2019 Vol. 36, No. 1

Display Method:
2019, 36(1)
Progresses in Research on Settling of Weighting Materials in High Density Drilling Fluids
PAN Yidang, YU Peizhi, MA Jingyuan
2019, 36(1): 1-9. doi: 10.3969/j.issn.1001-5620.2019.01.001
The density of drilling fluid plays a key role in controlling formation pressures, and the rheology and the settling stability of a high density drilling fluid, are technical difficulties always encountered in field drilling operations. Conventional weighting materials, such as API barites, tend to settle readily in high density drilling fluids, imposing serious negative effects on drilling/completion operations. Weighting materials of different particle sizes, morphology and densities play different roles in improving the rheology and settling stability of a drilling fluid. This paper summarizes the status quo of research work done to the settling of API barites and the progresses made in searching for micro powder weighting materials to replace API barites as drilling fluid weighing additives. Laboratory studies and field application both in China and abroad have demonstrated that micro powder weighting materials of high density are able to be used to address the settling stability problems associated with high density drilling fluids. These micro powder high density weighting materials also have the advantages of reducing friction and equivalent circulating density of drilling fluids. Problems associated with the use of micro powder weighting materials include difficulties in solids control and mud cake removal, and the glomeration of the micro particles of the weighting materials, which are now being addressed by many researchers all over the world.
Modified Soybean Lecithin Used as Water Base Drilling Fluid Lubricant
WANG Lan, WU Qi, JIANG Guancheng
2019, 36(1): 10-14. doi: 10.3969/j.issn.1001-5620.2019.01.002
Using lactic acid and hydrogen peroxide, the natural soybean lecithin can be modified through hydroxylation. The modified soybean lecithin is non-toxic, with EC50 greater than 30,000 mg/L. The modified soybean lecithin has good lubricity in fresh water, fresh water bentonite slurry and water base drilling fluids. Fresh water containing modified soybean lecithin has extreme pressure film whose strength is twice that of the extreme pressure film formed from PF-Lube in fresh water or CX-300H in fresh water. In 30 min four-ball friction test, the friction coefficient of a 1% modified soybean lecithin solution is less than 0.1, better as a lubricant than the DFL lubricant imported. The modified soybean lecithin was used at a concentration of 1% to treat 4% bentonite fresh water slurries before and after aging at 120 ℃,reducing the extreme pressure friction coefficient of the bentonite slurries by 90%, better than DFL and PF-Lube as extreme pressure lubricant. An environmentally friendly water base drilling fluid of 2.0 g/cm3 treated with 1% modified soybean lecithin and aged at 120 ℃ had lower viscosity,the HTHP filtration rate was reduced by about 50%, and the sticking coefficient and extreme pressure friction coefficient were all reduced by at least 60%. SEM was used to analyze the extreme pressure scratch, and XPS element analysis was conducted to reveal the lubricating mechanisms of the modified soybean lecithin. In general, the modified soybean lecithin is non-toxic and has good extreme pressure lubricity, revealing itself as a good lubricant in extended reach horizontal drilling.
Dynamic Simulation of Mud Losses into Fractured Formations Using ABAQUS Software
CHEN Xiaohua, QIU Zhengsong, YANG Peng, GUO Baoyu, WANG Baotian, WANG Xudong
2019, 36(1): 15-19. doi: 10.3969/j.issn.1001-5620.2019.01.003
Mud losses into fractured formations are the most common mud losses encountered in drilling fractured formations, and they are most complex and most difficult to control. Since mud losses into fractured formations are difficult to predict accurately in field operations, the success rate of bringing them under control is relatively low. Based on the principles of damage mechanics, the initiation of fracturing and propagation of the fracture during mud losses was simulated using the cohesive module of the ABAQUS software, and a 3D model describing the dynamic process of mud losses into fractured formations was established. The dynamic patterns of mud losses into fractured formations was obtained by analyzing the shape of fractures, the well circumferential stress and the pore pressures during mud losses. The study results showed that as the time of mud losses went on, the effect of the propagation pressure on the opening of a fracture was gradually weakening at first and then was increasing. As the opening of the fracture increased, the length of the fracture was increasing more and more slowly. The propagation of a fracture into which the mud was losing caused circumferential compressive stress around the mouth of the fracture (near the 0° position) to gradually decrease, while the circumferential compressive stress perpendicular to the mouth of the fracture was increasing. Pore pressures near the wellbore were affected by the invasion of drilling fluid, and were gradually increasing with time.
Downhole Fracture Diagnosis and Mud Loss Control Technologies Bases on Neural Network Algorithm
CHEN Zengwei
2019, 36(1): 20-24. doi: 10.3969/j.issn.1001-5620.2019.01.004
Formation fractures of different widths are always met during drilling, resulting in partial mud losses or even lost return which seriously affect drilling in a safe and efficient manner. Presently, the success rate of controlling mud losses into fractures is not high, and the fractures plugged have low pressure bearing capacities. One cause to these problems is the lacking of understanding of the widths of the fractures into which mud is lost. In this paper, rock mechanics mechanisms of formation fracture generation are used as the bases to determine the 6 mechanical and engineering factors affecting the width of fractures produced downhole. Using the nonlinearity and big data analysis natures of neural network computation a model for analyzing the widths of downhole formation fractures was established, which included input layer, output layer and 3 hidden layers. Using this model, the calculation precision of diagnosing the widths of downhole fractures was improved to an average error of only 2.09% and the maximum error of 5.88%, resolving the problem of predicting fracture width through experiences which is inaccurate or through imaging logging which is expensive. The widths of fractures calculated with the model were also used to optimize the particle size distribution of plugging additives, helping improve the strength and stability of bridging inside the fractures, the pressure bearing capacity of the plugged fractures was increased to 12.8 MPa and the back-pressure bearing capacity to 4.5 MPa. In field application, the highest pressure squeezed on the plugged fractures was 10 MPa, and the plugged fractures were able to stand large flow rate circulation, indicating that the fractured formations were effectively and successfully plugged.
Use Gel to Control Severe Mud Losses in Carbonate Reservoir Formations in Tahe Oilfield
LI Hui, LIU Huakang, HE Zhong, LI Zhiyong, ZHANG Shenshen, LI Qiang
2019, 36(1): 25-28. doi: 10.3969/j.issn.1001-5620.2019.01.005
Some carbonate reservoirs in Block 10 of the Tahe oilfield are developed with fractures and vugs, and are of high degree of inhomogeneity, resulting in severe mud losses difficult to bring under control with common bridging techniques. Polymeric gels, however, can be used because of their readiness to blocking the loss channels through their own crosslinking strength and sticking of the surfaces of the channels through which the mud is losing. Using partially hydrolyzed polyacrylamide (HPAM), hexamethylenetetramine (HMTA), methyl p-hydroxybenzoate (NIPAGIN) as the core additives, a high temperature gel used for lost circulation control in reservoirs was developed. Laboratory evaluation showed that the apparent viscosity of the gel is in a range of 40 – 45 mPa·s, and time for gelling under 140 ℃ is between 4 h and 10 h. Test of the gel on a fractured steel core (5 cm in length) showed that the gel was able to plug the fractures of 2–5 mm in width, and the pressures across the plugged fractures was 2.5 MPa, and was maintained within 18 d. The gel was broken and flowed back after 22 d of blocking. Efficiency of breaking the gel can be improved with gel breaker; the gel will get broken in 8 h when gel breaker is used. This gel, being able to both efficiently plug fractures and to effectively be removed, shows a broad prospect in controlling severe mud losses in reservoirs.
Study of a Strong Plugging Drilling Fluid Used in Shale Gas Drilling in He’nan Province
YUAN Qingsong, FENG Hui, ZHANG Dong, LI Zhongming, DAI Lei, DONG Guoguo
2019, 36(1): 29-35. doi: 10.3969/j.issn.1001-5620.2019.01.006
Downhole troubles such as borehole wall collapse and hole enlargement were frequently encountered during shale gas vertical drilling in Zhongmou county and Wen county, He’nan. Analyses of the geological characteristics of the reservoirs and test on the drilling fluids used in offset wells showed that the occurrence of the downhole troubles came from the lack of plugging capacity of the drilling fluid used. Based on this idea, studies were conducted on the formulation of the drilling fluid, focusing on the inhibitive capacity and plugging capacity of the drilling fluid. Two plugging agents, HSM and HGW, and a shale inhibitor HAS were selected to formulate the drilling fluid. Laboratory test of drilling fluid showed that it had good rheology after aging for 72 h at 100 ℃. Percent recovery of shale cuttings in hot rolling test was 98.5%. 10 h linear swelling rate of an artificial shale core tested with the drilling fluid was only 2.34%. 6 h API and HTHP filtration rates were 7.8 mL and 9 mL, respectively, indicating good plugging performance of the drilling fluid. The drilling fluid was also resistant to contamination. In field application, a well drilled with this drilling fluid experienced no borehole wall collapse and sloughing, percent hole enlargement was reduced from 21% to only 6%, proving that the drilling fluid has satisfied the needs of drilling operations in the blocks in question.
Treatment of CO32- and HCO3- Contamination in Water Base Drilling Fluid Used in Drilling the 3rd Interval of the Well HT2
ZHU Xuefei, SUN Jun, XU Sixu, LIU Haofeng, ZHA Lingfei
2019, 36(1): 36-40. doi: 10.3969/j.issn.1001-5620.2019.01.007
During drilling of the φ311.1 mm section between 4513 m and 5785 m of the well HT2, invasion of anions from the Donghe sandstones (main pay zone of the Hetianhe gas field) and the non-productive Ordovician limestone and dolomite caused CO32- and HCO3- contamination to the drilling fluid used for 140 d. Calcium concentration in the drilling fluid were always zero throughout the section. The drilling fluid was required to have high viscosity (funnel viscosity = 120-150 sec) high gel strength (10 sec/10 min gel strengths =(4-5) Pa/(15-25) Pa) to clean the hole because of three times of pipe sticking in broken formation sections, and this high viscosity/high gel strength caused the drilling fluid to have difficulties degassing and pumping. The rheology of the drilling fluid were then becoming difficult to control, finally the drilling fluid turned to a jelly state at high temperatures which no technical articles can be used for reference. In the early stage, quicklime, calcium chloride, organic salts and nanophase emulsion were introduced into the drilling fluid for property maintenance, and in the later stage, the properties of the drilling fluid were maintained with high concentration sulfonated polymer solution and alkaline liquor, without the addition of thinners in the drilling fluid. The properties of the drilling fluid were thus maintained stable through the whole section, ensuring safe drilling and realizing the geological goals expected.
Study and Application of a High-performance Water Base Drilling Fluid in the South Brink of Dzungars Basin
SHU Yiyong, SUN Jun, CHEN Junbin, ZHU Xuefei, ZHA Lingfei
2019, 36(1): 41-45,50. doi: 10.3969/j.issn.1001-5620.2019.01.008
The Anjihaihe formation in the south brink of the Dzungars Basin has high formation pressures and high I/S clay content, resulting in bit balling, borehole wall collapse and fast increasing of clay content in drilling fluid, and the properties of the drilling fluid can maintain stable only for a short time. High performance drilling fluids previously used are not be able to satisfy the needs of safe drilling. Laboratory study was conducted on the high-performance inhibitive drilling fluid technology suitable for drilling in the south brink of Dzungars Basin. The synergy of three drilling fluid additives, an amine based inhibitive agent SIAT, an amine based silanol HAS and a bonding agent HBA, and the plugging performance of two nanophase plugging agents were evaluated. A high-performance inhibitive water base drilling fluid was formulated using these additives, and the inhibitive capacity, resistance to contamination and high temperature tolerance were evaluated. Field application of the drilling fluid showed that the properties of the drilling fluid was stable, no bit balling has ever been found during drilling. Drilled cuttings maintained their shapes on shake screens and borehole wall was stabilized throughout the whole drilling process. Wireline logging and casing operation were all conducted smoothly.
A New Method for Evaluating Wetting Agents Used in Oil Base Drilling Fluid
LI Yanjun, HU Youlin, WU Jiang, ZHANG Wandong, LIAO Fengwu, YUE Qiansheng
2019, 36(1): 46-50. doi: 10.3969/j.issn.1001-5620.2019.01.009
Wetting agent is a key additive of oil base drilling fluid. Presently although there are a lot of methods for evaluating the performance of the oil base mud wetting agents, there is no standard for the evaluation. A new simple and easy method has been established to eliminate the deficiencies the old methods have, and it is based on the plastic viscosity of the oil phase, the settling velocity of barite particles in the oil phase and the volume of barite particles that settles. Three oil base mud wetting agents were studied in our studies, which are wetting agent A, wetting agent B and wetting agent C. Using the above evaluation parameters, the performance of the three wetting agents is in an order of C > A > B. To verify the feasibility of the new method, the contact angles of the three wetting agents and the properties of an oil base drilling fluid sample treated with A, B and C, respectively. The results showed that the new method is able to be used to effectively evaluate the wetting performance of wetting agents used in oil base drilling fluid.
Application of a High Temperature Modified Starch (FSL) in High Temperature Drilling
YANG Chao, YANG Guoxing, ZHOU Chenghua, WANG Chen, ZHAO Kaiqiang
2019, 36(1): 51-54. doi: 10.3969/j.issn.1001-5620.2019.01.010
The full play of the performance of the high temperature modified starch FSL benefits from the monomers used to produce the starch. The molecular weight of the monomers, contribution of the steric hindrance groups and the strong effect of the adsorbed hydrational groups all provide performance guarantee to FSL. FSL has been used to drill the high temperature sections of the well CSH1 and AF1 to verify its high temperature performance. The section of the well CSH1 in which FSL was used was drilled from 8145 m to 8380 m, and the bottom hole temperature was 187 ℃. The drilling fluid, after treatment with 2% FSL and full circulation, maintained its viscosity at a level that was almost the same as before, while its HTHP filtration rate was reduced obviously. The section of the well AF1 in which FSL was used was drilled from 5713 m to 5810 m, and the bottom hole temperature was 146 ℃. After the addition of 1% FSL into the drilling fluid and full circulation, the rheology of the drilling fluid was not apparently affected, while the filtration rate of the drilling fluid was greatly reduced. FSL showed its superior HTHP filtration control performance and high temperature stability in drilling the high temperature sections of the two wells. The excellent performance of FSL in field application has proven its broad application prospect. Another real environmentally protective and high temperature modified starch that is in development will technically support the green development of drilling industry.
Drilling Fluid Technology for Complex Salt-Gypsum Interbeds Drilling in Yolot,Turkmenistan
ZHU Siyuan, DENG Mingyi
2019, 36(1): 55-59. doi: 10.3969/j.issn.1001-5620.2019.01.011
Drilling operations in the Yolot area, Turkmenistan have encountered two problems, difficulties in controlling the properties of the drilling fluid because of high pressure formation water invasion and salt/gypsum interbeds, and mud losses. Studies have been conducted on high density drilling fluid formulations and mud loss control and prevention based on the geological and engineering characteristics of the high pressure saltwater zones and the salt/gypsum interbeds. Analyses were conducted on the difficulties in maintaining and controlling the properties of the drilling fluid as well as controlling and preventing mud losses at high drilling fluid densities, high temperatures and high calcium contamination. A high density saturated saltwater base drilling fluid was modified by introducing calcium-resistant shale inhibitors and other selected additives, giving birth to a high temperature high density drilling fluid containing high concentrations of calcium ions. Laboratory study and field practice showed that the modified drilling fluid was able to resist the effects of high temperatures to 140 ℃ and calcium contamination to 40,000 mg/L. Use this drilling fluid, calcium contamination from long section of salt/gypsum interbeds was successfully resolved. By reducing circulation pressure loss of the high density drilling fluid and using the techniques of mud loss control while drilling, combined with high concentration bridging lost circulation material slurries, drilling problems such as mud losses and narrow safe drilling window were satisfactorily resolved.
Study on a High Temperature High Density Drilling Fluid Used on the Well LOFIN-2,Indonesia
LUO Xiaohu
2019, 36(1): 60-64. doi: 10.3969/j.issn.1001-5620.2019.01.012
Well Lofin-2, a deepest onshore well drilled in Indonesia, is a key exploratory well deployed on the Seran Island, east Indonesia, with vertical depth of 5861 m. The highest temperature of the well is between 150 ℃ and 180 ℃, and a mud of 2.10–2.16 g/cm3 has to be used to balance the formation pressures. Drilling challenges include fractured shales, high pressure saltwater zones, which are the causes of induced mud losses and formation water invasion, and silty mudstones, which are the easy to disperse into drilling fluid to make the mud rheology uncontrollable worse. A drilling fluid was formulated to deal with these problems. Some high temperature drilling fluid additives were selected to render the drilling fluid good stability at elevated temperatures. The water base drilling fluid formulated is able to work normally at temperatures up to 180 ℃ and has densities adjustable between 2.10 g/cm3 and 2.16 g/cm3. Field application of this drilling fluid showed that it had stable properties which were easy to maintain. The well was successfully drilled with no big troubles. The use of this drilling fluid has provided a choice of using HTHP drilling fluid in this block.
Application of High Density Water Base Drilling Fluid System in Horizontal Slim Hole Drilling
WANG Xin, ZHANG Minli, ZHUANG Wei, TIAN Zengyan, WANG Zhibin, BAI Bing, ZHONG Xinxin
2019, 36(1): 65-69. doi: 10.3969/j.issn.1001-5620.2019.01.013
The well Shi-49H1, located in the block Shi-49 in Yingxi area, Qaidam Basin, Qinghai Oilfield, was drilled to enhance the productivity of the anticline structure of the block, especially the productivity of the E32-V reservoir group, and to further understand the oil and gas enrichment patterns of the E32 reservoir of the Shizigou. Well test data will be used to calculate reserves of the oilfield. A BH-WEI drilling fluid was used to drill the third interval, a slim hole section in which the use of high density drilling fluid resulted in downhole problems such as high annular pressure loss, rheology control, narrow drilling window, contamination to the drilling fluid, and high risk of well control etc. These problems have been successfully addressed partially because of the use of the BH-WEI drilling fluid. Average hole size was 159.88 mm, with percent hole enlargement of only 4.9%, indicating that the borehole wall was stabilized by the drilling fluid. The density of the drilling fluid was 2.10 g/cm3, the highest density that has ever been used in horizontal drilling in Yingxi area. No hindrance to exerting pressure on bit has ever been encountered during horizontal drilling. Tripping of the drilling string was conducted smoothly. The well was successfully completed. A high industrial oil production rate was acquired, as determined by well test, indicating that the BH-WEI mud has good reservoir protecting ability.
Effect of Well Cementing at Low Return Flowrate on the Performance of Oil Well Cement Slurries
XU Liqun, ZHANG Xingguo, WANG Yindong, JIN Ye, DING Hui, LIU Zeng, LIU Kaiqiang, GUO Xiaoyang
2019, 36(1): 70-76. doi: 10.3969/j.issn.1001-5620.2019.01.014
During liner cementing in the fourth and fifth intervals of ultrahigh pressure gas wells drilled in the piedmont structure in Kuche county, Tarim basin, the hydration reaction speed of the cement is probably affected by its low return flowrate and slow temperature rise during pumping and displacement. To resolve this problem, laboratory study was conducted on the effect of low agitating speed resulted from low return flowrate on the performance of ultra-high-density cement slurries. The study result showed that at low return flowrate, the hydration reaction speed and the reaction process of a cement slurry become slow, resulting in great extension of the thickening time of the cement slurry, which in turn results in ultra-retarding of the top cement slurry in annular space. The suspension performance of the cement slurry was basically not affected by the low return flowrate, and to some extent, the low return flowrate even helped improve the suspension performance. The 14 d compressive strength of the set cement was slightly reduced, while the 28 d compressive strength of the set cement was basically not affected by the low return flowrate. The results of this study will provide a new theoretical basis and technical means to select cement slurry formulation for well cementing in similar conditions, minimize the amount of retarding agents required, make it easier to formulate cement slurry, and mitigate the ultra-retarding problem of the top cement in annular space.
Study on Microscopic Hydration Process of a Cold Temperature Cement Slurry Used in Frozen Areas at -18 ℃
LIU Haoya, BAO Hongzhi, ZHAO Wei
2019, 36(1): 77-81. doi: 10.3969/j.issn.1001-5620.2019.01.015
The cold sea area in polar region of the earth possess huge reserves of oil and gas, cementing of the wells developing these oil and gas is not able to be completed using conventional cement slurries because the water in the cement slurry gets frozen in cold temperatures in polar region, and the hydration of cement is unable to proceed. A cement slurry has recently been developed for use in this cold area, and the products of hydration at -18 ℃ and at room temperature were compared microscopically. Laboratory experimental results showed that the cement slurry developed has excellent setting performance at cold temperatures; at -18 ℃, the cement slurry sets in 0.5-3 h, and the 24 h compressive strength falls between 3.5 and 9 MPa, indicating that the cement slurry can be used to resolve the problems conventional cement slurries have to face with: being unable to set and having no strength at cold temperatures. Microscopic test of the cement slurry shoed that the hydration degree of the cement slurry at -18 ℃ is lower than that of the cement slurry at room temperature, while the Aft content of the cement slurry at -18 ℃ is higher than that of the cement slurry at room temperature, a phenomenon that is positive to the mechanical properties of the set cement.
Study and Application of Wettability Reversal Agents for Well Cementing
ZHANG Fuming, ZHAO Hu, DAI Dan, WANG Xueshan, LIU Mengtao
2019, 36(1): 82-86. doi: 10.3969/j.issn.1001-5620.2019.01.016
To improve the job quality of well cementing, the oil base mud and oil films adhered on the surface of the borehole to be cemented have to be removed and the mixture of oil base drilling fluid and spacers in the borehole should be changed to water wetting. Two wettability reversal agents, PC-W31S and PC-W25L, have been developed to perform the tusks mentioned above. PC-W31S is added at a concentration between 0.5% and 1.0% (percent mass of water) and PC-W25L between 5% and 10%. Study of the working mechanisms of the two agents has been conducted, focusing on the effects of the wettability reversal agents on the water wetting capacity of spacers used. In the study, PC-W31S and PC-W25L were compounded to make the best use of the two. Evaluation tests of the two agents showed that when the volumetric fraction of a spacer treated with PC-W31S and PC-W25L (as the main additives) in a mixture of the spacer and oil base mud is less than 50%, the mixture can be completely turned from oil wetting (oil as the continuous phase) to water wetting (water as the continuous phase). Using the spacer to flush a rotor, more than 80% of the oil base mud adhered on the surface of the rotor can be flushed away and the flushed surface becomes water wet. The spacer is rheologically compatible with oil base drilling fluids and cement slurries, and the effects of the spacer on the thickening time and compressive strength of cement slurry are controllable. The two agents have been successfully applied on the well LD8-1-7 and won a bidding in a well cementing project in southeast Asia.
Rotary-liner Cementing Technology for Use in Complex Working Conditions in the Weizhou K Oilfield
LI Zhong, GUO Yongbin, GUAN Shen, LIU Zhiqin, PENG Wei
2019, 36(1): 87-92. doi: 10.3969/j.issn.1001-5620.2019.01.017
The well X1 drilled in the Weizhou K Oilfield, Beibu Gulf Basin, western South China Sea, is a directional well with complex downhole conditions. The problems associated with this well include high well angle, long open section, high temperature, abnormal low pressure resulted from depletion of reservoir pressure, and high gas/oil ratios, which as a whole present a challenge to well cementing operations. When cementing the φ177.8 mm liners in φ215.9 mm wellbore, low displacing efficiency will result if conventional static liner cementing technology is used because of the narrow clearance between the line string and the wellbore. Problems associated with this operation include lost circulation, gas channeling because of poorly cemented formations, formation pressure depletion, and poor cementing quality of the high temperature reservoirs that cannot satisfy the needs of subsequent production through perforation. To ensure good separation between oil, gas and water zones under complex work conditions, a rotary-liner cementing technology and a high temperature early-strength anti-channeling cement slurry have been used in the cementing the well X1. New flushing fluid and spacer for the oil base mud used were selected for better cleaning mud cakes, and for reversed wettability of the surfaces of the cement sheath and the borehole wall. Using computer software, the rotary torque of the liner string was accurately simulated, and the eccentricity of the liner string improved. The φ177.8 mm liner, which penetrated a pressure-depletion and high temperature reservoir, was successfully cemented. Sector cement bond tool logging data showed that good separation between oil, gas and water has been obtained. Cement quality of the whole well was excellent, better than the cementing quality of the well K2 drilled nearby, satisfying the needs of subsequent production through perforation.
Pumping Cement Slurry and Drilling Set Cement Plug in High Pressure Open Hole Gas Well
DANG Donghong, SONG Yuanhong, WU Yongchao, WANG Chong, HAN Gewei, WU Jinbo, YIN Lu
2019, 36(1): 93-96. doi: 10.3969/j.issn.1001-5620.2019.01.018
Well SBC-200 is a complex well drilled in a oil and gas field in east Venezuela. Technical casing of φ244.5 mm was run to 4,864 m in this well. Pipe sticking was encountered when drilling the 4th interval (hole size φ215.7 mm) to 4 945.12 m, and several methods of freeing the pipe sticking were tried and failed. Breaking out by explosion was performed and the top of the fish was at depth of 4,897.56 m. Gas cut occurred during drilling with an oil base drilling fluid of 1.415 g/cm3, and was stopped when mud density was 1.44 g/cm3. Mud losses occurred when mud density was 1.49 g/cm3. In order to drill to the designed depth, the open hole 35.53 m above the top of the fish was filled with cement slurry and the well was sidetracked. The well was finally cemented with a cement slurry of high density, high strength and low filtration rate. The cement plug was made to satisfy the needs of sidetracking, using prepad with complex functions and techniques suitable for the well conditions.
Study and Application of a Large Temperature Difference Cement Slurry with Good Elasticity and Toughness
GAO Yuan, YANG Guangguo, LU Peiqing, SANG Laiyu, LIU Xuepeng, LIU Rengguang
2019, 36(1): 97-101,108. doi: 10.3969/j.issn.1001-5620.2019.01.019
Cementing of a gas well with long section to be cemented and big temperature difference has been challenged with difficulties such as ultra-long time of retarding of the top cement column and retained pressure in annular space resulted from failure of cement sheath. Studies have been conducted on the selection of retarding agents and filter loss reducers that can satisfy the requirements of cementing at 170 ℃ with temperature difference of about 100 ℃ and the strength development of set cement. High temperature additives with good toughness were also selected and used in laboratory studies to reduce the brittleness and to enhance the elasticity and toughness of the set cement. Using these selected additives a large temperature difference cement slurry with good elasticity and toughness was developed. The cement slurry had densities adjustable between 1.50 g/cm3 and 2.20 g/cm3, good rheology, API fluid loss of less than 50 mL, 72 h compressive strength of 11.5 MPa of a 1.50 g/cm3 low density set cement at temperature difference of 50 ℃, 72 h compressive strength of 17.7 MPa of a 1.88 g/cm3 set cement at temperature difference of 70 ℃, and the set cement had elastic modulus of less than 7 GPa and flexural strength greater than 3.5 MPa. Inspection of the integrity of the cement sheath showed that the cement sheath was able to undergo 30 turns of loading and offloading of 90 MPa. This cement slurry was successfully used in the tieback of φ193.7 mm and φ206.4 mm liners in the well Shunbei-4 drilled by the Northwest Oilfield Division of Sinopec, with 5693 m open hole cemented with high quality in one try. The difference of the temperatures between the bottom and top was 105 ℃. The cementing operation of the well Shunbei-4 has set up an example of successfully cementing long section of a gas well
Thickening Performance and Thickening Mechanism of a Viscosifier for CO2 Fracturing Fluid
LI Qiang, WANG Yanling, LI Qingchao, WANG Fuling, YUAN Lin, BAI Hao
2019, 36(1): 102-108. doi: 10.3969/j.issn.1001-5620.2019.01.020
CO2 fracturing fluid requires suitable viscosifiers to increase its viscosity. A branched polysiloxane was developed for use in CO2 fracturing fluid as a viscosifier. The branched polysiloxane is synthesized with octamethylcyclotetrasiloxane and tetramethylt etravinylcyclotetrasiloxane as raw materials, hexamethyldisiloxane as blocking agent, pentamethyldisiloxane as branching additive, and tetramethylammonium hydroxide and chloroplatinic acid as catalyst. The molecular structure of the viscosifier was characterized using FT-IR method, and CO2 fracturing fluid treated with the viscosifier studied for its performance. It was found that, at 20 ℃, the viscosity of a CO2 fracturing fluid treated with 7% polydimethylsiloxane was 1.66 mPa·s, while the viscosity of another CO2 fracturing fluid treated with 7% synthesized branched polysiloxane viscosifier of the same molecular weight (as that of the polydimethylsiloxane) was 6.67 mPa·s, showing that the branched polysiloxane viscosifier is a better viscosifier for CO2 fracturing fluid. The viscosity of the CO2 fracturing fluid increases with increase in the concentration of the branched polysiloxane viscosifier in the fracturing fluid. At viscosifier (branched polysiloxane viscosifier) concentration of 1% to 3%, when pressure is increase from 8 MPa to 14 MPa, the viscosity of the CO2 fracturing fluid increased remarkably. On the other hand, the viscosity of the CO2 fracturing fluid decreases greatly as temperature increases. The branched polysiloxane viscosifier synthesized in this study is able to better increase the viscosity of CO2 fracturing fluid than polydimethylsiloxane, and has thickening ability that is almost the same as that of viscosifiers manufactured abroad. This paper also discusses the thickening mechanisms of the branched polysiloxane.
Study on a New Temperature-controlled Variable Viscosity Acid
Liu Tongyi, Wang Meng, Chen Guangjie, Dai Xiulan
2019, 36(1): 109-114. doi: 10.3969/j.issn.1001-5620.2019.01.021
A variable viscosity acid was formulated with a viscosifier BCG-5, a corrosion inhibitor HB-2 and an active agent NC-1. This acid, formulated on the theoretical basis of the Biggs’ three-stage model describing the reaction between polymer and surfactant, shows low apparent viscosity at low temperature, and shows high apparent viscosity at high temperature. Since formation temperature increases with depth, this acid, when injected into the formation, will show low viscosity in shallow depth and high viscosity in deep depth. Laboratory experiments have been conducted to compare the viscosifying capacity of different thickening agents, test the effects of the content of the active agent on the viscosifying of the acid under the control of temperature, and optimize the type and concentration of the corrosion inhibitor. It was found that the apparent viscosity of the acid was 29 mPa·s at room temperature, and gradually increased to 250 mPa·s after being heated at 90 ℃ for 20 min. At 100 ℃, the acid still had ability to change its viscosity. The corrosion rate of this acid was retarded by 90.1%. The apparent viscosity of the acid was reduced to 5 mPa·s after reaction with rocks, and the surface tension of the acid became 20 mN/m, which is helpful to increasing the flow conductivity, reducing friction and drag and performing in-depth acidizing and acid-fracturing.
Development and Application of an Adsorptive Retarded Acid
LI Zefeng, WANG Gaihong, JI Suibo
2019, 36(1): 115-119. doi: 10.3969/j.issn.1001-5620.2019.01.022
Conventional acids for acidizing job have some disadvantages such as fast reaction, short effective functioning distance and poor erosion etc. To address these problems encountered in acidizing with conventional acids, an adsorptive retarded acid was developed, in which the hydrophobic cationic groups of the retarder are able to adsorb on the surfaces of formation rocks, forming a protective membrane to shut off the contact of H+ and the surfaces of the rocks, thereby retarding the reaction between acid and rocks, and increasing the length of acid-corroded fractures and the inhomogeneity of acid corrosion. A retarded acid formulation was developed based on the optimization acid concentration and the concentration of other additives. Evaluation of the performance of the retarded acid showed that the acid was retarded by 91.2% and the rate of corrosion was retarded by 99.6%. Reaction of the retarded acid and rocks produced clear ditches and trenches, and the flow conductivity of the ditches and trenches drops at a low magnitude as enclosure pressure is increasing, fully proving the retarding capacity of the retarded acid. This retarded acid has been successfully used in Sulige gas field, the daily gas production rate of an individual well was 5 times that of gas wells nearby.
Preparation and Application of an Emulsion Supramolecular Fracturing Fluid for Shale Gas Development
ZHANG Xiaohu, YU Shihu, ZHOU Zhongjian, SUN Yadong, LI Jia
2019, 36(1): 120-125. doi: 10.3969/j.issn.1001-5620.2019.01.023
To satisfy the needs of producing shale gas efficiently and cleanly, anemulsion-like hydrophobic association polymer ASNP was developed through inverse emulsion polymerization. The ASNP was then compounded with an extender SD-Z to produce an emulsion supramolecular fracturing fluid SMF-1, which can be prepared at the moment of using, without the needing of extra additives. Changing the concentration of ASNP, the fracturing fluid can be turned into slick water, linear gel or colloidal solution. SMF-1 slick water has excellent drag reducing ability, fresh water and fracturing fluid flowed back containing 0.08% SMF-1 have their drag reduced by about 70%, and their salt resistance can be 10000 mg/L. SMF-1 colloidal solution has excellent high temperature and shearing performance, 0.6% SMF-1 solution sheared at 110 ℃ and 170 sup>-1 for 120 min has viscosity that is at least 120 mPa·s throughout the test process. SMF-1 fracturing fluid is a fluid with low viscosity, high elasticity and good sand carrying capacity. SMF-1 fluid after gel breaking has viscosity that is less than 1.5 mPa·s, and the residue content of the gel breaking fluid is only 12.8 mg/L. In core test with the SMF-1 fracturing fluid, permeability impaired by the SMF-1 fluid is as low as 11.8%. In field application, SMF-1 can be switched to different fluids with stable properties, and the sand content is also higher than the fracturing fluid used in the offset section of the same well and in offset wells.
Evaluation of Drilling Fluid Damage to Matrices of Tight Sandstone of Keshen Gas Reservoir in Tarim Basin
ZHANG Lufeng, ZHOU Fujian, ZHANG Shicheng, WANG Jie, WANG Jin
2019, 36(1): 126-132. doi: 10.3969/j.issn.1001-5620.2019.01.024
Micrometer-and nanometer-sized pores are very developed in the matrices of the tight sandstone of Keshen gas reservoir in Tarim Basin, and capillary force plays an important role in formation damage by drilling fluid invasion during drilling, leading to reduced reservoir productivity. Using conventional steady state method to evaluate damage to low permeability tight sandstone by drilling fluid requires high displacing pressure and long stabilization time and is therefore unacceptable. Hence, a mathematic model for permeability calculation was established on the basis of transient pressure transmission method, and the model was solved using Laplace transformation. Based on the solutions to the model, the patterns of damage of the tight sandstone matrices in Keshen gas field by drilling fluids was quantitatively analyzed using pressure transmission permeability tester. Experimental results showed that average percent formation damage by oil base drilling fluids was 31.24%, with water base drilling fluids, on the other hand, this value was 23.67%. The research outcome provides a new clue for evaluating the damaging potential of fluids to be injected into the hole.