadvantages of the four generations of reservoir protection technologies are detailed in this paper, and the trend of development of reservoir protection drilling fluid technology is expounded in an effort to be of guiding significance to field technologists and scientific researchers in their work.
Abstract: In hydration process, water molecules adsorbed by clay particles in different hydration stages have different structures and properties. The adsorbed water includes free water and bound water, which have different ways of being attached onto clay particles. Researchers both at home and abroad have paid more attention to qualitative analysis of the type and amount of the bound water, the quantitative analysis of bound water and research on the effects of the type and amount of bound water on rock mechanics, on the other hand, provides a quantitative correction method for the establishment of force-chemistry coupling model. Assume that the sodium montmorillonite particles are in a shape of hexahedron, a power function model describing the relationship between the amount of bound water and the total adsorbed water of sodium montmorillonite can be established taking into account the micro characteristics of water adsorption. The type and amount of water adsorbed by sodium montmorillonite can be measured with thermogravimetry, airdrying of clay, adsorption in room temperature and isotherm adsorption. The experimental data are then fitted with data from model calculation. The results show that the product of the relative errors and the geometric mean of relative errors of the established model are both approximately equal to 1, indicating that the established model has good precision of prediction.
Abstract: A quinary copolymer filter loss reducer for use in high temperature and high salinity environment has been developed with AM, AMPS, DMDAAC, DMAM and SAS as monomers through water solution copolymerization using redox initiation system. The optimum synthesis conditions were determined laboratory experiment. The synthesized filter loss reducer was characterized with IR spectrometry and thermogravimetry, and was evaluated for its properties in water base drilling fluid. The experimental results show that the synthesized quinary copolymer is resistant to high temperature to 180℃, to salt contamination to saturation, and to calcium contamination to 1.25%. Fresh water base mud, saturated saltwater base mud and base mud containing 1.25% treated with 2% synthesized quinary copolymer had filtration rate of 6.4 mL, 15.6 mL and 7.2 mL, respectively after being aged for 16 hours at 180℃. Compared with similar additive Driscal, the synthesized quinary copolymer is more effective in resisting high temperature, salt contamination and calcium contamination. The filtration rates as mentioned above are only about 50% of the same base muds treated with 2%Driscal, respectively.
Abstract: The well Songke-2 is a high temperature deep scientific exploration well deployed in the Songliao Basin, its purpose is to penetrate the Cretaceous formations to obtain the records of basal continental deposit. The bottom hole temperature has been predicted to be over 220℃. Measures for preventing borehole wall collapse are especially important in drilling the fourth and fifth intervals since borehole wall collapse has occurred previously in drilling the interbedded mudstone and sandstone in the Shahezi formation, and the broken tuff, mudstone and coal seam in the Huoshiling formation, which were to be penetrated by the fourth and fifth intervals of the well. Continuous coring was to be conducted in the fourth and fifth intervals, and frequent tripping of drill string gave a big challenge to borehole wall stabilization because of long time contact of the open hole with drilling fluid. The adoption of different drilling techniques in turn gave a challenge to drilling fluid. A high temperature polymer drilling fluid has been formulated to deal with these challenges. The composition of the drilling fluid is as follows:1.0% bentonite + 2% attapulgite +0.2%KOH +(0.5%-1.0%) high MW filter loss reducer +1% moderate MW filter loss reducer + 2.5% filming agent + (2%-4%)SMC +2%FT +3%KCl + 2%NaCOOH +3% white oil. At the beginning of the fourth interval, the mud left over from the third interval was evaluated and converted for re-use in the fourth interval based on large amount of pilot tests. In the fifth interval, the property of the mud was greatly modified because of the needs for dealing with downhole troubles. When the downhole troubles were resolved, the mud property was gradually adjusted to a stable state. In field application the mud property was adjusted at all times in accordance with the requirements of drilling operations. The mud had good rheology at high temperatures and good high temperature stability. High temperature resistance of the mud formulation was 240℃ based on laboratory test. The mud property was still satisfactory even after hot rolling for 72℃, providing strong technical support for the success of drilling operation. The drilling fluid technology used in drilling the well Songke-2 is of guiding significance in improving job quality of drilling and reducing exploration cost.
Abstract: Three thinners, A, B and C have been synthesized to deal with extra viscosity of high temperature high density oil base drilling fluids. Thinner A, a condensation polymerized fatty acid, was obtained by copolymerizing one or more raw materials such as dodecahydroxyl stearic acid, polyhydroxy stearic acid, stearic acid, and the homopolymer of the product of dodecahydroxyl stearic acid and stearic acid with stearic acid. Thinner B was obtained by reacting the product of fatty acid or fat and polyamine at 100℃-200℃ with maleic acid and maleic acid anhydride at 80℃-150℃, and then dispersed the product with 40% oleyl alcohol, fatty acid or condensation polymerized fatty acid. Thinner C was a derivative from the reaction product of condensation polymerized fatty acid, alcohol amine and polyamine. The working mechanisms of these thinners are discussed in this paper. Added poor quality clay to contaminate or added barite to weight a high density (2.2 g/cm3) oil base mud to 2.4 g/cm3, then treated the weighted mud with three thinners to test their ability to reduce viscosity. It was found that the thinner A and the thinner C both were able to control the rheology of mud caused by the addition of poor quality clays within predetermined range, and the oil base mud can thus be reused for many more times, thereby reducing mud cost. The thinner B was able to reduce mud viscosity caused by the addition of barite, hence the pump pressure. The thinner B has thinning efficiency of 77%, and functions properly at 225℃.
Abstract: Well Antan-4X is a prospecting well for exploring the oil/gas reserves in the Yangshuiwu buried hill area in Huabei Oilfield. The depth of this well, 6455 m, has set a new record of well depth in Huabei Oilfield. The fourth interval of the well penetrated formations mainly with limestone and mudstone, and the down-hole temperatures are between 210-217℃, which poses rigorous requirement on the high temperature resistance of drilling fluid. Laboratory studies on the mud samples taken from well site have been conducted, and based on the studies 4 key mud additives have been selected to optimize the mud formulation, a low solids drilling fluid with temperature resistance up to 200-220℃. In field operations, the drilling fluid was maintained at its best state in accordance with bottom hole temperature, thereby to maximize the cost performance of the drilling fluid. During the entire drilling operations, the drilling fluid showed stable properties and good cuttings carrying performance, ensuring the safe drilling operations in the ultra-high temperature fourth interval.
Abstract: High temperature high pressure deep wells drilled in Yinggehai penetrated formations with narrow density windows. Conventional polymer sulfonate drilling fluids become highly viscous and difficult to flow in complex geological environment, and false thick mud cakes are generated. These generally result in resistance to drill pipe tripping, pipe sticking and lost circulation. A high performance water base drilling fluid has been formulated in laboratory with new high temperature polymers (Calovis HT and POROSEAL) replacing conventional polymers (PAC-LV, EMI1045 etc.). Laboratory evaluation shows that the high performance water base drilling fluid with density between 2.30 g/cm3-2.40 g/cm3 maintained its thermal stability for a long time at 200℃-220℃, was resistant to the contamination caused by 50 g/L drilled cuttings, 50 mL/L formation water and 5 g/L CO2, and performed well in reservoir protection, the return permeability reaches 84.6%. This high performance drilling fluid has been used on a well in Yinggehai with formation pressure coefficient of 2.20-2.40 and formation temperature between 190℃ and 200℃, which conventional polymer sulfonate drilling fluid has failed the drilling operation previously. This proved that the high performance water base drilling fluid had good high temperature stability and superior rheology. The successful application of the high performance drilling fluid has provided an reference for selecting drilling fluids for HTHP complex well drilling.
Abstract: A new high performance water base drilling fluid, XZ, has been developed for use in drilling the costly deep wells in the Junggar Basin. The formulation of the drilling fluid, based on "plugging, inhibiting, solidifying, duel repellent, and lubricating" principles, was conducted with several additives, such as a bionic inhibitive agent XZ-YZJ, a bionic plugging agent XZ-FDJ, a lubricant XZ-RHJ, a solidifying filming agent XZ-CMJ and a duel repellent agent XZ-SSJ etc. This drilling fluid has good rheology and is resistant to long-term aging and to contamination. After being aged for 3 d or being contaminated with 2% CaSO4 or 10% bentonite, the mud still maintains good rheology. Swelling test with the drilling fluid on Na-bentonite cores showed that the rate of swelling of the cores was reduced by more than 95%, and roller oven test with drilled cuttings from a well site showed that cuttings recovery was greater than 95%, indicating that the drilling fluid has satisfactory inhibitive capacity. Good plugging performance, lubricity, inhibitive capacity and low surface tension of the drilling fluid are beneficial to borehole stabilization, lubricity, pipe sticking prevention and reservoir protection, rendering the drilling fluid adaptability to the drilling of deep well and deep extended-reach well which are characteristic of more downhole troubles. Field application demonstrated that the new drilling fluid is able to help in reducing downhole troubles, minimizing rate of well enlargement, and reducing time needed for well construction. The application of this drilling fluid has satisfied the needs for safe, efficient and environmentally friendly drilling operations, indicating that the drilling fluid has a bright future in finding wide applications.
Abstract: Formate completion fluid is mainly used in Tarim Basin to drill high temperature deep wells with bottom hole temperature to 180℃. Successful drilling of these high temperature deep wells imposes rigorous requirements on the properties of completion fluid, such as thermal stability, viscosity, filtration rate, plugging capacity, settling stability and permeability recovery etc. Selection of appropriate formate completion fluid additives is essential for the completion fluid to have properties satisfying the needs aforementioned. This paper discusses the pattern of compatibility between completion fluid additives and formate water solution, providing a basis on which formate completion fluid additives can be screened and used. The composition of a high temperature high density clay-free formate completion fluid that can be used at 180℃ is also presented in this paper.
Abstract: Equivalent circulation density (ECD) at bottom hole is an important parameter affecting the safety of drilling operations. Accurate prediction of ECD is the prerequisite for safe drilling operations. Presently in China the prediction of ECD is often to calculate with traditional hydraulic models. Calculation of ECD with traditional hydraulic models gives results that roughly reflect the change pattern of ECD, but the precision of the model used and the fuzziness of input parameters for the model make it difficult to get accurate ECD; the calculated ECD is quite different with the actual ECD, and there exist uncertainties in the prediction of ECD. It is therefore necessary to perform uncertainty analysis on the predicted ECD on the bottom of the hole. Based on the comprehensive analyses of models for quantitative calculation of ECD, the sources from which the uncertainty of ECD is produced are discussed first in this paper, then a formula for ECD uncertainty calculation is derived on the basis of the Uncertainty Theory, and a case history of ECD uncertainty calculation is presented. The discussions made in this paper have presented a new clue for scientifically describing ECD, and provided a technical support of safe drilling operations.
Abstract: A thermal stable salt-resistant oil base mud cleansing fluid, PF-MOCLEAN, has been developed with a nonionic surfactant Brij A and an ionic surfactant SJB, in an effort to overcome the problems of narrow range of applicable temperature and of losing efficacy in high salinity environment when micro emulsion oil base mud cleansing fluid is used. Laboratory study has been done on the effects of the quantity ratio and concentrations of the two surfactants on the cleansing efficiency of PF-MOCLEAN, and the optimum composition of PF-MOCLEAN was determined, that is, SJB:Brij A=2:1, and the total concentration of the two surfactants is 60%. PF-MOCLEAN, when in contact with oil base muds, automatically solubilizes oil phases to form a micro emulsion with ultra-low surface tension, high solubilizing power and high rate of diffusion. It effectively cleans off 95% oil base muds adhered on the surfaces of casing and borehole wall in a temperature range of 40-120℃ and in high salinity environment, meanwhile turns the surfaces of casing and borehole wall from being hydrophobic to hydrophilic, which is beneficial to reservoir protection and well cementing job. PF-MOCLEAN has been effectively used in South China Sea, showing prosperous future of application.
Abstract: A stable nanophase wax emulsion has been developed using emulsion inversion point (EIP) method combined with emulsifierin-oil method, with Span 80 and Tween 80 as compound emulsifier and hydrophobically modified hydroxyethyl cellulose (HMHEC) as emulsion additive. The compound emulsifier has an HLB value of 10.5. The concentration of the compound emulsifier in the reaction raw materials was 11%, and the concentration of HMHEC 0.6%. The average particle size of the nanophase wax emulsion is 65 nm. The produced nanophase was emulsion had good stability, with 24 h rate of sedimentation of about 5%. Test on the compatibility of the nanophase wax emulsion with commonly used mud additives shows that apart from NH4-HPAN and XC, which will increase the particle sizes of the emulsion to over 100 nm, other commonly used mud additives are well compatible with the nanophase wax emulsion. Plugging test results show that the nanophase wax emulsion effectively plugs the pore spaces in shale mud cakes, with 92.95% of the pore spaces being plugged, a plugging efficiency that is better than that of inorganic nanophase plugging agents such as zinc oxide and calcium carbonate.
Abstract: Mud losses mainly took place in the upper part of the N1 and E32 formations in the Shi-202 well zone. The N1 formation is full of fractures and the E32 formation is a double-medium reservoir full of fractures and solution vugs. Low formation pressure bearing capacity, long open hole, multiple lose zones in the hole and coexistence of high pressure and low pressure in the same open hole section have made it difficult to deal with the mud losses. A flaky particle material, NTS, with high compressive strength and being able to roll over when going into mud loss channels, was introduced to drilling fluid to stop and control mud losses. Based on the rates of mud losses, three mud loss control slurries were formulated through laboratory experiment:1) active mud+1.0% NT-DS+(2%-3%) NTS (fine)+(1%-3%) walnut shell (0.1-1 mm)+(1%-3%) SDL+(1%-3%) SQD-98. The total concentration of these additives was 12%-13%. 2) base mud+2% NTS (fine)+3% walnut shell (1-3 mm)+(3%-4%) walnut shell (0.5-1 mm)+1%NT-DS+3% SDL+3% SQD-98. The total concentration of these additives was 15%-16%. 3) base mud+3% NTS (medium:fine=1:2)+(3%-5%) walnut shell (1-3 mm)+(3%-5%) walnut shell (0.5-1 mm)+(1%-2%) NT-DS+3% SDL+5% SQD-98. The total concentration of these additives was about 25%. Operational program for the use of these mud loss control slurries was also developed and tried on 4 wells in the Shi-202 well zone. Good results have been obtained using the mud loss control slurries and mud losses were 100% under control. Pressure bearing capacity of the targeted formation was enhanced, widening the safe drilling window of the formation. The success of the mud loss control has satisfied the requirements of subsequent operations.
Abstract: A salt-resistant, high temperature filter loss reducer TSM-1 has been developed through radical aqueous solution polymerization, with acrylamide (AM), acrylic acid (AA), 2-acrylamide-2-methyl propane sulfonic acid and a new cationic monomer (X) as raw materials. The synthesis process was optimized through orthogonal experiment. TSM-1 was characterized with IR spectrometry, NMR and thermogravimetric analysis, and the overall properties of cement slurries treated with TSM-1 were evaluated. Laboratory experimental results show that the molecules of TSM-1 have the characteristic functional groups of the four monomers, rendering TSM-1 good thermal stability. TSM-1 has weak retarding effects, meaning that it does not affect the strength of set cement. TSM-1 is compatible very well with retarding agents commonly used in oil well cement. The introduction of the functional cationic monomer into the molecules of TSM-1 renders TSM-1 a wide working temperature range; the highest temperature under which TSM-1 works properly is 200℃. With TSM-1, the filtration rate of cement slurry formulated with saturated saltwater can be controlled within 50 mL, satisfying the needs for well cementing. Chemical analysis and SEM analysis of TSM-1 indicate that the mechanisms under which TSM-1 functions are that the amphoteric ions are firmly adsorbed on the surface of cement particles through multipoint adsorption, thereby forming a layer of adsorption film. Under the filtration pressure, the adsorption film is pressed and fills into the spaces between cement particles. As such, the water loss channel is plugged and the permeability of mud cakes reduced, thereby reducing water loss of cement slurry.
Abstract: A cement slurry used to deal with difficulties cementing the exploratory well Songke-2 in main land China, has been formulated with a quadripolymer filter loss reducer and a terpolymer phosphonate retarding agent to improve its thermal stability and avoid the risks of "thermal thinning" of the cement slurry. The filter loss and thickening time of the cement slurry were controlled to satisfy the needs of cementing ultra-high temperature wells by adjusting the concentrations of the two additives. Meanwhile, based on particle sizing and the close-packing principle, the particle sizes and concentration of silica sand were optimized, adjusting the ratio of silicon over calcium closing to 1, thereby preventing the decaying of the late-stage strength of set cement at ultra-high temperatures. Furthermore, an elastic tough material developed with particles and fibers was used to enhance the elasticity and toughness of the cement slurry. By optimizing the ratio of these additives, a cement slurry able to tolerate 260℃ well temperature was designed. This cement slurry has good stability, density difference between the upper and the lower parts of the cement slurry less than 0.03 g/cm3, thickening time between 200 min and 420 min, filter loss less than 100 mL, 48 h compressive strength greater than 20 MPa, and 7 d compressive strength greater than 38 MPa. The late-stage strength of the set cement is not declining. By optimizing the liner hanging and cementing techniques, and strictly controlling cement slurry density, the integrity of the formations penetrated by the well was maintained, without being fractured during cementing operations. Using high temperature high efficiency flushing spacers, the displacing efficacy was increased, and job safety and cementing job quality were ensured. Well cementing has been performed successfully with high job quality on the Well Songke-2, whose static bottom hole temperature is 260℃, and circulating bottom hole temperature 210℃.
Abstract: The effects of the properties of expansive cement on wellbore integrity have been studied using finite element method based on elastic mechanics theory. The study shows that cement with appropriate rate of expansion will reduce the maximum Mises stress inside casing. The higher the rate of expansion of cement, the higher the maximum Mises stress in side cement sheath, and the lower the maximum circumferential stress. When pressure exists inside casing, the higher the elastic modulus of the expansive cement, the lower the maximum Mises stress inside casing, and the higher the maximum Mises stress inside cement sheath. At lower casing pressure, the higher the elastic modulus of cement, the lower the maximum circumferential stress inside cement sheath, contrary to the situation in which the casing pressure is higher. The effects of Poisson ratio on the maximum Mises stress inside casing are lower. The higher the Poisson ratio of cement, the lower the maximum Mises stress and the maximum circumferential stress inside cement sheath. Similar pattern of the effects of the properties of expansive cement on the integrity of wellbore is found for elastic formations and creep formations. Under the circumstance of changing casing pressure, the properties of expansive cement exert greater influences on the compressive failure and circumferential tensile failure of cement sheath. These conclusions suggest that, in selecting expansive cement, the properties of the expansive cement should be taken into account, based on the actual application requirements.
Abstract: Three key exploratory wells have been deployed in Huabei Oilfield to develop the buried hill reservoirs in Block Yangshuiwu in Langgu sag of Jizhong depression. The geologic conditions in the buried hill are complex. The formation pressure coefficient is 0.94-1.09. There exist multiple deep active oil and gas zones. Lost circulation has occurred frequently in this area. High geothermal gradient, slim hole, narrow annular clearance, long section of liner string to be cemented and rigorous requirements on the integrity of cement sheath. It is understood from these facts that cementing of the 127 mm liner string is highly risky, and operation safety and job quality of well cementing are difficult to guarantee. Efforts have made to deal with these difficulties:1) optimizing technology for borehole cleaning, using cyclone sub centralizer to ensure the success of casing running. 2) using computer software to simulate displacing efficiency and pressure changes at critical spots. Appropriately adjust operation parameters to ensure pressure control. 3) using tough cement slurry and flushing spacer system, designing appropriate operational parameters, ensuring the stability of cement slurry and the toughness of set cement that satisfies the requirements for SRV fracturing. Field operations on three wells show that the application of cementing technology remarkably improved the job quality of well cementing, providing technical support for well cementing in the buried hill in the Block Yangshuiwu in Huabei Oilfield.
Abstract: In large-scale SRV fracturing in shale gas development, flowback rate is generally 10% to 60%, resulting in a mass of water that is trapped in the reservoir. Using XRD analysis and IR spectrometry to study the swelling property of shales taken from Zhaotong, Changning and Weiyuan. Gravimetric analysis was used to characterize the water absorption mechanisms and pore generation by dissolution. These methods reveal the state of existence of different working fluids in shales. The experimental results show that the clay contents of the shale samples are 18%-20%, mainly chlorite, illite and some illite/smectite mixed layer. The shale samples were soaked with distilled water, slick water, water solution of cleanup additive and water solution of swelling inhibitor for 1 d, 3 d, 5 d and 7 d. There is no obvious change at 1 nm on the XRD graph. IR spectrometry shows that there is no absorption peak for interlayer water. The volume of absorbed water and rate of absorption are proportional to particle size and size of pore throat. Percent of matters dissolved out of shale samples through ultrasonic soaking is about 0.6%, mainly KCl and NaCl, with minor amount of CaCl2. Specific surface area measured with BET method shows that pore generation is not obvious. A core with particle size of 0.154 mm was soaked in fresh water, and the sizes of pore throat were decreasing with time. The amount of water absorbed by the core was 2.37%-2.85% at saturation, equivalent to the volume of pores of the core. Using the width and height of the peak at 1 nm on the XRD graph as indicators, and ratio of interlayer water peak value over Si-O peak value on IR spectrometry graph as verification, a method for the evaluation of clay swelling property is established. Evaluation of cores taken from south Sichuan shows that the soaking of shale in working fluid does not cause clays to swell. Shales taken from south Sichuan have lower contents of soluble salts, hence the pore generation by the working fluids is not obvious. The working fluids can enter into the nanometer-sized micro pores in time is enough. The working fluid will occupy the micro pores, but will not enter into the spaces between crystal layers of clay, and will not cause the permeability of formations to be impaired by swelling.
Abstract: A non-acid block removing fluid has been developed to deal with several problems encountered in the development of unconsolidated sandstone reservoirs in Bohai oilfield. The problems include failure of rock matrices in conventional acidizing job, secondary precipitation caused by residue acids that are unable to timely flow back because of the limits from configuration of pipe string and workover jobs, and flowback fluids with high electric conductivity that cannot be directly disposed of. All these problems pose serious restrictions on reservoir acidizing operations. The newly developed non-acid block removing fluid is also able to protect the reservoir from being damaged. The residue of this non-acid block removing fluid has lower electric conductivity. The non-acid block removing fluid, containing 20% compound polycarboxylic chelating agent A and 5% fluorine complex C, can slowly release H+ and F-, and maintain its pH value between 6 and 7, showing high retarding property and capability of protecting rock matrices. By chelating metallic ions, scales are prohibited and secondary precipitation is minimized. The non-acid block removing fluid has low corrosivity, and the flowback fluid has low ionic concentrations and electric conductivity, which are beneficial to the on-the-spot and efficient disposal of the flowback residue acid in the platform process. This non-acid block removing fluid has been tried out in Bohai oilfield with remarkable efficiency, showing good application prospect.
Abstract: Slick water fracturing fluids presently in use have some shortages, such as incompatible with the flowback water and severe damage to reservoirs etc. Based on the characteristics of the Longmaxi shales of the Lower Silurian system in the south of the Sichuan Basin and field operational requirements, a clear slick water fracturing fluid has been developed for use in Block Changning. Laboratory evaluation of the slick water fracturing fluid shows that the main additive, JHFR-2, in the fracturing fluid has good drag reducing performance. Slick water formulated with the flowback water and JHFR-2 has drag reducing efficiency of 70%, and it only takes 30 s or shorter time for JHFR-2 to dissolve. The optimum treatment of JHFR-2 is 0.07%-0.10%. Percent permeability recovery of cores flowed with the formulated slick water is 91.9%. The clear slick water fracturing fluid is non-toxic and easy to flow back. Application of the clear slick water fracturing fluid on well H26-4 and well H26-5 proved that the fracturing fluid had good drag reducing performance. Continuous mixing of the slick water fracturing fluid for direct use completely satisfied the needs of long time fracturing of shale gas wells which consumed large volume of fluid and large amount of sands. The easily formulated low cost clear slick water fracturing fluid is believed to have good application prospect.
Abstract: To improve the thermal stability of thickening agent used in fracturing fluid, a new modified hydroxypropyl guar gum (HPG) thickening agent has been synthesized with hydroxypropyl guar gum, 2-pyrrolidone and (2-chloroethyl) trimethyl ammonium chloride. The ability of the thickening agent to resist high temperature was evaluated with TGA, and laboratory study was conducted on the conditions for the thickening agent to crosslink, as well as thermal stability, shearing resistance, gel breaking performance, residue content and core damage of the fracturing fluid formulated with the newly developed thickening agent. It was demonstrated that by introducing a rigid group into the molecular structure, the thermal degradation temperature of HPG was increased to 220℃, and the modified HPG had good thickening performance at a concentration of 0.6% in the fracturing fluid. The optimized formulation of the fracturing fluid is as follows:0.6% modified HPG + 0.5% high temperature swelling inhibitor BZGCY-C-FP + 0.5% high temperature clean-up additive BZGCY-C-ZP + 0.1% high temperature stabilizer BZGCY-Y-WD + 0.2% sodium carbonate + fresh water + organic boron-zirconium crosslinking agent (crosslinking ratio=100︰0.4). After sheared at 200℃ and 170 s-1 for 120 min, the viscosity of the formulation was still higher than 60 mPa·s, indicating that the thermal stability of the fracturing fluid is improved. Field application showed that the new fracturing fluid has satisfied the needs for high temperature operation.
Abstract: During drilling process, water phase invades into reservoirs through capillary force and positive differential pressure, causing water phase trapping in tight sandstone gas reservoirs, and resulting in wrong logging data explanation of pay zones to water zones, hindering timely discovering and accurately appraising of tight sandstone gas reservoirs. To understand the self-imbibition behavior of water phase in tight sandstone gas reservoir, plug cores from a typical tight sandstone gas reservoir were used to simulate selfimbibition by end contact of plug core with water when water comes into contact with reservoir rocks at the moment when the reservoir is first drilled, self-imbibition by soaking of rocks when fractures are flooded with water, and forced imbibition by capillary force under the action of positive differential pressure. The influences of contact area and differential pressure on capillary self-imbibition of water to tight sandstone are analyzed. The simulation test results show that imbibition rate is affected by imbibition area and the development of fracture. The more developed the fractures and the greater the contact area, the higher the imbibition rate, and the imbibition process is easier to reach equilibrium. Positive differential pressure accelerates capillary imbibition in rocks whose physical properties in turn affect the imbibition process. When the physical properties of rocks are low to a certain extent, the imbibition behavior is mainly affected by capillary force. For the dense part of a tight gas reservoir matrix, positive differential pressure has minor effect on imbibition. When fractures are developed in the dense part of the tight gas reservoir matrix, the contact area for flow is increased, and a high positive differential pressure enhances the imbibition rate. It is thus concluded that water invasion into tight sandstone reservoirs during drilling and completion can be prevented mainly by plugging fractures and by controlling differential pressure to minimize water-rock contact and the amount of water entering into reservoir rocks.
Abstract: In laboratory studies, solubilizing agent was used to increase the solubility of commonly used inorganic salts such as CaCl2 and ZnCl2 to formulate a new cost-efficient high density solid-free clear saltwater completion fluid. The addition of inorganic salts in a completion fluid increases the density of the fluid while not increasing its solids content. Two solubilizing agents were selected through laboratory experiments, which performed best in a solution containing 2%LAS-30+2%SLF-4. A clear saltwater completion fluid prepared with the said solution can have density of 1.926 g/cm3 with compounded inorganic salts. At this density, the concentration of CaCl2 is 160 g/100 mL water, and the concentration of ZnCl2 is 98 g/100 mL water. The new completion fluid has apparent viscosity of 33 mPa s, temperature tolerance of 140℃, and recovery of damaged permeability as high as 96%. This completion fluid performed very well in reservoir protection.
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