钻井液与完井液

Abstract:
Mud loss is a complex problem frequently encountered in drilling operation. Polymer gel is often used as a lost circulation material (LCM) to control mud losses. Conventional polymer gel lost circulation material has poor high-temperature stability and low-pressure bearing capacity, which are not benefit to mud loss control. A new high-temperature fiber reinforced gel LCM has been developed through molecular structure design using monomers such as acrylamide, butyl methacrylate and 2-acrylamido-2-methylpropanesulfonic acid. A flexible fiber was used as reinforcing material and ammonium persulfate as initiator in the synthesis reaction. The intermediate product was then reacted with a high molecular weight crosslinking agent BWL to produce the final product. The effect of the flexible fiber on the rheology of the gel LCM was studied. The gel LCM was studied, with SEM, thermogravimetric analysis and mud pressured loss control test etc. for its micro structure, thermal stability, swelling performance after water absorption and performance in controlling mud losses under pressure. It was found that the existence of the flexible fiber strengthens the spatial network structure of the gel LCM, making it much tougher. The particles of the gel LCM have good thermal stability and swelling property when absorbing water. When water is absorbed, the gel LCM swells and is squeezed into the channels through which mud is lost to stop mud losses. High permeability loss zones sealed with this gel LCM at 140℃ has pressure bearing capacity of greater than 7 MPa, wide fractured zones sealed with this gel LCM had pressure bearing capacity of greater than 5 MPa, indicating that this gel LCM can be used to control mud losses in high temperature high pressure environment.

Gel Microsphere: Synthesis through Inverse Emulsion Polymerization and Evaluation of Its Plugging Capacity

XIANG Ying, WANG Xi, JIANG Guancheng, DENG Zhengqiang, LI Wanjun, YE Yu, ZHOU Haiqiu

2020, 37(3): 275-281. doi: 10.3969/j.issn.1001-5620.2020.03.002

Abstract(958) PDF (9605KB)(99)

Abstract:
A gel microsphere (OBMG) was synthesized with acrylamide (AM) and 2-acrylamide-2-methylpropane sulfonic acid (AMPS) through inverse emulsion polymerization. The molecular structure of OBMG was characterized by infrared spectrum (FTIR) and proton nuclear magnetic resonance spectrum (¹HNMR). Effects on the plugging capacity of OBMG by several affecting factors, such as the HLB value of the emulsifiers in the inverse emulsion system, oil/water ratio, molar ratio of the monomers, the total concentration of the monomers as well as the concentration of the crosslinking agents, were fully investigated. The optimum synthesis condition was found as follows:HLB of the compound emulsifiers=5.0, oil/water ratio=0.64:1, the concentration of the crosslinking agent=0.07% of the total concentration of the monomers, and the total concentration of the monomers=30%. Using gel microsphere produced under these conditions to control mud losses, percent reduction in volume of mud losses under unit differential pressure was 80% (maximum). Study on the effects of the concentration of OBMG on the plugging performance, electric stability and apparent viscosity of oil base muds indicated that at OBMG concentration of 2%-3%, the drilling fluid had the best plugging capacity, meaning that OBMG is beneficial to improving the emulsion stability. In oil base drilling fluids, the plugging performance of OBMG excels modified asphalt and resin microsphere.

A Drilling Fluid Gelling Agent Synthesized with Pentaerythritol as Branching Agent

ZHAO Suli

2020, 37(3): 282-287. doi: 10.3969/j.issn.1001-5620.2020.03.003

Abstract(643) PDF (1102KB)(133)

Abstract:
When using gelling agents to increase the gel strengths of water base drilling fluids, it was found that the increase of gel strengths was generally smaller than the increase of viscosity. A low viscosity high gel strength additive PAAVP has been developed to deal with this problem. PAAVP was prepared by the copolymerization of acrylamide (AM), 2-acrylamide-2-methylpropane sulfonic acid (AMPS) and 4-vinyl-1-(3-sulfopropyl) pyridinium salt (4-VPPS) using pentaerythritol as branching agent and cerium ammonium nitrate as initiator. The effects of copolymerization conditions on the viscosity and gel strengths of PAAVP was studied. Introduction of pentaerythritol into the copolymerization system reduced its apparent viscosity and increased its ratio of yield point to plastic viscosity (YP/PV). The optimum concentration of pentaerythritol was determined to be 2.5%-3.0% (mass) of the monomers for the copolymerization. 4-VPPS is beneficial to the thermal stability and salt resistance of the final product, and its concentration in the copolymerization system was 6%-10% (mass) of the monomers. The concentration of the initiator was 0.0275%-0.03% (mass) of the monomers. 1% water solution of the PAAVP produced in accordance with the recommended mass ratio of reactants had apparent viscosity of 27 mPa·s and YP/PV value of 1.45 Pa/mPa·s. The solution, after hot rolling at 150℃, still had 74% of its original apparent viscosity and 54% of its original YP/PV value, showing better thermal stability than xanthan gum. PAAVP dissolved in 5% NaCl solution had 91% of its original apparent viscosity and 85% of its original YP/PV value, demonstrating potential for future application.

Improve High Temperature Performance of Drilling Starch with Compound Phytophenol

ZHANG Jie, JING Yuntian, ZHU Baozhong, YAO Huangyou, ZHANG Fan, TANG Deyao, CHEN Gang

2020, 37(3): 288-293,300. doi: 10.3969/j.issn.1001-5620.2020.03.004

Abstract(557) PDF (2741KB)(135)

Abstract:
A citrus peel power-starch compound was developed with raw materials citrus peel power and potato starch. A drilling fluid treated with the compound was measured for its apparent viscosity, yield point, filtration control property and adhesion coefficient to find a way of improving the high temperature performance of starch drilling fluids. The working mechanisms of the compound in the drilling fluid was analyzed by particle size measurement, infrared spectrum analysis and thermogravimetric analysis. It was found that a water base drilling fluid treated with 0.3% citrus peel powder (80-120 mesh) and 1.0% potato starch had its high temperature stability at 150℃, filtration control performance and lubricity significantly improved. The working mechanisms are that the phytophenol in the citrus peel powder react with the α polysaccharide in the potato starch to form a phenol-polysaccharide compound which effectively inhibits the high temperature degradation of the backbone of the molecular chains of the polysaccharide in the starch, thereby effectively improving the high temperature resistance of starch. Meanwhile, the hydroxyl group of the cyclohydrin in the polysaccharide molecules and the phenolic hydroxyl group of the phytophenol are able to be adsorbed on the surfaces of bentonite particles in the drilling fluid, forming a hydration membrane, hence inhibiting the hydration and swelling of bentonite.

Technical Difficulties and Case Study of Oil Base Drilling Fluid Operation in Shale Gas Drilling in South Sichuan

ZUO Jingjie, ZHANG Zhenhua, YAO Rugang, PENG Yuntao, WANG Gang, NAN Xu

2020, 37(3): 294-300. doi: 10.3969/j.issn.1001-5620.2020.03.005

Abstract(654) PDF (1714KB)(211)

Abstract:
Shale gas drilling in the south of Sichuan Province has been faced with downhole troubles such as back reaming during POOH in long horizontal section, pipe sticking and mud losses etc. This paper summarizes and analyzes the geological nature and pore and fracture distributions of the Longmaxi shale formation. Technical concerns as to the use of oil base muds are illustrated in this paper, such as plugging of micro fissures in shales, mud rheology control, lubricity of mud in horizontal section to prevent pipe sticking, optimization of mud density, control of low density solids, as well as the prevention and control of mud losses. By analyzing some typical cases, technical challenges as to the use of oil base muds in shale gas drilling are detailed. It is pointed that proper mud density, good mud rheology, good cuttings carrying capacity as well as practical engineering measures play important roles in preventing mud losses and in ensuring downhole safety.

Study on and Application of a Polyamine Drilling Fluid

Zhang Kun, Wang Leilei, Dong Dianbin, Xu Shaoying, Ma hong, Huang Chen, Zhang Peng, Guo Yao

2020, 37(3): 301-305. doi: 10.3969/j.issn.1001-5620.2020.03.006

Abstract(671) PDF (4077KB)(173)

Abstract:
The Minghuazhen Formation drilled in Dagang Oilfield is of highly mud making, making conventional polyamine drilling fluids laden with bentonite when drilling into this formation. High contents of bentonite in the drilling fluid make the bentonite colloid easy to be damaged when conventional polyamines are used, and this problem has been solved using this newly developed polyamine. A drilling fluid formulated with this polyamine has high tolerance to bentonite and works normally at 150℃. Contaminated with 10% bentonite, the drilling fluid still has good rheology. Biotoxicity, biodegradability and metal content of the polyamine all conform to the requirements of environment protection. Using drilling fluids formulated with this newly developed polyamine, the mud-making and borehole wall instability problems have been solved. The well Gang3-52-1, was drilled smoothly and successfully with the polyamine drilling fluid. Compared with wells drilled nearby, the ROP of the well Gang3-52-1 was increased by at least 70%, even though this well was deeper and had higher well angle and longer bottom hole displacement.

Reservoir Protection with Double Hydrophobic Agent in Jilantai Oilfield

QUAN Xiaohu, JIANG Guancheng, LYU Chuanbing, LI Yongjun, ZHANG Yong, QIU Aiming, JIA Dongmin

2020, 37(3): 306-312. doi: 10.3969/j.issn.1001-5620.2020.03.007

Abstract(581) PDF (2707KB)(123)

Abstract:
The Hetao area is a fast deposited super-compensated basin, reservoirs in this area buried in less than 2000 m have notable characteristics of "three lows and one high", that is, low maturity, low permeability, low strength, and high shale content. The reservoir rocks have strong water sensitivity, extremely strong sat sensitivity, poor cementation, non-uniform particle sizes and high shale content. Poor cementation of the rocks makes it difficult to prepare core samples which are easy to break when wash with oils. Poor rock cementation also seriously affects the production rate of crude oil. A double hydrophobic agent and a filming agent were developed to deal with the strong sensitivity and poor cementation problems. Laboratory experimental results showed that a drilling fluid treated with the double hydrophobic agent and the filming agent can be converted into a double hydrophobic drilling fluid without affecting the rheological properties of the original drilling fluid. This drilling fluid is then able to turn the rock surfaces from being hydrophilic to hydrophobic, and coats the borehole wall with a film. In this way the reservoir is protected from the invasion of solids and filtrate and borehole wall is stabilized by the hydrophobic property and plugging behavior of the drilling fluid. The drilling fluid has been used on well Jihua2-209x and well Jihua2-322x, and it was found that with the double hydrophobic reservoir protection technology, the drilling fluid had stable rheology, low filtration rate and strong inhibitive capacity. Borehole wall was stabilized and a gauge hole was drilled. No downhole problems were ever met. Compared with other wells drilled nearby, the two wells were drilled with higher ROP and lower cost. The development and application of the double hydrophobic technology have provided a strong technical guarantee for the safe and efficient development of the Hetao area.

Highly Inhibitive Polymer Drilling Fluid Help Resolved Problem of Low Recycling Rate of Drilling Fluid Use to Drill Fat Holes in ChuanYu Area

FAN Jin, LI Juncai, WANG Jun

2020, 37(3): 313-318,326. doi: 10.3969/j.issn.1001-5620.2020.03.008

Abstract(535) PDF (4487KB)(135)

Abstract:
Drilling fluids used to drill fat hole in ChuanYu area always have high density, high viscosity and high content of poor-quality solids, making them difficult to reuse. Disposal of them as waste drilling fluids greatly increases operational cost and environmental risks. Analyses of the mineral components of formation rocks taken from the fat hole sections show that the clay minerals in the rock contain more than 70% illite and illite/smectite mixed layer mineral. Exchangeable cations, such as calcium and magnesium ions, are adsorbed onto the surfaces of clay particles, rendering clay particles high activity and hydrophilicity. These clay particles are thus very easy to hydrate, swell and disperse when in contact with water. Mudstone samples were taken from the Sha2 member in Moxi, ChuanYu area for inhibition test. Since calcium ions inhibit clay hydration by reducing water activity and suppressing electric double layer of clay particles, a mechanism different than that of potassium ions, it was concluded that the synergy of calcium ions and potassium ions is better than using just calcium ions or potassium ions to inhibit clay minerals. An optimum ratio of calcium ions over potassium ions was selected through laboratory experiment. By introducing intercalation and hydrophobic inhibitive agents into the drilling fluid, it was found that a drilling fluid with optimum concentration of calcium/potassium, intercalation and hydrophobic additives has the strongest inhibitive capacity. Based on this idea, a highly inhibitive polymer drilling fluid was formulated with selected inhibitive additives and WN2-2, a salt-resistant polymer. Tis drilling fluid is suitable for use to drill the fat hole sections in ChuanYu area. It has very strong inhibitive capacity, greatly inhibit the clay formation from hydration and dispersion. Comparison of the drilling operation of the well Mox-009, well Moxi-022 and well Moxi-019 shows that the highly inhibitive polymer drilling fluid, which was used to drill the well Moxi-019, was recycled by 75%, while the drilling fluids used to drill the other two wells were not recycled. This highly inhibitive polymer drilling fluid is worth spreading for its high rate of recycling.

Mud Losses in Well Xianxi-2: Characteristics and Control

XIONG Zhan, WANG Helin, ZHANG Minli, ZHONG Dehua, HE Yongbo, LI Guangji

2020, 37(3): 319-326. doi: 10.3969/j.issn.1001-5620.2020.03.009

Abstract(476) PDF (550KB)(180)

Abstract:
The third interval of well Xianxi-2 has found serious mud losses during drilling which is difficult to control.Totally 5182.45 m³ of drilling fluids were lost in 18 times of mud losses. Two times of pipe sticking were encountered during mud loss control. Drilling operation was badly hindered because of these downhole troubles. The well was temporarily abandoned after comprehensive evaluation of the risks in drilling ahead.By analyzing the mud loss behavior as well as the mud loss control techniques adopted, such as mud loss control with bridging method,solidification method, drilling through loss zones with balance, and sealing of water zones, and by summarizing the experiences and teachings obtained in the operation, a set of feasible technical clues for safe and fast drilling operation in this block and the like was presented.

A Highly Resilient Borehole Wall Strengthening Plugging Agent

WANG Tongyou, ZHANG Wei

2020, 37(3): 327-331. doi: 10.3969/j.issn.1001-5620.2020.03.010

Abstract(425) PDF (12412KB)(108)

Abstract:
Borehole wall stability is a prerequisite for safe and smooth drilling, and also a key point and a difficult problem worth attention in drilling operation. Elastic graphite, because of its unique resilience, has unparalleled advantages in strengthening and plugging borehole walls. PF-RG is an elastic graphite borehole wall strengthening plugging agent produced independently in China. It is completely inert, nonmagnetic and high temperature resistant. It can be used both in water base drilling fluids and oil base drilling fluids, without affecting their rheology property. It reduces the friction coefficient of drilling fluids. Drilling fluids treated with PF-RG have their filtration rate greatly reduced. High pressure elasticity test results showed that PF-RG has very high resilience, with its rate of resilience greater than 20% to 100%, the maximum, equivalent to similar products produced abroad. PF-RG has been successfully used in field operations, proved that its good pressure bearing capacity has been accepted by those who have used PF-RG.

A Magnesium Oxychloride Cement Slurry for Controlling Loss of Oil Base Drilling Fluids

YU Ling, LIU Weihong, XU Mingbiao, SONG Jianjian, ZHOU Wen, DENG Yahui

2020, 37(3): 332-336. doi: 10.3969/j.issn.1001-5620.2020.03.011

Abstract(544) PDF (1022KB)(162)

Abstract:
Magnesium oxychloride cement has excellent mechanical and thermal performance and is widely used in industrial flooring, fire control, grind wheel making and wall insulation. Conventional cement has some disadvantages as well cementing material such as poor contamination resistance, poor acid solubility and inability to deal with severe mud losses. To resolve these problems, a magnesium oxychloride cement slurry was developed using DISP-S as dispersant, and DOT and Atmp compound as retarder. The set magnesium oxychloride cement has polycrystalline phase in it and the slurry is able to deal with severe loss of oil base mud. Laboratory experimental results showed that a magnesium oxychloride cement slurry of 1.76 g/cm³ has very good settling stability, zero free water, filtration rate of less than 40 mL, thickening time of 230 min at 60℃, and set cement with compressive strength of greater than 30 MPa in intermediate and low temperatures. The set cement, even mixed with some invading oil base mud, still maintains certain level of mechanical properties, and is able to dissolve completely in concentrated hydrochloric acid.

Patterns of Salinity Sensitivity of Heterogeneous Carbonate Reservoirs in Shunbei Oil and Gas Field

PAN Lijuan, DU Chunchao, LONG Wu, WEI Panfeng, HUANG Zhijuan, ZHANG Wang

2020, 37(3): 337-344. doi: 10.3969/j.issn.1001-5620.2020.03.012

Abstract(418) PDF (2897KB)(105)

Abstract:
Large amount of fracture reservoirs are produced in Shunbei oil and gas field because of the effects of the multi stage movement of faults, rendering the reservoirs characteristics of fractured vuggy carbonate. Evaluation of the salinity sensitivity of carbonate reservoirs in Shunbei showed that a unified conclusion cannot achieved with data of many samples, and is thus unable to guide field production. Whole mineral content measurement with XRD showed that the total content of minerals (including calcite, dolomite, silica and clay) along the vertical direction of the Yijianfang formation and the Yingshan formation reservoirs changes between 0.9% and 65%. SEM observation showed that the formation fractures are filled with plate-like illite-smectite mixed layers, and the quantity and shape of the fractures are randomly distributed. The vertical porosity and permeability of 2 sets of reservoir rock samples measured with helium and nitrogen are 0.42%-2.40% and 0.03-7.62 mD, respectively, indicating obvious fluctuation in the distribution of porosity and permeability, and small total porosity. Permeability impairment by water sensitivity and salt sensitivity of the Yijianfang formation rocks is 29.47%-74.80% and 30.44-82.93%, respectively, and for the Yingshan formation rocks, the data are 66.06%-75.80% and 78.10%-79.91%, respectively, indicating that mineral components and fracture development resulted in obvious fluctuation in salinity sensitivity in different areas. A mathematical model was developed to quantitatively describe the relationship among several factors, such as ratio of permeability loss, salinity range in which formation porosity and permeability are not impaired, total content of clay minerals, porosity, permeability and salinity of formation water. The mathematical model can be used to evaluate the salinity sensitivity of reservoir rocks with comprehensiveness and rapidity. Compared with conventional methods, the percent reduction of permeability of contaminated reservoir was reduced by 19.90% using the critical concentration of KCl calculated with this model, an obvious controlling effect of increasing salinity sensitivity.

CEMENTING FLUID

Running Suspended Cement Plug to Temporarily Isolate Reservoir in an Offshore HTHP Horizontal Gas Well

YANG Yuhao, Wang Chenglong, HAN Cheng, WU Jiang, LI Wentuo, ZHANG Wandong

2020, 37(3): 345-350. doi: 10.3969/j.issn.1001-5620.2020.03.013

Abstract(776) PDF (1319KB)(115)

Abstract:
Suspended cement plug was run in a high temperature high pressure (HTHP) horizontal well in the west of South China Sea to temporarily isolate the HTHP reservoir. The cement plug was required to run in the highly deviated HTHP hole section, the bottom of which was only 150 m (MD) or 40 m (TVD) away from the reservoir penetrated by a horizontal slim hole section. Caution should be taken to prevent slurry channeling and loss during injection of cement slurry because of pressure fluctuation on the bottom of the hole. Cement plug run into a well drilled with high density oil base mud makes mud cake cleaning very difficult and the quality of cementation is thus reduced. If low volume of cement slurry is used, the cement slurry is easy to get contaminated by drilling fluid. Several measures were taken to avoid these problems, such as converting the drilling fluid in advance, optimizing pipe structure for slurry injection, increasing the support capacity of the cement plug, optimizing the prepad fluid, cement slurry composition and surplus volume of cement slurry, improving displacing efficiency, optimizing volume of displacement and technique of displacement and using new technology of cleaning the internal pipe wall of the cementing slurry injection string etc. With these measures, a set of technology for running suspended cement plug in offshore HTHP horizontal gas well to isolate reservoir was presented. This technology has been successfully applied on 7 HTHP horizontal wells drilled in the Ying-Qiong basin, west of South China Sea, providing a technical reference for running suspended cement plug in HTHP highly deviated holes drilled with high density oil base mud.

Numerical Simulation of Failed Bonding between Cement Plug and Casing String in Abandoned Wells Based on Cohesive Element Method

JIANG Jiwei, LI Jun, LIU Gonghui, LIAN Wei, YANG Hongwei

2020, 37(3): 351-357. doi: 10.3969/j.issn.1001-5620.2020.03.014

Abstract(445) PDF (2542KB)(85)

Abstract:
Failure of bonding between cement plug and casing string in abandoned wells imposes a rigorous challenge to the borehole integrity. A 3D finite element model of cement plug, casing string, cement sheath and formation was established to simulate the stripping process of cement plug-surface of casing in vertical wells, to study the effects of geostress on the evolution of failure of the interface between cement plug and casing string, and to analyze the effects of horizontal geostresses, mechanical parameters of cement plug and the property of the interface on the height of the stripping fractures. The establishment of the 3D finite model takes into account the fluid-solid coupling effect between underground fluids and cement plug and is based on Cohesive element method. It was found in the study that when the horizontal geostresses are uniform, the stripping fractures extend along the entire circumference of the interface and have the same height. When the elastic modulus of the cement plug is reduced from 30 GPa to 1 GPa, the height of the stripping fracture is decreased by 9.3 m. When the critical normal strength is increased from 0.25 MPa to 2.0 MPa, the height of the stripping fracture is reduced by 6.5 m. These data indicate that low elastic modulus and high critical normal strength are beneficial to the mitigation of failure of bonding between cement plug and casing string. When the Poisson's ratio of the cement plug is reduced from 0.35 to 0.10, the height of stripping fracture is reduced only by 2.0 m. When the critical shear strength is increased from 0.5 MPa to 4.0 MPa, the height of stripping fracture is reduced only by 3.3 m, indicating that Poisson's ratio and critical shear strength play a minor role in the failure of the bonding. The model established is believed to be instructive to the optimization of cement slurry composition and techniques for well abandonment.

Mechanism Investigation and Performance Evaluation of Water Indispersible Cement Slurries

WANG Jianyao, TU Siqi, MEI Mingjia, XIN Haipeng, SUN Fuquan, ZOU Shuang

2020, 37(3): 358-362. doi: 10.3969/j.issn.1001-5620.2020.03.015

Abstract(542) PDF (2827KB)(104)

Abstract:
The working mechanisms of water indispersible cement slurries are investigated in the light of colloidal stability theory, electric double layer compression theory and principle of bridging by adsorption. The bridging cohesion effect of an indispersible flocculant BCY-100S on cement particles was proved by SEM analysis. By evaluating the effects of many drag reducers on the rheology and dispersion resistance of water indispersible cement slurries, a drag reducer BCD-220S, which helps improve the rheology of cement slurry and does not affect the dispersion resistance of the same, was selected. Three water indispersible cement slurries with water/cement ratio of 0.45, 0.47 and 0.50, respectively, were tested for their dispersion resistance, mechanical performance and comprehensive performance under 30-80℃. It was found that increase in water/cement ratio did not affect the dispersion resistance of the water indispersible cement slurries. The water indispersible cement slurries had free water of 0 mL, density difference of the top and the bottom cement slurries of less than 0.03 g/cm³, mobility of greater than 20 mL, filtration rate that can be controlled in less than 50 mL, and mechanical properties that satisfied operation requirements.

A 350 ℃ High Temperature Silicate Cement Slurry Used in Cementing Heavy Oil Thermal Production Wells

ZHANG Hua, JIN Jianzhou, LIU Mingtao, XIAO Yunfeng, ZHANG Xiaobing, GUO Jintang, ZHANG Tongying

2020, 37(3): 363-366. doi: 10.3969/j.issn.1001-5620.2020.03.016

Abstract(546) PDF (2435KB)(136)

Abstract:
Conventional cement slurries with sand have loose structures and low compressive capacity at high temperatures such as 350℃ in heavy oil thermal production wells. Aluminate cement and phosphoaluminate cement are expensive, while silicate cement always cause contamination to the reservoir formations. Based on the understanding of high temperature strengthening mechanism, some special strengthening additives were developed. These additives, plus some silicate additives, were used to formulate a cement slurry that is resistant to 350℃ high temperature to deal with the problems as said above. The general performance of the cement slurry was tested, the composition of the crystal phase of the cement was analyzed with XRD, and the morphology of the crystal phase was analyzed with SEM. It was found that the high temperature (HT) silicate cement slurry had top and bottom density difference of less than 0.02 g/cm³, zero free water, API filtration rate of less than 50 mL, and mobility of greater than 20 cm. The 24 h compressive strength of the set cement of the HT silicate cement slurry at 70℃ was greater than 14 MPa, and the compressive strength of the set cement in three rounds of test was greater than 40 MPa, indicating that the HT cement slurry has stable long-term strength development, and therefore satisfies the requirement of heavy oil thermal production. Silicate cement slurry used in previous ultra-high temperature operations had low strength, to have high strength, expensive aluminate cement or phosphoaluminate cement had to be used. With the development of the high temperature silicate cement, all these difficulties have diminished, and progress in ultra-high cement slurry technology has been made.

A High Temperature Stabilizer for Set Cement

LIU Jingli, PENG Song, HE Wu, Zhang Ming, HUO Rujun, JI Weiqiang, YANG Yuhang, FU Yueying

2020, 37(3): 367-370. doi: 10.3969/j.issn.1001-5620.2020.03.017

Abstract(537) PDF (726KB)(98)

Abstract:
A high temperature stabilizer has been developed for use in cement slurries to deal with decline of compressive strength of common set cement with sand at elevated temperatures. This stabilizer is well compatible with other additives in cement slurries and has no side effects on the thickening time and the development of the strength of the set cement at room temperatures. A set cement treated with this stabilizer had compressive strength that did not decline at elevated temperatures (320℃ and 450℃, respectively), showing better properties than set cement with sand and ultra-fine silica set cement. Cement slurries treated with this high temperature stabilizer had good cementation strength, which is 4 times of the cementation strength of cement sheath formed by cement slurries with sand, and 3.5 times of the cementation strength of the ultra-fine silica cement sheath. Operation of two wells with this high temperature stabilizer in Block Menggulin was successful and good well cementing job was performed, the cementation between the casing string and cement sheath as wells as the cementation between the cement sheath and the borehole wall were satisfactory, indicating that the high temperature stabilizer has good application prospect.

Normal Injection, Reverse Squeeze and Intermediate Diversion: A Technology for Cementing the Complex Well **1-H*

DANG Donghong, GUO Wenmeng, LI Lijun, LI Dong, SHEN Lei, MA Qianyun, CHEN Dacang

2020, 37(3): 371-376. doi: 10.3969/j.issn.1001-5620.2020.03.018

Abstract(482) PDF (2043KB)(113)

Abstract:
The second interval of the well **1-H* penetrated the Neogene N₂k, N_1-2k, the upper N₁j (claystone, interbeds of sand shale and sandy conglomerate) and the lower N₁j (claystone, sandstone and interbeds of gypsum and claystone), and was drilled to the top of the Paleogene E_2-3s formation (claystone), providing conditions for drilling the third interval. Several high pressure water zones are found between 5065 m and 5360.53 m of the second interval, with overflow of well at static condition when mud weight was 1.51 g/cm³. Mud loss was encountered at pumping between 5318 m and 532,51 m, and there was only 2.47 m of claystone worked as a baffle layer. The drilling process of this interval and wireline logging were accompanied by the continual well killing and mud loss control because of the coexistence of mud loss and overflow in the same interval. This interval was drilled to 5363 m and was cased with φ244.5 mm casing string. A cement slurry with anti-channeling agents for invasion resistance, LCM, enhanced toughness, three setting points, double densities and salt resistance was used in the well cementing job. Normal injection, reverse squeeze and intermediate diversion were taken to ensure the success of the well cementing job. The quality of the well cementing job met the designed requirements.

FRACTURING FLUID & ACIDIZING FLUID

The Countermeasure of Low Cost and High Efficiency Fracturing Technology of Normal Pressure Shale Gas

LIU Jiankun, JIANG Tingxue, BIAN Xiaobing, SU Yuan, LIU Shihua, WEI Juanming

2020, 37(3): 377-383. doi: 10.3969/j.issn.1001-5620.2020.03.019

Abstract(466) PDF (3828KB)(126)

Abstract:
The normal pressure shale gas is widely distributed in the southeast of China. It has the characteristics of low rock brittleness, low initial scale of fracture, low gas abundance, high adsorption ratio and low pressure coefficient. Fracturing is confronted with the difficulties of low crack complexity, limited transformation volume and insufficient long-term conductive ability, resulting in low production and diminishing fast, which has affected the economical and effective development of normal pressure shale gas. From the angle of the fracturing engineering, in order to improve the unit volume of fracturing and the long-term conductive ability of multi-scale fracture, on the basis of fracturing stimulation, the cost of engineering is further reduced and the countermeasure of high efficiency fracturing technique is put forward. The first countermeasure is fracturing stimulation technology. It puts forward the model of plane perforation, improve the stimulation strength and the the induced stress interference range, the degree of fracture complexity and SRV(18%-20%) is improved, the effect of stimulation is obvious(three years of production increase 28.5%). The technology of multi-scale fracture creation and alternating injection acid is proposed to further increase the effective fracturing volume and fracture complexity. The multi-component combination adding sand mode is proposed to improve the width and filling degree of the proppant in the crack, and improve the long-term conductive ability. The second countermeasure is the cost reduction technology. Through the elaborate simulation of fracture creation mechanism, the inefficient liquid was reduced(single cluster saving 20%-25%) and the inefficient fracturing construction was avoided. The cost of fracturing materials is further reduced by the comprehensive application of a multi-effect fracturing fluid system and mixed proppant. The results provide theoretical basis for low cost and high efficiency fracturing of normal pressure shale gas, and improve the science and effectiveness of fracturing.

Preparation of Fracturing Fluids with Hot Water

WANG Hongke, LIU Yin, HE Wu, ZHOU Guanglong, LU Wei, JIN Jianxia, LIU Yuchen, LI Xingbao

2020, 37(3): 384-388. doi: 10.3969/j.issn.1001-5620.2020.03.020

Abstract(465) PDF (2840KB)(125)

Abstract:
Reservoirs in the Fuer member in Subei basin produce oils with high pour point, no asphaltene and low sulfur. Fracturing fluids prepared with water of normal temperature render "cold" damage to the producibility of the reservoirs. By optimizing the method of preventing "cold" damage from fracturing operation and analyzing the mechanisms of dispersion of guar gum in hot water, a fracturing fluid was prepared with hot water. Studies were performed on the effects of hot water on the properties of guar gum fracturing fluid, such as apparent viscosity, time for swelling, shear viscosity, time of sand suspending, viscosity of fluid with gel broken as well as core damage etc., and a technology of preparing fracturing fluid with water of 70℃ was established. Field application showed that the fracturing fluid prepared with hot water effectively prevented "cold" damage to the reservoirs. Production rate of oil after fracturing job was 6.8 m³/d, 2 times of the production rate of the reservoirs fractured with fracturing fluids prepared with water of normal temperature, demonstrating that the hot water fracturing fluid has presented good potential in enhancing oil recovery.

Research on Rheological Properties of Triethanolamine Modified Hydroxypropyl Guar Gum Solution

TANG Luxin, FANG Bo, ZHANG Xiaoqi, WANG Yiqing

2020, 37(3): 389-393. doi: 10.3969/j.issn.1001-5620.2020.03.021

Abstract(622) PDF (2549KB)(94)

Abstract:
A crosslinked gel was obtained by using triethanolamine-modified hydroxypropyl guar gum as a thickener, and triisopropanolamine/lactic acid/glycerol organic zirconium as a crosslinking agent. The rheology properties of the cross-linked gels and the crosslinking processes of triethanolamine-modified hydroxypropyl guar solution were studied. The viscosity and viscoelastic modulus varying with time in crosslinking process were obtained. The effects of temperature on the crosslinking process were investigated. The solution properties in static cross-linking processes were studied by NMR imaging analyzer, and the relationship of relaxation time varying with time was obtained. The results show that the gels demonstrate obvious viscoelasticity and thixotropy and have good sand-carrying properties. The viscosity and viscoelastic modulus of the modified solution varying with time during the crosslinking process can be described by 4-parameter crosslinking process rheokinetic equation. And 4-parameter static cross-linking process kinetic equation can better describe the relaxation time varying with time in static cross-linking process. The model parameters have clear physical meaning.

COMPLETION FLUID

A New Low-Cost High-Density Solids Free Anti-Scaling Compound Salt Kill Mud

QIANG Jie, DONG Jun, YIN Ruixin, YANG Jianlin, HAN Enjun, LIU Enshan, ZHANG Zufeng, SHAO Yanfeng

2020, 37(3): 394-397,404. doi: 10.3969/j.issn.1001-5620.2020.03.022

Abstract(450) PDF (1628KB)(134)

Abstract:
Bromide, zinc salts and heavy calcium salts used in kill mud for HTHP reservoirs have poor compatibility with formation waters, formation contamination and high corrosivity. High density kill muds formulated with formats are quite expensive. A new weighting agent was recently developed with the help of efficient scale inhibiting technology. Using this weighting agent, a low-cost high-density solids free anti-scaling compound salt kill mud was formulated. The base fluid of the kill mud was formulated with some cheap inorganic salts. This kill mud is free of calcium and magnesium ions, all salts presented in the kill mud are monovalent salts. The maximum density of the kill mud is 1.70 g/cm³. This kill mud, with its cost being only 50% of a formate kill mud of the same density, retains all the advantages of the formate kill mud. The new kill mud is low damage, lost cost, high density, solids free and nontoxic., satisfying the requirements of the new national safety and environment protection laws. Pilot test of the new kill mud on a well drilled in Dagang Oilfield showed that the average yield recovery period of the well was 1 d and the average percent recovery of yield was 100%, demonstrating that the kill mud has the capacity of reservoir protection.

The Corrosion Behavior of Tubing and Casing Steels in Formate-Phosphate Compound Completion Fluid

MA Lei, YUE Xiaoqi, ZHAO Mifeng, ZHANG Huijuan, XING Xing, WANG Hua, ZHANG Lei, LU Minxu

2020, 37(3): 398-404. doi: 10.3969/j.issn.1001-5620.2020.03.023

Abstract(764) PDF (13057KB)(69)

Abstract:
The corrosion behavior of the 13Cr super-martensitic stainless steel (tubing steel) and P110 carbon steel (casing steel) in completion fluid formulated with potassium formate and potassium pyrophosphate in different volumetric ratios was studied with high temperature high pressure simulated soaking test method. It was found in the test that corrosion of the 13Cr super-martensitic stainless steel in the compound completion fluid comes from the inclusion of S element in the steel; enrichment of S in the product film of the steel is the major factor for the deterioration of its corrosion resistance. For the P110 carbon steel, the corrosion product at high temperatures is thick and loose. An increase in the ratio of formate in the compound completion fluid can mitigate the deposition of corrosion product on the surface of the P110 steel, thereby enhancing the tightness of the product film and improving the high temperature corrosion resistance of the steel.

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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