Abstract: High temperature thermal decomposition and chemical extraction are commonly used in the innocent treatment of oilbearing wastes in operation areas. These treatments require the construction of a plant for the centralized processing of the wastes and gigantic equipment with high energy consumption is required. In collecting the wastes, environmental risks have to be considered. Nano emulsion at normal temperatures can rapidly separate oil from oil-bearing wastes, providing a good base for the "treatment while producing" of oil-bearing wastes. In laboratory study, a mixture of a surfactant, a secondary surfactant and water in different rations was further mixed with n-octane in a ratio between 1:9 and 5:5. The final mixture was agitated with supersonic wave at frequencies between 10-100 Hz to obtain a Winsor IV type single phase nano emulsion NR-A. The particle size, D90, of the NR-A emulsion measured on a laser particle size analyzer was 11 nm, and the interfacial tension between oil and water, as measured with the DuNouy method, was only 1.35 mN/m. The Zeta potential of the emulsion system was greater than 50 mV, indicating that the system was a thermodynamic dispersion. Adding the NR-A into oil-bearing wastes, the oil phase of the wastes can be desorbed from the solids under low energy consumption through fast mass transfer and ultra-low interfacial tension. Laboratory evaluation showed that when 0.5% NA-R was mixed with oil-bearing wastes from shale gas drilling, after agitation at room temperature for 20 min, 95.7% of the oil-on-waste was desorbed from the wastes. The desorbed oil can be used as the base oil for mixing oil base drilling fluids, realizing the efficient treatment and recycling of oil-bearing wastes.
Abstract: Mass polymerization and solution polymerization were used to prepare styrene-maleic anhydride (SMA) with styrene (St) and maleic anhydride (MA). The two SMAs made were then sulfonated to sulfonated styrene-maleic anhydride (SSMA). SSMAs made from the two methods were evaluated for their abilities in drilling fluids to reduce viscosity and to resist the effects of high temperature and salt contamination. It was found that the two SSMAs made both can effectively tear apart the spatial networking structure formed by the clay particles in the drilling fluid. In saltwater muds and at high temperatures, the two SSMAs performed differently in viscosity reduction. First, in fresh water base drilling fluids, the two SSMAs both can reduce mud viscosity efficiently. At a concentration of 0.75%, the SSMA made through mass polymerization can reduce the viscosity by 95.38%, while the SSMA made through solution polymerization can reduce the viscosity by 85.54%. Second, in saltwater drilling fluids, the SSMA made through mass polymerization had better viscosity reduction ability and better salt resistance. At a concentration of 1%, the viscosity of saltwater drilling fluids can be reduced by 53.33% by the SSAM made through mass polymerization. Third, in aging experiments at elevated temperatures, the viscosity reducing performance of the SSMA made through mass polymerization was less affected by temperature than that of the SSMA made through solution polymerization. After aging at 230℃, the rate of viscosity reduction (by the SSMA made through mass polymerization) was still maintained at 40% or higher. Fourth, in high density drilling fluids, SSAM made through mass polymerization had higher rate of viscosity reduction. After aging at 220℃, the rate of viscosity reduction was still maintained at 60% or higher, higher than the rate of viscosity reduction of SSMA made through solution polymerization, which was 47.45% in high density drilling fluids.
Abstract: Well Shunbei-3 is an exploration well located on the north rim of the Shuntuoguole low uplift in Tarim Basin, Xinjiang. This well penetrated the Permian system igneous rocks which have developed fractures, poor cementation, easy-to-break zones and low pressure bearing capacity. Six times of lost circulation during drilling were dealt with bridging agent lost circulation material (LCM) and cement slurry, and the results were unsatisfactory because of low success rate of the first try in lost circulation control. To resolve the lost circulation problem taking place in the low pressure bearing capacity formation of the Permian system, a chemical gel LCM, HND-1, was developed with several nanophase LCMs. Analyses of the mechanisms of HMD-1 indicated that HND-1 had the ability of controlling lost circulation through "synergism" of multiple LCMs, and it can substantially enhance the pressure bearing capacity of formation. Laboratory evaluation demonstrated that chemical gel LCM slurry formulated with HND-1 had thickening time adjustable between 4 h and 20 h, and the compressive strength of the LCM slurry after 24 h was 12 MPa or higher. The HND-1 LCM slurry had density adjustable between 0.8 g/cm3 and 2.25 g/cm3, and was compatible with other drilling fluid additives. The HND-1 LCM slurry was tried in the controlling of lost circulation occurred in the Permian system penetrated by the well Shunbei-3, and good results were obtained. The thief zones were pressurized at 5 MPa, with pressure drop of only 0.2 MPa in 30 min. The equivalent density of the Permian system reached 1.55 g/cm3, satisfying the density requirement for drilling in the Permian system.
Abstract: A temporary plugging agent SMHHP has been developed to satisfy the needs of temporary plugging in ultra-high temperature reservoirs. SMHHP is composed of particle material, fiber material, elastic material and nanophase material which are in reasonable ratios. The sizing and selection of particles was based on ideal packing theory. A high temperature highly acid soluble fiber was introduced into SMHHP to improve the stability of the plugged formations. Considering the poor adaptability of particle sizes to the sizes of pores to be plugged because of the irregularity of particles during processing, a high temperature elastic material was added into SMHHP. Tiny pores formed in bridging can be further precisely packed with nanophase material, thereby improvingthe compactability of plugged formations. SMHHP only slightly affect mud rheology, and has high temperature resistance, strong sealing ability, goodtemporary plugging effect and high acid solubility. SMHHP functioned normally at 200℃. Test performed with SMHHP slurry on 0.2 mm fractures showed that pressure bearing capacity of more than 7 MPa can be achieved. Filtration depth of SMHHP slurry on sand bed with 0.28-0.90 mm sand particles was less than 3 cm. Percent permeability recovery of cores contaminated with SMHHP slurry was greater than 93.9%. Acid solubility of SMHHP was greater than 82.1%. SMHHP can be used in reservoirs of ultrahigh temperatures, protecting the reservoirs from being damaged.
Abstract: The size distribution of pores in shale formations in Nanpu oilfield is in a level of micrometers or even nanometers. Conventional micrometer-sized solid particulate plugging agents used in water base drilling fluids are unable to effectively plug these pores. Laboratory experiments have been conducted with several nanometer-sized particulate plugging agents, such as FT-3000, HLFD-1 and Green Seal, to ascertain the effects of type and concentration of these plugging agents on HTHP filter loss, filtration through sand disc, pressure bearing capacity of mud cakes, and their performance in plugging nanometer-sized pores. Experiments have also been done on core samples taken from Nanpu oilfield to test the changes in core permeability before and after plugging of cores, pressure transfer and membrane efficiency. The experimental results showed that Green Seal had HTHP filter loss of 17 mL and filter loss through sand disc of 13.8 mL, the minimum values among the three plugging agents. With Green Seal, the pressure bearing capacity of mud cakes was increased to 8 MPa or even higher. Analyses of permeability of the cores before and after plugging experiments indicated that Green Seal had the best efficiency in pore plugging, effectively inhibiting pressure transfer. Membrane efficiency of Green Seal was 0.0990, the highest value among the three plugging agents. These experiments have proved that Green Seal, an environmentally friendly deformable plugging agent, is the best plugging agent evaluated. Green Seal has been applied on the well Nanpu36-3652 and the well Nanpu36-3701. The borehole wall was stable, and gauge holes were obtained. Recovery of permeability was high and filtrate invasion was low, realizing the multiple goals of stabilizing shale borehole and protecting reservoir formations from damaging.
Abstract: Palm oil has the advantages of good biodegradability, low cost and being environmentally friendly. It can be used as the base fluid of oil base drilling fluid. Palm oil has different components and molecular structures than those of diesel oil and white oil, and filter loss reducers presently available for use in conventional oil base drilling fluids cannot be used in palm oil base drilling fluid, and it is thus necessary to develop filter loss reducers special for use in palm oil base drilling fluid. Dry method, wet method and chloroformylation reaction were used to prepare and optimize filter loss reducers for palm oil base drilling fluid. Evaluation of the performance of the optimized filter loss reducer indicated that a filter loss reducer FLA made from SAA-6 (an organic modifying agent) and sodium humate through ionic adsorption reaction (wet method) had the best performance. FLA had colloidal coefficient of 92% in palm oil drilling fluid, and the optimum reaction conditions for the production of FLA was 95℃, 2 h of reaction time, and ratio of sodium humate to SAA-6 of 5.5. A palm oil drilling fluid treated with 5% FLA had API filtration rate of less than 4 mL and yield point of about 8 Pa, demonstrating good filtration behavior. The FLA treated palm oil drilling fluid had good thermal stability; it functioned properly at 150℃, and had HTHP filter loss of less than 9 mL. Laboratory experiments showed that this drilling fluid had inhibitive capacity, lubricity, contamination resistance, reservoir protective capacity and bio-toxicity that all satisfied the needs of drilling operations. This study provides an experimental base for the application of palm oil in drilling fluids.
Abstract: Dual-effect drilling fluids with weak gel and micro solids have been developed to better satisfy the needs of borehole wall protection in coal bed methane (CBM) drilling, to minimize the damage to CBM pay zones by drilling fluid, and to realize safe and efficient drilling operations. Laboratory evaluation of the drilling fluids showed that they had excellent basic properties, good inhibitive capacity, temperature resistance (50℃), salt resistance (NaCl, CaCl2, MaCl2) and drilled cutting (coal) tolerance. A 500 mL weak-gel drilling fluid sample and a micro-solid drilling fluid sample treated respectively with 0.1 g cellulose, 0.1 g neutralized α-amylase and 0.1 g compound enzyme had rates of degradation of the two drilling fluid sample were 90.9% and 83.0%, respectively. The weak-gel drilling fluid and the micro-solid drilling fluid had friction coefficient of 0.17 and 0.12, respectively, and percent permeability recovery of 91.3% and 82.3%, respectively, exhibiting good lubricity and reservoir protection capacity. Observation under microscopy showed that contact angles of the two drilling fluids were increased, capable of protecting formations from being damaged by water block. The compound bio-enzyme used in the drilling fluids not only reduced the apparent viscosity of the drilling fluids, it also helped degrade mud cakes, thereby minimizing blocking of fractures in CBM zones, greatly mitigating the negative effects of mud cakes on CBM production.
Abstract: A vacuum saturation method has been worked out to evaluate permeability impairment by water block of cores (with initial water saturation).This method is established to replace traditional methods which are not suitable for the evaluation of permeability impairment by water block of cores taken from tight gas reservoirs. Laboratorystudies of a polymer sulfonate drilling fluid have been done on cores taken from Tarim Basin with the method developed. Permeability impairment of cores by water block before and after mud contamination was measured with gas flowing through the cores. The new method, giving a result that better tallies with the reality of a gas reservoir, can be used to make a comparison between the gas permeability of a core with initial water saturation and the gas permeability of the same core with bound water saturation.A procedure of setting lower initial water saturation of tight gas reservoir was established for the method. Further experiments have been done to study the effects of time for vacuum saturation, time for backflow after gas flooding and flowrate of gas flooding etc. on the vacuum saturation method. Permeability impairment of tight cores by polymer sulfonate drilling fluids used in Tarim Basin tested with the method developed is between 54.83% and 72.73%.
Abstract: Well Nuo-1, 5 000 m in depth, is a key exploratory well located in the east of the northern margin (Quanji anticline, Huobuxun sag, Sanhu depression) of the Qaidam Basin. Formations penetrated by the well included strongly water-sensitive mudstones and frequent interbeds of sandstones and mudstones. Faults are developed in the area and formation saltwater renders contamination to the drilling fluids used. Difficulties in drilling fluid operation existed because of the problems and no offset well data were available for reference. An amine-based silanol highly inhibitive plugging drilling fluid was selected to inhibit the hydration and swelling of shale, and techniques for drilling fluid maintenance were optimized to inhibit the hydration and swelling of mudstone and shale formations, thereby to stabilize the borehole wall. The drilling of Well Nuo-1 was successful, providing a technical support for subsequent drilling operation in the same area. When drilled to the designed depth of each interval and the completion depth of the well, viscous mud was spotted at the bottom of the well to guarantee the success of casing running and well cementing. 10 times of well logging were all conducted successfully and casing strings were run to the bottom with no hindrance. Average percent hole enlargement of the φ444.5 mm was 7.46%, the φ311.2 mm was 9.33%, and the φ215.9 mm was 9.40%. Although pipe sticking had occurred drilling, these data indicate that the quality of the whole well is satisfactory, especially when the exploratory well was first drilled in an area that had never been explored. Average ROP of the well was 7.54 m/h, realizing the objective of "high quality fast drilling".
Abstract: Conventional compound lost circulation materials (LCMs) have no cementation among their particles. When these LCMs are put into the hole to stop mud losses, they are quite easy to be eroded away by the flow of drilling fluid. Cement slurry is another LCM frequently used to deal with severe mud losses, with a shortage of being easy to make new "hole" in a hole that uses cement slurry to stop mud losses. A Laboratory study has been conducted on drillable cement LCM. In this study, ultra-fine calcium carbonate was added into sulphoaluminate cement, a new gel material with adjustable drillability. It was found that when the concentration of ultrafine calcium carbonate in the cement slurry was not greater than 7%, the strength of the cement slurry was increasing with increase in the concentration of ultra-fine calcium carbonate. When the concentration of calcium carbonate was greater than 7%, the strength of the cement slurry was decreasing with increase in the concentration of ultra-fine calcium carbonate, i.e., the drillability of the cement was getting better. A sulphoaluminate cement treated with 0.4% water reducer, 0.3% viscosifier and 0.6% retarder had thickening time of 155 min, satisfying the needs of safe operation. A new lost circulation material was thus formulated by adding 12% scaly mica, 1% fiber and 1.5% limestone powders. This lost circulation material can be used to plug slots of 3 mm and 5 mm width, respectively. This drillable cement has provided a technical support for borehole wall strengthening and lost circulation control in drilling operations.
Abstract: A new reticulated foam was developed to deal with lost circulation. Laboratory study was conducted on the reticulated foam to examine its ability to control lost circulation in fractured formations with bridging method. A high performance lost circulation control slurry was developed through engineered concentrations of different lost circulation materials (LCMs), comparison between the reticulated foam and screen-type LCMs and compounding of the reticulated foam and screen-type LCMs. This LCM slurry was tried in a well drilled in the piedmont area in Kuche, Tarim, with a high density oil base drilling fluid. It was found that this LCM slurry had the ability of plugging long fractures, and was able to effectively increase the pressure bearing capacity of thief zones and to reduce the total amount of mud lost. The reticulated foam is deformable under pressure, suitable for plugging fractures of different shapes and sizes. Drilling fluid flowing within the foam was experiencing high flow resistance, and large amount of reticulated foam particles distributed inside the fractures formed multiple partitions of lower strengths to hinder the flow of mud, thereby buffering the pressure exerted on the end partition. The reticulated foam particles, along with rigid particles, can also effectively bridge the narrow parts of fractures to hinder mud flow in fractures. The reticulated foam becomes weak in oil base drilling fluids and at high temperatures; it therefore is suitable for use in water base drilling fluids and at low temperatures. The reticulated foam, with its raw materials readily available, is quite cost effective and is expected to find wide application in lost circulation control.
Abstract: Carbonate reservoirs in the Block Abu, Missan Oilfield (Iraq) are full of fractures and vugs and are of low formation pressure. Mud losses have been the main problem encountered in drilling operations. Based on the summary of previous mud loss control techniques, an acid soluble compound lost circulation material (LCM) formulation was optimized under the help of logging data and electric imaging logging data. The acid dissolution rate of the optimized compound LCM was increased to above 75%. In laboratory simulation test, the pressure bearing capacity of the optimized compound LCM was increased to 7 MPa. Techniques of using the LCM were also optimized. This compound LCM was used on 5 wells in the Block Abu, and the success rate of mud loss control was evidently increased, further cutting down drilling time.
Abstract: As petroleum production is moving forward to the production of heavy oil and oils from ultra-deep wells, conventional oil well cement expansion agents, such as CaO and ettringite are no longer able to satisfy the needs of well cementing because of their deficiency in high temperature performance. Oil well cement expansion agents with MgO as the main component, is expected to find wide application in oil well cementing. This paper listed the research findings made abroad in the application of MgO in oil well cement. From these researches it was found that there must be a matching between the calcination temperature of MgO and the operation temperature. High concentration (12%) of MgO can be used to optimize the pore sizes of set cement with 3D constrained state at 80℃ and to enhance the compressive strength of the set cement. At concentrations between 5%-10%, MgO would reduce the compressive strength of sand-contained set cement at 135℃-150℃. The existence of MgO in set cement helps improve the bonding between the interfaces between cement sheath and borehole wall because of the radial expansion of the set cement caused by MgO. The quality of sealing of the annular space is thus improved and interfaces between cement sheath and borehole wall in which mud cakes of poor quality also has its strength enhanced. This paper is of guidance in the study, application and popularization of high temperature compound anti-channeling agents with MgO as the main component.
Abstract: Wells in northwest Sichuan are being drilled deeper and deeper. In west Sichuan, exploration activity has extended to the depths of the lower Permian Series and the Cambrian System. In the west of Sichuan cementing of complex ultra-deep wells has to be faced with multi pressure systems along the wellbore, and narrow drilling windows. Using conventional liner cementing techniques, the ultra-deep wells are unable to be cemented effectively. To address the problems in liner cementing, i.e., the coexistence of blowout and lost circulation in ultra-deep wells, well cementing under dynamically balanced pressure was practiced in wells penetrating pressure sensitive formations, and a set of techniques, including annular pressure control when cementing a well with narrow safe drilling windows and anti-channeling cement slurries. The techniques have first been successfully applied in cementing the φ114.3 mm liner in the well LG70 under managed pressure, ensuring the job quality of cementing a well with small annular clearance, high temperature and coexistence of blowout and lost circulation. These techniques have also been successfully used on many other wells, providing a whole new technology for the prevention of channeling and lost circulation in cementing wells with narrow safe drilling windows.
Abstract: In well cementing operations, cement slurriesflowing along the hole and the drilling fluid in place are experiencing different temperatures at different well depths. In deep wells, rheology of borehole fluids is more remarkably affected by temperature. Based on the analyses of HTHP rheological data obtained, a model for calculating the changing pattern of rheological data at different temperatures was developed. Raw data for the model can be acquired by measuring the rheological data of fluids at different temperatures. A method of calculating the effects of temperature on rheology in deep well cementing was developed based on the model. Error analysis of rheological data acquired from rheology measurement indicates that errors associated with the calculation method are acceptable, and the calculation method is hence applicable.
Abstract: The P.D.M Oilfield, located in Venezuela, is an oilfield of light crude with associated natural gas put into production in 1980. Geologic conditions in this oilfield are very complex. Wells with five intervals were designed for the development of the oilfield. Oil base drilling fluid was used to drill the fifth interval. The ϕ165.1 mm borehole section was cased with ϕ139.7 mm liners to about 5 200 m to seal off the coarse sandstone reservoir in Merecure formation (Oligocene series). After long time of development, the P.D.M oilfield is approaching depletion, daily production rate of a single well is less than 60 m3. Reservoir depletion has resulted in formation pressure depletion and hence lost circulation during drilling, and risks in well cementing. In well cementing operations, multi-function compound prepad fluids had to be used. Furthermore, H2S existed in the associated natural gas. To deal with these problems, low density cement slurry was used to reduce the pressure in annulus exerted by fluid column, thereby to minimize the risks of lost circulation. High performance cement slurry with high toughness was selected for well cementing. The cement slurry had low filter loss, good mobility, transit time of gel strength less than 25 min, and the ability to minimize gas channeling in annular space. With the optimized cement slurry and operational techniques, liners in wells with low pressure, high seepage rates and narrow annular clearance have been successfully cemented.
Abstract: The Kuche piedmont structure in Tarim Basin is abundant in oil and gas which, unfortunately, are buried at depth of about 7 000 m. Oil base muds can be used to overcome the drilling challenges such as salt and gypsum contamination, borehole instability through mudstone and shale formations. On the other hand, oil base muds negatively affect the bonding between set cement and borehole wall, and the bonding between set cement and casing string. To minimize these negative effects, researches were conducted based on the data from drilled wells to systematically analyze the main factors affecting well cementing job quality from several aspects, i.e., wettability reversion on liquid-solid interface, flow rate to increase displacement efficiency while avoiding lost circulation, compatibility between drilling fluid in hole and cement slurry, as well as the placement of centralizers along casing string. The research work showed that percentage of surfactants/water in spacer fluid above 30% makes the interfaces (cement sheath-casing string and cement sheathborehole wall) water wet. Flow rates enough to realize plug flow while lost circulation is avoided help increase displacement efficiency. One centralize every two singles of casing ensures that casing centricity is greater than 67%. It can be concluded that poor cementing job quality in some wells is resulted from poor casing centricity and poor compatibility of cement slurry with drilling fluid in hole. This study provides a feasible and reliable method and basis for the enhancement of well cementing job quality in the piedmont structure.
Abstract: A cementing slurry treated with light weight plastic beads has been developed to improve well cementing job quality of the gravel-packing section of a well in Jingnan block, Sulige gas field. Lost circulation has been frequently encountered in this area, hence different lost circulation materials (LCMs) were studied for their effects on the properties of the cementing slurry developed. Three LCMs, a plant particle (A), a mixed fiber QD-2 and a compound fiber DF-NIN, were studied through orthogonal experiment. It has been found that when the three LCMs were added into cement slurries in concentrations of 2%, 2% and 3% respectively, best performance of lost circulation control can be obtained, and the cement slurry had compressive strength of 7.6 MPa. In laboratory lost circulation test, the volume of slurry lost was greatly reduced, and the basic properties of the cement slurry were able to satisfy the needs of well cementing. A set of well cementing techniques were established based on the investigation of the geological characteristics of the formations. The cement slurry and the techniques developed have been applied in Jingnan area for 8 times, the percent of pass of cementing between cement sheath and casing string was 95%, and this number was 99% for the cementing between cement sheath and borehole wall, demonstrating that the light weight lost circulation control cement slurry is able to greatly improve the quality of cementing job in the gravel-packing section of a well, and satisfy the needs at utmost of sealing a whole well.
Abstract: Re-fracturing of an oil well is one of the important methods of restoring its production capacity and enhancing its ultimate recovery. The most effective re-fracturing method presently in use is to fracture the reservoir formations with fracturing fluid containing temporary plugging agent functioned as diverting agent. An environmentally friendly water soluble temporary plugging diverting agent has recently been developed with biodegradable materials, high molecular weight polymers, an expansion agent and a solidifying agent. The particle sizes of this temporary plugging agent can be customized to fit for the width of fractures into which the particles will go in. The temporary plugging agent dissolved 4 hours after the fracturing operations. Laboratory experiments on cores indicated that 99% of the pores in the cores can be plugged by this plugging agent, with pressure bearing capacity of at least 40 MPa. The dissolved plugging agent had only minor impairment to the permeability of cores, meaning that the temporary plugging agent had satisfied the needs of fracturing job. On field trial on a well, after adding the temporary plugging agent, operating pressure went up to 3 MPa, proving that the temporary plugging agent functioned very well. Daily oil production rate of the fractured well was increased by 1.1 t, and water cut of the well was reduced by 5%, indicating that the use of this fracturing method has realized the goal of restoring production capacity and reducing water cut.
Abstract: Sand carrying in CO2 fracturing fluid has been a problem because of the low viscosity of liquid CO2 which always results in poor fracturedevelopment in fractured formations. One of the key factors in the successful use of CO2 in reservoir fracturing is to increase the viscosity of CO2 used. According to the working mechanisms of Lewis acids and Lewis bases, an olein with Lewis base characteristics was chosen to mix with cyclohexane and chloroform in a ratio of (2.6-4.3) (1.0-2.3) (1.6-2.6) to form a liquid fluorine-free amphiphilic fatty compound, ZNJ, a viscosifier used to enhance the viscosity of CO2. At 20-25℃ and 18-20 MPa, liquid CO2 treated with 7% (vol.%) ZNJ had viscosity of 8.82 mPa·s, as measured on an MARS Ⅱ rheometer. At 10-20 MPa (controlled with a hand pump), 7-18℃, and shearing rate of 170 s-1, percent change in the viscosity of CO2 did not exceed 13%. The viscosifier has been used on 5 wells for 6 times. In the field applications, the concentration of ZNJ was 3%, the proppant used was haydite of 40-70 mesh, the maximum sand volume added in the fracturing fluid for a single fracturing zone was 10 m3, and the average ratio of sand to liquid was 6.1%. The fracturing job was smoothly performed, and the orientation of the fractures developed in the formations was in agreement with the orientation monitored in conventional fracturing jobs. It is concluded that liquid CO2 can be viscosified with olein, cyclohexane and chloroform.
Abstract: A high efficiency oil displacing fracturing fluid has been developed to replace guar gum fracturing fluid in dealing with problems associated with fracturing fluids, such as high friction, too many residues after gel breaking and difficulties in fracturing fluid recovery. This fracturing fluid was formulated with 1.5% XYZC-6 and 0.15% XYTJ-3. XYZC-6 is a thickening agent made with a viscoelastic surfactant having peptide chain structure and a multi-component solvent; it can be mixed continuously in fracturing fluid in field operations and can be re-used. XYTJ-3, a modifier, can react with ions in the flowback fluid to form water-soluble complexes, thereby minimizing the effects of salinity on the performance of fracturing fluid. Experimental results showed that the fracturing fluid functioned normally at 90℃, was resistant to salt contamination to 100,000 mg/L, and performed very well in sand carrying and in fraction reducing. Gel breaking of the fracturing fluid can be done efficiently; the residue content of the gel-broken fluid was as low as 2 mg/L, and the interfacial tension of the gel-broken fluid was 10-2-10-3 mN/m. The fracturing fluid has been used successfully in the block Jing'an in Changqing oilfield. Wells fractured with this high efficiency oil displacing fracturing fluid have got oil production rates that are 2 times of the production rates of offset wells. The flowback fluid, after separation and sedimentation, can be re-used in formulating new fracturing fluid. The final flowback fluid can be used in oil displacement, helping realize the objectives of "zero discharge and zero pollution", greatly reducing the environment pollution risks associated with well fracturing operations. The use of this fracturing fluid has provided technical support for "not-falling-to-the-ground" of fracturing fluids.
Abstract: An instant polymer fracturing fluid has been developed to try to resolve the difficulties in disposing waste fracturing fluids and to minimize formation damage and pollution to the environment caused by fracturing fluids. Thickening agent, crosslinking agent, clay stabilizer and cleanup additive for the fracturing fluid were studied and optimized through laboratory experiment. The formula of the fracturing fluid suitable for use under formation temperature of 60-120℃ was prepared through laboratory evaluation of the fracturing as to its swelling ability, sand-carrying ability, gel-breaking ability, resistance to high temperature and shearing and its contribution to formation damage. Fracturing of 4 wells in Huabei Oilfield with this fracturing fluid was 100% successful. In fracturing operation, the low molecular weight polymer emulsion, multipurpose additives and ammonium persulfate are first pumped into a fracturing blender truck through metering pump, then mixed with water and proppants in the blender truck to start fracturing. The maximum sand ratio can be as high as 50%. This fracturing method, by combining the mixing of the fracturing fluid closely with operating, has the advantages as follows:1) there is no need for pre-mixing fracturing fluid, and the operation is thus simplified, and operation efficiency is enhanced. 2) the volume of the fracturing fluid can be prepared based on actual requirement, thereby minimizing residual fracturing fluid. The flowback fluid can be recovered for mixing new fracturing fluid, thereby minimizing the pollution to environment. 3) the fracturing fluid has a neutral pH value and is free of residue, and formation damage is thus minimized.
Abstract: When drilling and completing reservoirs of high oil saturation, water base fluids will diffuse into the near wellbore region and gradually mixed with oils in the near wellbore area during production. Under some conditions this process will lead to oil/water emulsification which further causes reservoir damage. For reservoirs with low oil saturation drilled with oil base drilling fluids, oil filtrate from the drilling fluids will also diffuse into the near wellbore region, resulting again oil/water emulsification in subsequent production. A mathematical model was established to predict reservoir damage caused by oil/water emulsification based on hydrodynamic instability. The time-distribution, spatial distribution and change of reservoir damage by oil/water emulsification was obtained using this model. The reach of reservoir damage, although is confined within several tens of centimeters around the wellbore, serious permeability impairment results in high skin coefficient. This numerical model, in which the breakdown and dispersion of oil/water interface at low interfacial tensions and high shear rates were hydrodynamically analyzed, and the pore distribution of reservoir rocks and blocking by emulsion drops were taken into account in the simulation, has provided, to some extent, time and spatial simulation and diagnosis of reservoir damage by oil/water emulsification.
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