钻井液与完井液

Abstract:
Formation damages existed in drilling operations include particle blocking, water blocking, coarse emulsion, wettability in the near-wellbore area. A non-ionic micro emulsion formulated with glycol ethylene octylphenyl ether has been studied on its efficiency in removing blocking caused by mud solids particles. The micro emulsion has interface tension less than 0.1 mN/m, and can fast solubilize highly viscous crude oils. The pH value, ionic type and salinity of the micro emulsion as well as temperature have little effect on the solubilizing power of the micro emulsion. Laboratory experiments show that this micro emulsion can remove emulsion blocking in the formations and crude oil in mud cakes effectively. It helps restore the permeability of reservoir formations by wettability reversal. 90% of mud cakes can be removed by this emulsion, and the rate of permeability recovery can be as high as 95%.

Study and Application of Gel-time Controllable Lost Circulation Material

LI Shaoli, GUO Ziwen

2016, 33(3): 7-14. doi: 10.3969/j.issn.1001-5620.2016.03.002

Abstract(853) PDF (6844KB)(292)

Abstract:
In the development of theshale gas in Jiaoshiba, Fuling, Chongqing, mud losses into solution cavities or fractures have occurred frequently during the whole drilling process, and the mud losses were very difficult to be stopped. A gel-time controllable lost circulation material (LCM) has been developed for use in this area to try to control the severe mud losses. This LCM is formulated with gel materials, thixotropic agents, fibers, swelling agents, microcapsules and surfactants. The performance and mechanism of this LCM in mud loss control have been evaluated and analyzed. This gel-time controllable LCM is suitable for controlling mud losses into formations with high permeability, large-sized pores, fractures, or solution cavities. This LCM works in a temperature range of 30-80℃, and has adjustable gel time. When solidified, the LCM has compressive strength of 5.0 MPa (4 h) and 10 MPa (8 h). Pressure bearing capacity of the set LCM is 14 MPa. The set LCM is striongly resistant to water corrosion and has strong thixotropy. 80% of mud losses in 45 wells have been successfully brought under control. This gel-time controllable LCM has played a great role in controlling mud losses into solution cavity and fracture.

Numerical Simulation of Borehole Wall Strengthening Using ABAQUA

SONG Dingding, QIU Zhengsong, WANG Can, LIU Junyi, WANG Qiang, ZHONG Hanyi, ZHAO Xin

2016, 33(3): 15-19. doi: 10.3969/j.issn.1001-5620.2016.03.003

Abstract(839) PDF (6931KB)(234)

Abstract:
The borehole wall strengthening technology has in recent years been becoming an important means of enhancing the compressive strength of formations all over the world. This paper discusses a two-dimensional model for borehole wall strengthening based on the software ABAQUS, and the working mechanism of and factors affecting borehole wall strengthening through numerical simulation. It has been found that plugging materials, after bridging the fractures in the formations, laterally press the formations on both sides, increasing the peripheral stresses of the borehole which have the maximum increase between the lower angles of 0° and 30°. After the redistribution of the peripheral stresses, the fracture pressure of the formation is increased, and the easy-to-fracture point is deviated from its original position. In certain fracture openings, the wider the fractures, the more severe the lateral formations are pressed, and hence the better the strengthening of the borehole wall. Anisotropy of geo-stresses, positions of the bridging by plugging agents and borehole pressures all play important roles in affecting the peripheral stresses. The more severe the anisotropy, and the higher the borehole pressure, the higher the peripheral stress increments after bridging. Bridging spots of the plugging agents that are much closer to the borehole wall mean better strengthening effects; with the bridging spots moving towards the apexes of the fractures, the borehole wall strengthening dies away.

Synthesis and Study on Hectorite Viscosifier Used in Water Base Drilling Fluid

QIN Yong, MA Kedi, JIANG Guancheng

2016, 33(3): 20-24. doi: 10.3969/j.issn.1001-5620.2016.03.004

Abstract(667) PDF (3370KB)(323)

Abstract:
Hectorite can be used as a high temperature viscosifier in water base drilling fluids, and it is a rare mineral found in nature. A hectorite has been successfully synthesized in laboratory using microwave irradiation method and characterized with XRD, FTIR and particle size distribution analysis. The performance of the synthesized hectorite in water base drilling fluid has been evaluated. The particle sizes of the synthesized hectorite falls in the range between 18.17 nm and 58.77 nm, averaged at 29.72 nm. 4% bentonite slurry treated with 0.3%-1.5% synthesized hectorite, has viscosity, gel strength and YP/PV ratio remarkably increased, and filter loss reduced. When the concentration of hectorite is 1.2%, the viscosity of the slurry is increased by 2.64 times, while the gel strength and YP/PV ratio still remains moderate. The bentonite slurry treated with 1.5% hectorite can resist the contamination of calcium (2.5%) and salt (15%). With temperatures increased from 80℃ to 220℃, the apparent viscosity of the 4% bentonite slurry +1.5% hectorite decreases followed by an increase, and finally remains at above 20 mPa·s. The gel strength and YP/PV ratio changes at a same pattern as that of apparent viscosity, but with remarkable decreases at first. At 200℃, almost all conventional polymers lose their efficiency as viscosifiers in water base drilling fluid, while hectorite is still functioning. Thus the synthesized hectorite is an ideal viscosifier for use in high temperature water base drilling fluid, and is well compatible with other additives.

Borehole Wall Collapse and Control in Shale Gas Well Drilling

LIU Jingping, SUN Jinsheng

2016, 33(3): 25-29. doi: 10.3969/j.issn.1001-5620.2016.03.005

Abstract(760) PDF (7874KB)(232)

Abstract:
Borehole wall instability in shale gas horizontal drilling is critical to the success of shale gas development in China. Shale samples taken from the Longmaxi formation in the Block 108 in Zhaotong, Yunnan, were studied for their mineral components, micro structures and textures, surface characteristics, swelling and dispersion performances through XRD, SEM, mechanics and wettability analyses, rate of swelling and percent recovery of shale cuttings through hot rolling test. The mechanism governing the collapse of the shale formation studied has been disclosed. This formation, mainly composed of illites, has no montmorillonite and I/S mixed layers, and surface hydration is the main cause for the shale formations to lose their stability. Based on the second law of thermodynamics, a decrease in shale's surface free energy will inhibits the surface hydration of shale. In laboratory studies, long chain alcohols were used to change the wettability of the shales through surface adsorption, thus effectively decreased the surface free energy and inhibited the surface hydration of the shales, and the formation can be stabilized.

Study and Application of Additives for Synthetic Fluids with GTL as the Base Fluid

WANG Maogong, XU Xianguang, SUN Jinsheng, WANG Lihui, YANG Haijun, WANG Baocheng

2016, 33(3): 30-34,40. doi: 10.3969/j.issn.1001-5620.2016.03.006

Abstract(699) PDF (1146KB)(265)

Abstract:
To improve the high temperature rheology and filtration property of the synthetic base drilling fluid using gas-to-liquid (GTL) oil as the base fluid, an organophilic clay having superior gel properties and an environmentally friendly filter loss reducer made from natural humic acid, have been developed. A GTL base drilling fluid was formulated with the organophilic clay, the modified humic acid, a primary emulsifier and secondary emulsifier previously developed. The organophilic clay, DR-GEL, was made by intercalating dihexadecyl dimethyl ammonium chloride into the crystal layers of a purified sodium montmorillonite, and had good gel performance in GTL (percentage of colloid particles to 98%), high viscosity and gel strength (3 Pa), and good high temperature stability (it functioned at 220℃)in laboratory experiments. The filter loss reducer, DR-FCLA, was made by modification of purified humic acid with dihexadecyl dimethyl ammonium chloride and diethylene triamine. DR-FCLA greatly reduced the HTHP filter loss, helped make the drilling fluid emulsified better and improved the rheology of drilling fluid. It functioned at high temperatures up to 230℃. The synthetic drilling fluid made with these additives had densities ranging in 1.6-2.3 g/cm³, good rheology (AV=27-61 mPa·s, YP=6-9 Pa) at temperatures ranging in 120-200℃, high electrical stability (ES>800 V), and HTHP filter loss <2.5 mL. This synthetic drilling fluid has been successfully used in Sumatra, Indonesia to drill the well NEB Basement-1 in Block Jabung. The properties of the drilling fluid remained stable for 40 days at bottom hole temperatures higher than 180℃. Difficulties in maintaining the suspension and cuttings carrying capacity of drilling fluid have been solved since then.

Ploya mine Shale Inhibitor Content Measurement and Determination of Optimum Dosage

GUO Jianhua, MA Wenying, LIU Xiaoyan, DU Mingjun, LI Baohui, ZHONG Ling

2016, 33(3): 35-40. doi: 10.3969/j.issn.1001-5620.2016.03.007

Abstract(579) PDF (3601KB)(214)

Abstract:
As a high performance shale inhibitor, polyamine has found a wide application in drilling with water base drilling fluids. Studies on polyamine were primarily focused on the inhibitive capacity and field application, and no technical specifications of polyamine have been established. A method of measuring the content of polyamine is discussed in this paper. Using the "sodium tetraphenylborate method", the content of a free polyamine, FYZ-1, was measured. The measuring method has been determined through the optimization of the testing conditions, such as indicators, precipitation conditions, titration conditions, pH values, etc. The effect of drill cuttings on the content of polyamine has also been studied. It has been founded in laboratory experiments that the quantities of the adsorbed polyamine on carbonaceous shale, hydratable shale, brittle shale and sandstone are decreasing in that order. This finding can be used to determine the concentrations of polyamine in drilling fluids in field operations.

Inhibitive Drilling Fluid Technology Used in High Dipping High Pressure Drilling in Block D, Myanmar

QIU Guangyuan, XIAO Chao, ZHANG Kaishen, HE Hanping

2016, 33(3): 41-45. doi: 10.3969/j.issn.1001-5620.2016.03.008

Abstract(547) PDF (3725KB)(180)

Abstract:
The formations penetrated during drilling in the Block D in Myanmar are characteristic of high dipping, multiple fault zones, high formation pressures, water sensitive shales and developed fractures. Borehole wall collapse, hole washout (100%) and pipe sticking caused by borehole wall collapse (32 times in a single well) have been the problems frequently encountered during drilling and unlikely to be solved by conventional KCl polymer drilling fluid and protecting the borehole wall by multiple casing strings. The conventional KCl drilling fluid has thus been modified through laboratory experiment. In the new drilling fluid, an optimized emulsified asphaltene with particle sizes in micrometers is used as an additive for borehole wall collapse controller, KCl and poly glycol as main shale inhibitors, PAC as filter loss reducer, and sulfonated polymer as high temperature stabilizer. Compared with the previously used KCl polymer drilling fluid, the rate of swelling of shale cutting sample tested with the new mud has been reduced by 15%, and the recovery of shale cuttings on hot rolling test increased by 50%. Good performance of the new mud in controlling borehole wall collapse has been obtained, together with other measures such as increasing mud weight, optimizing the properties of drilling fluid, and reducing API filter loss. With the new mud, the rate of bore hole washout has been reduced from 100% to 20%, the drilling time saved by 20%, the time efficiency of well drilling increased by 35%. This new drilling fluid technology has effectively solved the borehole wall collapse frequently encountered in wells drilled in Block D, where high dipping and high pressure were of great concern.

Discussion on the Mud Loss and Borehole Wall Collapse Prevention in Horizontal Drilling in Sulige Gas Field

WU Manxiang, MOUYANG Qiongjie, GAO Jie

2016, 33(3): 46-50. doi: 10.3969/j.issn.1001-5620.2016.03.009

Abstract(577) PDF (2581KB)(309)

Abstract:
Borehole stabilization previously in horizontal drilling in Sulige gas field has been realized through increase in mud weight. Presently, the development of the Sulige gas field has entered a new stage of overall development in which formation pressure has been depleted because of gas production. Mud losses caused by high density and difficulties in controlling severe mud losses often led to inability to exert WOB and differential pressure pipe sticking. To prevent mud losses caused by high mud weight, several things have to be done, for example, improve the sealing and plugging performance of the drilling fluid, maintain the inhibitive capacity and activity of the mud filtrates, reduce the ECD to a certain level, and improve the mud rheology and use good engineering practices. The types of the mudstones commonly found in the horizontal section are analyzed, and requirements on drilling fluid studied. Measures for controlling mud losses are discussed. It is presented that to prevent borehole wall collapse, the important thing is to avoid mud losses. If sandstones are drilled in the horizontal section, or, if the mudstones encountered in the horizontal section is stable, mud weigh and flow rate can be reasonably reduced. Mud losses in the horizontal section are generally losses caused by differential pressures, and squeezing LCM slurries may induce new fractures in the formations, hence aggravating mud losses even into adjacent wells. For different formation lithology, such as argillaceous sandstone, sandy mudstone, gray mudstone and carbonaceous mudstone, different mud properties shall be adopted.

The Development and Evaluation of A Set of New Lost Circulation Material

CHENG Pengzhi, YI Caiwen, MEI Linde, CAO Jing

2016, 33(3): 51-55. doi: 10.3969/j.issn.1001-5620.2016.03.010

Abstract(790) PDF (1527KB)(277)

Abstract:
Conventional lost circulation materials (LCM) have some "deficiencies", for example, the particles of mineral LCM have too big density and are too brittle, thus it is easy for the particles to settle down in drilling fluids, and to crush when the formation fractures are closing. The particles of plant LCM have densities that are too low for them to mix evenly with drilling fluid, and are always float at the top of the LCM slurries. These plant LCM become soft at HTHP conditions, no longer suitable for stopping mud losses. Flake LCM, such as seashells and mica, are also too brittle and the mouth of the opening of fractures are easy to be covered by these flake LCM. In subsequent operations, the flakes are eroded away, inducing mud losses to occur again. To solve these problems, a series of new LCM, the LCC series, have been developed using special techniques. In the LCC series, the LCC100 has densities adjustable between 1.30-2.30 g/cm³, and the ratio of particles broken at 25 MPa is less than 10%. After hot rolling in NaOH solution with pH 12, no obvious changes in the strength of the particles have been found, meaning that LCC100 has good pressure resistance, temperature resistance and high pH tolerance. LC200 is an LCM that is both ductile and rigid. LCC300 can make its way into fractures under pressure, strengthening the plugging and sealing of mud loss channels. It has been demonstrated that LCC series are effective in controlling mud losses into fractures and pores; they remain their integrity at a pressure of 7 MPa on API LCM tester. Oil base or water base LCM slurries made with LCC series can stand 20 MPa on HTHP LCM tester (with wedge-shaped fractures) at 150℃, without being pierced, and the pressure can be stabilized at 19.8 MPa.

Displace Open Hole Full of High Density OBM with WBM

ZHU Xuefei, YAN Fushou, SHU Yiyong, SUN Liangguo, SHEN Rendong

2016, 33(3): 56-59. doi: 10.3969/j.issn.1001-5620.2016.03.011

Abstract(737) PDF (673KB)(210)

Abstract:
The lithology of the "Kumugeliemu Group" in the Block Keshen (Kuche piedmont structure) of the Tarim Oilfield is of compound salt and gypsum having high pressure coefficients. Long open hole drilling and plastic deformation of the formations penetrated made drilling very difficult. Oil base drilling fluids have long been used in the drilling operation. The well KS603 drilled in this area has experienced mud losses at the end of salt and gypsum drilling. To avoid losses of the expensive oil base drilling fluids during casing running, unsaturated brine muds have been used at the end of the drilling of the salt and gypsum formations. In displacing the oil base mud, a thinner solution with high concentration of alkalis is added into the spacer fluid in an effort to maintain a low viscosity of the spacer through the thinning effect of the alkali solution and the neutralization of calcium in the oil base drilling fluid with OH^-. Since lost circulation material (LCM) cannot be added directly into the spacer, the first pit of mud displaced into the hole will be treated with 8% of LCM to avoid losses of the mud. To maintain the borehole stability of the salt and gypsum formations, the displacing mud will be weighted to 2.39 g/cm³, and the chloride maintained at no less than 1.8×10⁵ mg/L to avoid the dissolution of formation salts. NTA-2 is used in the displacing mud to avoid salts from recrystallizing. Before running the casing strings, the compressive capacity of the weak points along the borehole is increased with LCMs to avoid mud losses during casing running. The properties of the displacing fluids have been proved stable by field operations. Wiper trips using drill strings with no centralizers, one centralizer, three centralizers, or four centralizers have been performed without a hitch. After 72 hours of waiting for logging the creeping of the salt and gypsum formations, a wiper trip with four-centralizer drill string, the casing running, and the well cementing have all been done right the first time. The borehole wall has remained stable during the operation, with no downhole troubles occurred.

Modified Natural Polymer Drilling Fluid Used in Exploration Wells in the Gulf of Liaodong

HOU Yue, BAN Shijun, ZHAO Yunlong

2016, 33(3): 60-63. doi: 10.3969/j.issn.1001-5620.2016.03.012

Abstract(565) PDF (1935KB)(200)

Abstract:
The well DS4 is an areal exploration well located in the offshore Gulf of Liaodong in the north Bohai Sea. The well DS4, a long open-hole well, penetrated formations with complex geology and many oil and gas bearing zones. Based on the studies on the inhibitive capacity and plugging capacity of the drilling fluid, as well as reservoir protection mechanism, a modified natural polymer drilling fluid was optimized. The results of the laboratory experiments have revealed that the inhibitive capacity and the plugging capacity of the drilling fluid are greatly enhanced after treatment with the strong shale inhibitor AP-1 and the plugging agent DLP. Using this modified natural polymer drilling fluid, mud losses previously occurred in drilling the highly permeable Minghuazhen formation and Guantao formation were minimized, and the borehole wall instability in drilling the lower Dongying formation (shales) was brought under control with lower mud weights, realizing safe and fast drilling. This drilling fluid has good lubricity; in the second interval, which has length of 3,131 m, horizontal displacement of 1,060 m and well angle of 34.5℃, the wireline logging was 100% successful, with no repetition. The drilling fluid has low fluorescence, which is helpful in pinpointing pay zones accurately. The drilling fluid has good reservoir protection ability; the well DS4 had good oil shows, and high production rate was obtained during well testing.

The Application of Strongly Flocculent Drilling Fluid in Sulige Gas Field

CHEN Zaijun

2016, 33(3): 64-66. doi: 10.3969/j.issn.1001-5620.2016.03.013

Abstract(662) PDF (1092KB)(220)

Abstract:
As the environment protection requirements are becoming more stringent, mud pits for surface circulation of drilling fluid will be completely replaced by mud tanks with which the drilling fluid is circulated at the surface. To clean the mud effectively and efficiently with mud tank circulation, and maintain good drilling fluid properties to ensure safe drilling, a strong flocculent for fast flocculation used in Sulige gas field has been developed, and the formulation of a drilling fluid containing the flocculent is determined. In laboratory experiments, the formulated drilling fluid can effectively flocculate a 100 kg/m³ bentonite slurry in 20 s, finally separating the solids with the liquid. This drilling fluid was tried in the well S47-8-66H2. The length of the well using this drilling fluid is 1800 m, and the average ROP is 27.42 m/h. Compared with the average ROP, 23.00 m/h, obtained in drilling the vertical sections of horizontal wells in Sulige in 2014, an increase in average ROP of 19.22% has been realized. This drilling fluid can be well cleaned through surface tank circulation, providing successful experiences for environment protection through "no drilled cuttings on the ground" at the drilling site in Sulige gas field.

Cement Slurry Treated with Latex Nano Liquid Silica Anti-gas-migration Agent

GAO Yuan, SANG Laiyu, YANG Guangguo, CHANG Lianyu, WEI Haoguang

2016, 33(3): 67-72. doi: 10.3969/j.issn.1001-5620.2016.03.014

Abstract(1040) PDF (6834KB)(270)

Abstract:
Cement slurry treated with latex nano liquid silica anti-gas-migration agent has been studied for the possibility of using it in Shunnan area, where ultra-deep wells have penetrated high temperature high pressure formations. The nano liquid silica anti-gasmigration agent and latex anti-gas-migration agent are both used to synergistically enhance the anti-gas-migration performance of the cement slurry. By optimizing the particle sizes and concentrations of the silica powder, the high temperature stability of the set cement can be improved. Inorganic fibers are added into the cement slurry to stop the development of fractures, thus controlling the losses of cement slurry and improving the shock resistance of the set cement. This cement slurry has good mobility, API filter loss less than 50 mL, right-angle thickening curve, and SPN less than 1. The set cement has good high temperature stability, high bond strength, and high shock resistance. Cement slurry with density of 1.92 g/cm³, after aging at 190℃ and 21 MPa for 30 h, has strength (measured with ultrasonic wave method) gradually stabilized, and interface (between casing string and cement sheath) bond strength of 12.6 MPa. Compared with conventional cement slurry, the elastic modulus of the set cement has been reduced by 52%, and the shock resistance increased by 188%. Striking the set cement with Hopkinson bar has only left several pieces of fractures that do not penetrate the set cement. This cement slurry has been successfully used in the cementing of the well Shunnan5-2 and well Shunnan6, overcoming the difficulties encountered in ultra-deep gas well cementing.

The Application of Phosphate Cement Slurry Used in Cementing In-situ Combustion Reservoir Section of Well X in LKQ Area

XIN Haipeng, WANG Jianyao, ZHOU Zhiqin, HE Shuli, ZENG Jianguo, FU Zhenghua, SUN Fuquan

2016, 33(3): 73-77,83. doi: 10.3969/j.issn.1001-5620.2016.03.015

Abstract(607) PDF (4319KB)(175)

Abstract:
In-situ combustion and fire-flooding have been done by injecting air into the well X in TH oilfield to try to develop the thick oil resources effectively. In this area the reservoir formations have high permeability and mud losses into the formations have occurred frequently before, resulting in poor cementing job quality. Phosphate cement has been chosen for use in well cementing because this cement is resistant to CO₂ corrosion and has good high temperature performance, and the strength of the set phosphate cement measured by ultrasonic sound develops faster. The phosphate cementing slurries are formulated with these additives:phosphate cement BCM-600S, filter loss reducer BCF-600L, cementing retarder BCR-600S and defoamer G603. Laboratory evaluation demonstrates that the phosphate cement slurries are resistant to high temperatures to 550℃ when set, and their high temperature strength can last for a long time. The whole length of the well X was cemented with the phosphate cement slurries, 93.8% of the hole section has been cemented excellently. The phosphate cement can be used in other cementing operations.

Analysis of Gas Migrationin Well Cementing and Cementing Technology for Shallow Gas Wells in ANACO Gas Field

LIU Zhentong, WANG Jun, CHEN Dacang, ZHOU Jian, XIN Zhihong, ZHANG Hongyan, WU Guangfu

2016, 33(3): 78-83. doi: 10.3969/j.issn.1001-5620.2016.03.016

Abstract(645) PDF (987KB)(225)

Abstract:
The ANACO gas field is located in the northeast of Venezuela, and has huge natural gas reserves, almost 60% of the total natural gas reserves in Venezuela. The reservoir formations of the ANACO gas field are of great complexity, with gas zones and water zones extensively distributed from the shallow formations and to the deep formations. Several gas zones with different pressure systems coexist, and have low fracturing pressures, high pore pressures and narrow safety pressure windows. In some parts of the gas field, high pressure gas zones and water traps form high pressure gas pockets and water belts. Wells drilled in this area generally have five intervals to seal off zones of different pressure systems. From the first interval to the third interval, high pressure shallow gas zones exist, and the control of the shallow gas zones is limited by the pressure bearing capacity of the formations. Cement slurries with multiple thickening times cannot be used in cementing the top formations. Several factors, such as large hole sizes, low displacement efficiency, mixing and channeling of cement slurries in annular space, contamination to cement slurries, changes in anti-migration performance, as well as weight loss by gelling of cement slurry, all contribute to poor cementing job, negatively affecting the development of the gas field. The cementing service team hasstudied the stability of cement slurry, static gel strength and SPN coefficient to try to find a way to solve the problems encountered. In field operations, time interval for the development of the static gel strength of cement slurry was controlled within 25 min, and SPN controlled to less than 3, and in cementing casing strings with large sizes, a low flow rate of 0.55 m³/min was used and plug flow maintained during injection and displacement. High density anti-migration cement slurry was also injected into the annular space to displace the contaminated cement slurry, in an effort to thoroughly seal the formation with double thickening times. Using this technology, loss of cementing slurry has been avoided, formation pressure completely brought under control, and gas migration prevented. The quality of the cementing jobs in ANACO gas field has been improved using this technology.

Liner Cementing Technology for Well Moxi009-4-X2 in Block Anyue

ZHANG Hua, WANG Daquan, HU Lin

2016, 33(3): 84-88. doi: 10.3969/j.issn.1001-5620.2016.03.017

Abstract(544) PDF (686KB)(197)

Abstract:
In running the φ177.8 mm liner string in well Moxi009-4-x2, many difficulties have been expected to be encountered, such as high bottom hole temperature, long cementing section, long and active oil and gas shows, drilling fluid of high density that are severely contaminated, and decreased mud density in the next interval, etc. To deal with these difficulties, a high strength high density anti-gas-migration cement slurry and a high performance contamination-resistant spacer fluid have been developed based on the choice of weighting materials and studies on these issues such as the mechanisms of enhancing the toughness of set cement through expansion, the mechanism of cement slurry contamination, and the optimization of cementing techniques. With the cement slurry, the spacer, and the corresponding techniques, the development of the strength of the top cement slurry has been accelerated, and the toughness of the high density set cement has been improved. The contamination of cement slurry and drilling fluid has been minimized, and the bond strengths of set cement with casing string and borehole wall have been enhanced. 94.5% of the liner string cemented has been up to the standard, and the merit factor of cementing job has reached 74.8%. This cementing technology provides a support for the improvement of the quality of well cementing in the area, and a guarantee for the safe and efficient development of the deep high pressure wells in Anyue gas field.

A Quadripolymer Cementing Slurry Retarder for High Temperature Operation

WANG Hongke, WANG Ye, JIN Jianxia, LI Lichang, YANG Yuhang, CHEN Liu, CHENG Haitao, CHEN Shi

2016, 33(3): 89-92. doi: 10.3969/j.issn.1001-5620.2016.03.018

Abstract(525) PDF (1966KB)(338)

Abstract:
A quadripolymer cementing slurry retarder has been synthesized for use in high temperature operations to improve the performance of cementing slurries experiencing temperature changes from intermediate temperatures to high temperatures. The retarder is synthesized with raw materials such as AMPS, acrylic acid, acrylamide, and N, N-dimethyl acrylamide through aqueous solution polymerization. No monomers exist in the final product, as indicated by IR spectrum characterization. Laboratory evaluation of the synthesized retarder has proven that the retarder shows good retarding performance in 80-120℃ and is insensitive to the changes in temperature. At the same temperature, an increase in the concentration of the retarder in cement slurry results in an increase in thickening time, and there is a good linear relationship between the concentration and the thickening time. At 100℃, cement slurry treated with 0.8%, 1.0% and 1.5% of the retarder has thickening time of 161 min, 197 min and 227 min, respectively. At the same concentration, an increase in temperature leads to a decrease in thickening time. At a concentration of 1.5%, it takes 248 min, 227 min and 208 min for the cement slurry to thick at 80℃, 100℃and 120℃, respectively. In 80-120℃, the retarder only slightly affects the compressive strength of set cement. It is resistant to the salt contamination of 18%, and compatible with other cement slurry additives. The working mechanism of the retarder is also analyzed.

Mechanism of Fracture Extension Near Borehole Wall in Deviated Well and Fracturing Technology

HAN Dong, LI Liangchuan, WU Jun, HUANG Jianyi, CHENG Moji

2016, 33(3): 93-97. doi: 10.3969/j.issn.1001-5620.2016.03.019

Abstract(625) PDF (2569KB)(188)

Abstract:
With an increase in well angle, difficulties in fracturing the well is also increasing. The problems encountered in fracturing high well angle wells are low sand concentration, higher pressure, and difficulties in adding proppants into the fracturing fluid in mid- and later-stage of the fracturing job. The fracturing jobs most often fail the design. It has been understood that the main reason for the difficulties in adding proppants is the deviation of the well. Using a large size true tri-axial simulator, the extension of fractures at different downhole conditions were studied. And combining the test results with field operations, the main reason of difficulties in adding proppants into fracturing fluid in mid-or later-stage of fracturing in the deviated wells in the A-fault in Nanpu can be ascertained. Measures to deal with the difficulties have been established, and field operations have been successful, because the concentration of proppants has been increased from 18% to 40%.

The Application of Self-assembled Compound Fracturing Fluid in Horizontal Fracturing

ZHAO Zhongcong, TANG Dongzhu, LI Yan, LIU Jianxin, PENG Tianjie, LIU Zhaojie

2016, 33(3): 98-101. doi: 10.3969/j.issn.1001-5620.2016.03.020

Abstract(646) PDF (1242KB)(222)

Abstract:
To satisfy the needs for low permeability horizontal well fracturing, a compound fracturing fluid has been developed through self-assembly of a comb polymer and surfactant micelles. This fracturing fluid contains no cross-linkers and water insoluble matter. At 80℃, the self-assemble fracturing fluid containing 0.3% co 0 mb polymer CD-1 and 0.2% surfactant has storage modulus of 290 Pa, far greater than the loss modulus, showing an obvious viscous-elasticity. At flow rate of 5 m³/min, the percent reduction in friction achieved with the fracturing fluid is 74.05%, showing an obvious low friction nature. Different self-assembled fracturing fluids all have surface tensions less than 27 mN/m, and interface tensions less than 0.8 mN/m, satisfying the needs for the flow-back of fracturing fluids. Average permeability impairment by these self-assembled fracturing fluids is 18.04%, far less than that of the guar gum fracturing fluids, which is 78.75%. Laboratory evaluation and field application have all indicated that the self-assembled fracturing fluids have high efficiency of friction reduction and low damage to reservoir formation, and higher production rates have been gained using these fracturing fluids. It has also demonstrated the soundness of the theory, which states that through self-assembly of polymers and surfactant micelle, a structure can be developed in the fluid to carry sands. The self-assembled fracturing fluid has satisfied the needs for fracturing wells with special holeprofiles, and provided a new way of developing low permeability reservoirs.

Factors Affecting Friction Loss of Hydraulic Fracturing in Ultra-short Radius Radial Wells and the Calculating Equation Thereof

GONG Diguang, QU Zhanqing, GUO Tiankui, GONG Facheng, TIAN Xuxin, HUANG Zitong

2016, 33(3): 102-106. doi: 10.3969/j.issn.1001-5620.2016.03.021

Abstract(627) PDF (1251KB)(270)

Abstract:
The friction loss testing equipment (composed of friction testing controller, fracturing fluid distributor, speed-controllable screw pump, pipes with varied diameters, high-sensitivity pressure gauge, and electric flow meter) developed by China University of Petroleum (East China) has been used to study the effects of borehole diameters and fracturing parameters on the friction loss of fracturing ultra-short radius radial (URR) wells and to calculate the magnitude of the friction losses of the fracturing fluid. The flow conditions in URR wells were simulated and the friction losses of the fracturing fluids used accurately measured. Analysis of the experiment results shows that factors affecting the friction losses of the fracturing fluids in URR wells are, in the order of decreasing importance, hole diameter, flow rate, viscosity, particle size of proppant, and sand content, and the effects varies in different conditions. An equation for the calculation of friction losses of guar gum fracturing fluid in URR wells has been developed taking into account the aforementioned factors, through the regression fits of 322 sets of data and based on the principle of reducing friction ratios. The standard error of estimate calculated from correlation coefficient testing method is 0.140, indicating that the regression fit equation is valid. It has been found through the experiments that the viscosity of the guar gum fracturing fluid has dual effects on the friction; the viscosity, by increasing the intrinsic shear stress and the shear stress between fluid and the wall of the pipe, increases the friction losses of the fracturing fluid. On the other hand, with an increase in viscosity, a transition delay is being developed in the polymer solution, and the polymer solution has stronger control over the proppants used, thereby decreases the friction losses of the fracturing fluid.

Analysis of the Potential of Generating Acid Sludge in the Dense Reservoir Formations in Block YD (Iran) and the Prevention of the Acid Sludge Generation

GAO Xiang, JIANG Jianfang, MA Feng, CAO Kexue, QI Jing

2016, 33(3): 107-111. doi: 10.3969/j.issn.1001-5620.2016.03.022

Abstract(635) PDF (2819KB)(188)

Abstract:
In reservoir stimulation operations, incompatibility between acids and crude oil leads to the formation of stable emulsions and acid sludge which cause the reservoir formations to be damaged. In analyzing the saturated hydrocarbons, aromatic hydrocarbons, gums and asphaltene components in crude oils obtained from the SV reservoir formation in Block YD, Iran, X-ray and ESEM have been used to study the constituents and micro structure of the reservoir rocks. Laboratory experiments have been performed to determine the compatibility between oil and new acids/pantothenic acids under in-situ conditions. A compound additive for use in acidizing operations has been developed with acid sludge inhibitor, Fe stabilizer and demulsifier. The oil sample taken has a C_Ⅱ of 2.19, indicating the high potential of acid sludge generation. The reservoir rocks, on the other hand, are mainly calcite, having no or little clay components. The permeability of the reservoir rocks remained almost unchanged during water injection. The contact of oil sample with new acids and pantothenic acids generated acid sludge and stable emulsions. The existence of Fe³⁺ in the oil sample increased the amount of acid sludge generated, and the higher the concentration of Fe³⁺, the more the acid sludge generated. Addition of 1% demulsifier FTP-18, 0.5% sludge inhibitor FTZG-01 and 2% citric acid (Fe stabilizer), the amount of acid sludge generated was greatly decreased.

Activated Completion Fluid for Thermal Heavy Oil Recovery

XING Xijin, LIU Shujie, LUO Gang, XIE Renjun

2016, 33(3): 112-116. doi: 10.3969/j.issn.1001-5620.2016.03.023

Abstract(537) PDF (2681KB)(207)

Abstract:
In thermal recovery of heavy oils, after well shut-in, the filtrates of the completion fluids entering the reservoir formations and water from the injected steam will react with rock minerals and formation fluids at high temperature. This reaction will inevitably damage the reservoir formations in contact. To avoid this damage, an activating completion fluid has been introduced. The activating acid, HJS, is used to activate the residue completion fluid in reservoir formations at certain temperature, and hydrogen ions are released to reduce the pH of the reaction system. This will mitigate the dissolution of formation minerals at high pH which is a cause of formation damage. Several additives such as high temperature swelling inhibitor HTW, high temperature friction reducer HUL, high temperature erosion agent HDB and high temperature corrosion inhibitor HJP were chosen and their optimum concentrations determined. With these additives, an activating completion fluid has been formulated. In laboratory experiments, the activating temperature of the completion fluid is 80℃, and the activating time, 60 min. The use of HJS greatly enhances the dissolution of drilled cuttings by the completion fluid. The ratio of swelling of the completion fluid after aging at 220℃ for 8 h is only 1.11%. The completion fluid is compatible with formation waters, and the turbidity of the mixed fluid is between 3.6 NTU and 6.9 NTU. The recovery of permeability after steam (270℃) flooding is greater than 90% (measured at 80℃). These data demonstrate that the activating completion fluid plays a positive role in protecting reservoir formations.

Laboratory Experiments on the Effect of KCl Concentration on Desorption Capacity of Reservoir Rocks

ZHENG Lihui, WEI Panfeng, LOU Xuanqing, SUN Hao, FU Yuwei, NIE Shuaishuai

2016, 33(3): 117-122. doi: 10.3969/j.issn.1001-5620.2016.03.024

Abstract(790) PDF (3177KB)(225)

Abstract:
In studying the damages to shale gas reservoirs, the damages to the desorption capacity of reservoir formations caused by the salinity of drilling/completion fluids have not been studied. In our laboratory studies, a shale piston plunger (diameter=38 mm) made from the Longmaxi formation was used to simulate the reservoir formations. In the experiment, temperature was controlled to 60℃, and confining pressure to 20 MPa. The flowrates of the methane (purity 99.99%) at both the inlet and outlet of the piston plunger were measured every 8 min with gas chromatograph. If the flowrate at the inlet and the flowrate at the outlet were equal, then the piston plunger can be regarded as saturated with adsorbed methane. At initial pressures ranging between 0.001 MPa and 0.01 MPa, the original total desorption volume and rate of desorption were measured for a consecutive 224 min period. The same piston plunger was re-saturated with methane, and the inlet and outlet were sealed with a constant pressure of 3.5 MPa, then inject at the outlet into the piston plunger with KCl solution of 2000, 5000, 10000, 20000 and 40000 mg/L at a rate of 0.1 mL/min, and contaminate the piston plunger for 1 h. Measured the total desorption volume and rate of desorption at the same conditions as when measuring the original total desorption volume and rate of desorption. The measurement for each KCl concentration was tested twice. With an increase in KCl concentration, the average total desorption volume of methane decreased from the original 0.009209, 0.007758, 0.007708, 0.006502 and 0.008027 mmol to 0.000565, 0.004263, 0.004232, 0.003229 and 0.003441 mmol, respectively, and the percentages of damage to the total desorption volume were 93.74%, 45.22%, 44.90%, 50.20% and 57.09%, respectively. The average rates of desorption decreased from the original 0.000041, 0.000035, 0.000040, 0.000029 and 0.000036 mmol/min to 0.000005, 0.000020, 0.000025, 0.000016, 0.000018 mmol/min, respectively, and the percentages of damage to the rate of desorption were 85.78%, 36.87%, 35.42%, 38.88%, 47.34%, respectively. These experiment results demonstrate that the concentration of KCl solution will affect the desorption volume and rate of desorption of the shale gas reservoir rocks, and they provide a reference to the design of drilling/completion fluids and stimulation fluids.

Drill Bridge Plug with a New Fluid in Coiled Tubing Operations in Well JY25-1HF

HE Jibiao, LIANG Wenli, CHEN Mingxiao, CHEN Zhiyuan, LIU Junjun

2016, 33(3): 123-126. doi: 10.3969/j.issn.1001-5620.2016.03.025

Abstract(525) PDF (1871KB)(242)

Abstract:
When drilling the bridge plugs in coiled tubing operations, the limitations from the coiled tubing equipment and the drilling fluids always hinder the return of drilled cuttings which in turn causes problems such as overpressure pumping and pipe sticking etc. To avoid these problems, a polysaccharide polymer has been introduced into the drilling fluid, and, by carefully select materials used in the drilling fluid and performance evaluation, a new drilling fluid has been developed for use in the drilling of bridge plugs. As a power law fluid, the pipe flow of it is of turbulent flow, and flow in annular space is of laminar flow, showing stark contrast with the old drilling fluid which is of turbulent flow both in annular space and in pipe. The new drilling fluid has circulation pressure losses of 1.7 MPa and 0.116 MPa in pipe and in annular space, respectively, while the circulation pressure loss of the old drilling fluid is 0 MPa both in pipe and in annular space. The new drilling fluid has been tried in Well JY25-1HF. The highest pump pressure, 1.80 MPa, was achieved when pumping 10 m³ drilling fluid into the hole, very close to the calculation, with an error of 1.80%. The application of the new bridge plug drilling fluid has demonstrated that it has better carry capacity, more than 3 times of the old drilling fluid, and can be introduced to other area where bridge plugs are to be drilled.

Competent Authorities：China National Petroleum Corporation Ltd

Sponsored by：CNPC Bohai Drilling Engineering Co. LtdPetroChina Huabei Oilfield Company

Editor-in-Chief：Shi-chun Chen

Address： Editorial Department of Drilling Fluid and Completion Fluid, Bohai Drilling Engineering Institute, Yanshan South Road, Renqiu City, Hebei Province

Postcode： 062552

Tel：（0317）2725487　2722354

E-mail： zjyywjy@126.com

CN13-1118/TE

ISSN1001-5620

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