钻井液与完井液

Abstract:
The hydration expansion of clay minerals in shale is an important factor affecting the sidewall stability of shale gas well. The montmorillonite is the main constituent of clay minerals, and its hydration mechanism is very important to solve the problem of borehole wall instability in shale gas well. In order to further explore the hydration mechanism of the montmorillonite under high temperature and high pressure, molecular simulation software was used to study the inter-layer spacing, inter-layer material movement, ionic hydration properties and mechanical parameters of the montmorillonite under different temperature and pressure conditions from a microscopic perspective. The results show that when the temperature increases and the pressure decreases, the inter-layer spacing of montmorillonite augments, and relatively the temperature has a great influence on the inter-layer spacing, which ranges from 1.823-2.042 nm. The diffusion rate of inter-layer water molecules and sodium ions increases with the increase of temperature and decreases with the increase of pressure. The hydration coordination number of sodium ion is large at low temperature and high pressure, and the coordination number varies from 2.35 to 4.35. When the temperature goes up, the volume modulus, shear modulus and elastic modulus of montmorillonite crystal goes down and poisson's ratio increases, while the effect of pressure on the mechanical parameters of montmorillonite crystal is the opposite. It can be seen that the research results of this paper have important theoretical guiding significance for the research of shale formation hydration mechanism under high temperature and high pressure formation environment.

Study of Rheological Dynamics of Water-Based Drilling Fluids at High Temperature and High Pressure

HE Miao, SHI Haohan, XU Mingbiao

2021, 38(3): 271-279. doi: 10.3969/j.issn.1001-5620.2021.03.002

Abstract(487) PDF (2745KB)(156)

Abstract:
In order to ensure the safety of drilling process, it is necessary to have a more profound understanding of the rheological properties of drilling fluid under high temperature and high pressure (HTHP). Polysulfide drilling fluid has excellent performance and is widely used. Experimental research on the rheological properties of drilling fluid under HTHP still needs to be strengthened. Under wide range of temperature and pressure(-180℃, -100 MPa), the rheological properties of the selected water-based drilling fluid were evaluated, and the rheological parameters were quantitatively evaluated and analyzed. The experimental data show that the rheological property of Polysulfide drilling fluid is less affected by pressure than by temperature. By fitting the commonly used rheological models (Bingham model, Power Law model, Casson model, Herschel-Bulkely model and Robertson-Stiff model) in drilling field, the fitting effect of each model is analyzed, and the best rheological model for describing the rheological behavior of the drilling fluid is found out. The results show that both The H-B model and the R-S model can describe the rheological behavior of the drilling fluid under HTHP, and the fitting effect of the H-B model is slightly better than that of the R-S model. The order of the fitting effect of each mode is as follows:Herschel-Bulkely ≈ Robertson-Stiff ≈ Bingham > Casson > Power Law. Based on the H-B model, the optimal fitting equation of rheological parameters with temperature and pressure was obtained from the nine combinations of (T,P), (T,1/P), (T,lnP), (1/T,1/P), (1/T,lnP), (lnT,P), (lnT,1/P) and (lnT,lnP) by direct fitting method and finally the prediction formula of shear stress of polysulfide drilling fluid was obtained. The prediction accuracy of the formula was good, and the relative error rate was mostly concentrated between -7.15%-11.46%, The average error was only 1.03%.

Equipment and Methods of Measuring High Temperature Rheology of Drilling Fluids

LIU Xiaodong, LIU Tao

2021, 38(3): 280-284. doi: 10.3969/j.issn.1001-5620.2021.03.003

Abstract(525) PDF (1372KB)(109)

Abstract:
Since the six-speed direct reading viscometer is unable to measure the change of mud rheology with downhole temperature, downhole pressure, downhole shear rate and time, drilling fluid researchers turn to the high temperature high pressure (HTHP) rheometer for evaluating the rheology and thermal stability of drilling fluids, hoping that it will give more scientific and effective test results. To simulate the actual mud properties downhole, several test methods are established, which are test of low shear rate viscosity, test of loss of viscosity at high temperatures and test of changes of mud viscosity with time at dynamic and static conditions. These tests are used to characterize the cuttings carrying capacity, rheology at elevated temperatures and high temperature stability of drilling fluids at dynamic and static conditions, the test results can reveal the actual rheology of the drilling fluids downhole. Field application of the HTHP rheometer in testing the properties of the organic salt drilling fluid used in drilling the well Chengtan-1 indicated that the test method can be used to provide field engineers with accurate data for judging whether the mud properties can meet the requirements of drilling operation under high bottomhole temperatures. The test method and the HTHP rheometer have provided a scientific and reliable way of designing, developing and using high temperature drilling fluids and mud additives, and greatly made up for the shortcomings and defects of using the six-speed viscometer to measure the rheology of drilling fluids.

A high-temperature and High-Density Environmentally-Friendly Water-Based Drilling Fluids Based on Modified Plant Polyphenols

LIU Ziguang, SONG Fengbo, YOU Zhiliang, ZHUO Lyuyan, PENG Yuntao, XIANG Chunfen, JIANG Guancheng

2021, 38(3): 285-291. doi: 10.3969/j.issn.1001-5620.2021.03.004

Abstract(544) PDF (885KB)(81)

Abstract:
To improve the high-temperature resistance and density upper limit of environmentally friendly water-based drilling fluids, the fluid-loss reducer EHT-FL and the thinner EHT-TH were developed by modifying plant extracts of natural polyphenol. Two synthesized products were characterized by infrared spectroscopy. In laboratory experiments, the fluid-loss reducer EHT-FL and the thinner EHT-TH exhibited good high-temperature resistance. And the EC₅₀ reached 2.38×10⁵ mg/L and 4.49×10⁵ mg/L, respectively, with no biological toxicity. The medium-pressure and high-temperature/high-pressure fluid-loss of freshwater-based mud with 2.0% EHT-FL are only 7.2 mL and 23.6 mL after aging at 200℃. When the dosage of EHT-TH is 1.0%, the apparent viscosity of high-density water-based drilling fluid (ρ=2.0 g/cm³) after aging at 200℃ decreases from 106.5 mPa·s to 66.5 mPa·s, and the high-temperature thickening phenomenon disappears. Based on the excellent temperature-resistance of EHT-FL and EHT-TH, a high-temperature and high-density (ρ=2.0 g/cm³) environmentally friendly water-based drilling fluid has been developed. This drilling fluid has reasonable rheological and fluid-loss properties. It has high-temperature resistance of 210℃ and resistance to 25% salt contamination, 1% calcium contamination, and 10% inferior soil contamination. EC₅₀ of this drilling fluid is 4.19×104 mg/L, BOD₅/COD_Cr is 29.23, heavy metal content is lower than the standard value, non-toxic, biodegradable. Therefore, this environmentally friendly drilling fluid can meet the drilling needs of deep-wells complex formations.

Ultra-High Temperature Drilling Fluid Technology for Drilling Well Jiantan-1

HAO Shaojun, AN Xiaoxu, WEI Xihai, ZHANG Chuang, LI Baoqing, LEI Biao

2021, 38(3): 292-297. doi: 10.3969/j.issn.1001-5620.2021.03.005

Abstract(503) PDF (769KB)(136)

Abstract:
The well Jiantan-1 is a key exploratory well of PetroChina located in the Jianshan structure of the central rhinoplasty belt in the Chaidamu Basin. The main purpose of this 6343 m well is to explore the gas reserves in the base rocks of the Jianshan structure. The highest bottom hole temperature measured is 235℃, one of the highest bottom hole temperatures encountered in onshore drilling. The formations drilled in this area have fractures that are fully developed, long sections of gypsum and mudstones, high pressure saltwater zones, high CO₂ concentrations and high geothermal gradient. Borehole wall collapse, mud losses, overflow, creeping and tight hole in the gypsum/mudstone formations are downhole troubles encountered and sometime intertwined with each other during drilling. To deal with these problems, laboratory study was conducted on several aspects of the drilling fluid used, which are high temperature stability, rheology and high temperature filtration control. An organic salt drilling fluid was formulated with additives specially selected, such as ultra-high-temperature filter loss reducers, anti-collapse additives with plugging capacity, lubricants and thermal stabilizers etc. This drilling fluid is able to resist high temperatures up to 240℃. After aging for 72 hours, the HTHP filtration rate was maintained with 10 mL, the coefficient of friction was less than 0.1, and the invasion depth on a sand-bed less than 12 cm. In addition, the fourth and fifth intervals of the well penetrated formations with micro-fissures and a basal rock weathered crust, and mud losses occurred many times into the fissures. A lost circulation material slurry for the well Jiantan-1 was then developed with choice rigid, flexible and gel-like plugging additives which are suitable for use at elevated temperatures. Using this mud loss control slurry, the pressure bearing capacity of the formations into which mud losses have occurred was finally enhanced. The organic salt drilling fluid and the mud loss control slurry played a major role in preventing and controlling borehole wall collapse and mud losses, ensuring the success of the drilling of the first ultra-high temperature Jiantan-1 well in Chaidamu Basin.

Study on a Lyophobic Nanophase Plugging Agent for Oil Base Muds

NI Xiaoxiao, JIANG Guancheng, WANG Jianhua, YAN Lili, LIU Rentong

2021, 38(3): 298-304. doi: 10.3969/j.issn.1001-5620.2021.03.006

Abstract(529) PDF (13890KB)(80)

Abstract:
Physical plugging with nanophase materials and wettability alteration of rock surface were used to solve the borehole wall stability problem encountered in shale gas drilling with oil base muds. The surface of the nanophase silica was modified sol-gel method, turning the silica into a lyophobic nanophase plugging agent, SNP-1. Molecule structure characterization with NMR and laboratory evaluation with SEM and natural imbibition revealed that SNP-1 gains the functional groups it was expected to have. With SNP-1, the contact angle of liquid on the surface of shale is greater than 150° and the additional capillary pressure is reversed to a force resisting the liquid phase from entering the pore throats of shales, further reducing the oil content of rocks through natural imbibition. The HTHP filtration rate and electrical stability of the oil base mud treated with SNP-1, after being aged at 150℃, were 2.4 mL and above 800 V, respectively, effectively hindering the pressure transmission through shale cores.

Applicability of Methods for Evaluating Temperature Resistance of Foaming Agents Used in Foam Drilling Fluids

YANG Qianyun, WANG Baotian, YANG Hua

2021, 38(3): 305-310. doi: 10.3969/j.issn.1001-5620.2021.03.007

Abstract(366) PDF (2205KB)(54)

Abstract:
The applicability of several methods used to evaluate the high temperature stability of foaming agents was studied in an effort to find the most applicable method for selecting the best foaming agent used to formulate high temperature foam drilling fluids. Three industrial high temperature foaming agents, sodium dodecyl benzene sulfonate (SDBS), sodium dodecyl sulfate (SDS) and sodium α-olefin sulfonate (AOS) were tested and compared using hot rolling method and dry powder heating method, both of which are based on mechanical mixing. Investigation of the effects of temperature on the foaming property of these foaming agents and the stability and rheology of the foaming fluids showed that the same foaming agent evaluated with different methods gives different results. Using the hot rolling method to test at 0-190℃, the performance of SDS is better than that of AOS and SDBS; on the other hand, SDS cannot perform properly at temperatures above 200℃, while AOS and SDBS, after hot rolling at 240℃ for 16 hours, still had good foaming performance. Evaluating the performance of the three foaming agents with dry powder heating method showed that AOS and SDBS, after heating at 260℃ for 4 hours, still foamed, while SDS can only last for 3 hours at 150℃. Based on the evaluation and other tests, it is recommended that hot rolling test method be used to evaluate the performance of foaming agents; with this method, the effects of temperature on the performance of foaming agents can be understood and suggestion can be given to the formulation of foaming fluids used for drilling at different temperatures.

Drilling Fluid Technology for Shale Oil Exploration and Development in Daqing Oilfield

YU Kun, CHE Jian

2021, 38(3): 311-316. doi: 10.3969/j.issn.1001-5620.2021.03.008

Abstract(584) PDF (2575KB)(98)

Abstract:
In this paper the geological characteristics, operation difficulties and mechanisms of borehole wall collapse of the Gulong block in Daqing Oilfield are summarized and analyzed in an effort to solve the borehole wall instability problem encountered in shale oil horizontal drilling in the Qijia-Gulong block. Different measures have been presented to solve different problems encountered for the use of oil base muds, such as borehole wall stabilization, mud rheology control and hole cleaning. Key plugging agents such as SFD-1, non-fluorescent anti-collapse agent BY and Soltex were selected for use in the oil base (water-in-oil) drilling fluid that was used in the past and was now optimized. Laboratory evaluation tests showed that the optimized oil base mud has HTHP filter loss of less than 3 mL and is resistant to the contamination from 30% drilled cuttings. Filed application of this mud on the well ^**2HC in the Gulong block was successful and no downhole troubles have ever happened during drilling. The optimized oil base drilling fluid can be used to solve borehole wall collapse problem encountered in long horizontal drilling, and will have broader prospects of application in shale oil exploration and development in Daqing Oilfield.

Preparation and Performance Study of an Octaamino Star-Shaped Low Molecular Weight Polymer Inhibitor

LIU Fengbao, ZHANG Shuncong, YAN Zhihang, LUO Xiao, DONG Yinghua, SUN Aisheng

2021, 38(3): 317-323. doi: 10.3969/j.issn.1001-5620.2021.03.009

Abstract(480) PDF (2621KB)(59)

Abstract:
The hyperbranched low molecular weight polyamine inhibitors presently in use have some deficiencies such as low density of primary amino groups and lack of inhibitive capacity in high pH environment. To overcome these deficiencies, an octaamino star-shaped low molecular weight polymer (OASS) with regular molecular structure and high density of amino groups was developed through twostep reaction with pentaerythritol as the raw material. Molecular simulation of OASS showed that the adsorption density of OASS on the surfaces of clays is almost the same as that of pentaerythrityltetramine (PTTA) and 3,3-bis(2-aminoethyl)-1,5-pentanediamine (BAPD), but the adsorption energy of a single molecule layer of OASS is significantly greater than that of PTTA and BAPD, indicating that the adsorption centers of the three polyamines on the clay surfaces are all provided by the amino groups, and OASS which has the highest amino group density has the highest adsorption capacity. Test on the adsorption capacity of OASS showed that at 25℃, the saturated adsorption capacity of OASS is only 1.12 mmol/L, and the molar concentration of OASS at saturated adsorption capacity I sonly 10 mmol/L. Laboratory experiment on the capacity of OASS in inhibiting clay yield and linear expansion, and in percent recovery of drilled cuttings in hot roller test showed that OASS is remarkably superior to PTTA and BAPD in inhibiting the yield of shale cuttings. Laboratory experiment also showed that OASS is compatible with filed drilling fluids and does not affect the rheology of the drilling fluids before and after aging. OSAA also helped improve the filtration control property of the drilling fluids. The results of the study have prove d that OASS has excellent inhibitive capacity and is well compatible with different drilling fluids.

Preparation and Performance Evaluation of an Amine-based Silanol Shale Inhibitor

MA Shuangzheng, WANG Guanxiang, ZHANG Yaoyuan, YUAN Pingnan, CHEN Xiaojuan, NAN Yuan, HUANG Yun, MA Ying

2021, 38(3): 324-330. doi: 10.3969/j.issn.1001-5620.2021.03.010

Abstract(461) PDF (7122KB)(60)

Abstract:
An amine-based silanol shale inhibitor Si-HPEI has been developed to deal with the problem of poor high-temperature stability of shale encapsulators encountered in high temperature deep well drilling. To improve the adsorptive capacity at elevated temperatures of a polymer, siloxane groups were introduced into the backbone of a hyperbranched polyethyleneimine (HPEI) molecule to produce an amine-based silanol shale inhibitor. Laboratory evaluation of Si-HPEI showed that Si-HPEI can tolerate clay contamination of up to 35.0%. Hot rolling test with a drilling fluid treated with 0.5% Si-HPEI gave a shale cuttings percent recovery of 70.33%. Si-HPEI functions at 160℃, making it a better high temperature shale inhibitor than conventional shale inhibitors. The working mechanisms of Si-HPEI were analyzed through laboratory experiments such as the measurement of the basal spacing of clays, the high temperature adsorption capacity, the encapsulation capacity, hydrophobicity and micromorphology. It was found in laboratory study that hydrolysis of Si-HPEI produces silanol groups which react through polycondensation with the silanol groups on the surfaces of clays, in this way the Si-HPEI is chemically adsorbed firmly on the surfaces of clay particles. This adsorption is so strong that it is not easy for the Si-HPEI molecules to detach from the clay particles and hence strengthens the forces between the clay particles, effectively encapsulates the clay particles and changes the hydrophobicity of the surfaces of the clays, thereby preventing water molecules from invading between clay platelets which causes hydration and dispersion of clays.

Application of a Clay-Free Low Solids Water Based Drilling Fluid in Block Mi-38 in Changqing Oilfield

LI Xiuling, DU Kun, WANG Benli, ZHAO Huaizhen, LI Qiong

2021, 38(3): 331-336. doi: 10.3969/j.issn.1001-5620.2021.03.011

Abstract(544) PDF (1495KB)(70)

Abstract:

Horizontal drilling has long been used to develop the dense sandstone natural gas reservoirs in the Block 38 in Shenmu gas field (part of Changqing Oilfield) in the north of Shaanxi Province. The drilling fluid used to drill the upper formations had high solids content, which resulted in many problems in drilling the reservoir section, such as difficulties in exert pressure on the drill bit, high friction, borehole wall collapse and resistance to tripping into the hole. Based on the reservoir characteristics of the reservoirs in the Block Mi-38, a clay-free low solids drilling fluid was formulated with carefully selected key additives to address these problems. Laboratory experiment on this drilling fluid showed that this clay-free low solids drilling fluid has good plugging and inhibitive capacity; depth of fluid invasion at HTHP (3.5 MPa, 150℃) into a sand-bed was 7.2 cm, and the length of a shale core had an extension in length of only 0.76 mm after experiment for 16 hours. In field application, this drilling fluid showed good rheology, inhibitive capacity and plugging capacity, satisfying to some extent the needs of drilling the easy-to-collapse horizontal sections of wells drilled in the Block Mi-38 in Changqing Oilfield. Three wells drilled with this clay-free low solids drilling fluid showed low friction and no difficulties in exerting pressure on bit during drilling. Tripping of the drilling pipe into or out of hole was smooth and no downhole troubles have ever been encountered. The drilling time was 10.85 d less than the designed drilling time, casing string was run into the hole with no resistance. Compared with wells drilled nearby, the production rate of gas of a single well drilled with the clay-free low solids drilling fluid was significantly increased.

Misunderstanding of Fractured Shale Collapse Prevention and Plugging Method for Preventing Borehole Collapse

BAI Chuanzhong, LIU Gang, XU Tongtai, XIAO Weiwei, FAN Zhaobo, ZHANG Yongli, MA Fei

2021, 38(3): 337-340. doi: 10.3969/j.issn.1001-5620.2021.03.012

Abstract(463) PDF (4269KB)(89)

Abstract:
In fractured formations, drilling fluids under the action of pressures inside and outside of the borehole wall are very easy to invade the formation along the fracture channels, thereby increasing the pore pressure in the near-wellbore where fractures are quite developed, causing shale to hydrate and swell and strength decrease, increasing the collapse pressure of the formations, and hence exacerbating borehole wall collapse. In dealing with borehole wall collapse occurred in drilling the Shihezi formation and the Shiqianfeng formation in Yan'an gas field, it was found that the borehole wall collapse became more severe when mud weight was being increased. Study on this situation found that the failure of the borehole wall collapse just came from the lack of effective plugging of the fractures in the two formations. Understanding this, a countermeasure of preventing the collapse of fractured formations was developed, which can be described as "plugging the fracture has the top priority, inhibiting the hydration of the formations and using reasonable mud weight". Based on this measure, an optimized drilling fluid with high plugging capacity was developed for use in drilling operation in the Yan'an gas field. The technical clues in this study can be used as a reference for preventing borehole wall collapse in drilling the similar fractured formations.

CEMENTING FLUID

Enhancing High Temperature Mechanical Performance of Aluminate Cement with Plasma-Modified MgO Whisker

XING Xuesong, CHENG Xiaowei, LI Gao, NI Xiucheng, WANG Jinyao, WU Zhiqiang

2021, 38(3): 341-345. doi: 10.3969/j.issn.1001-5620.2021.03.013

Abstract(383) PDF (3907KB)(35)

Abstract:
High brittleness and low tensile strength at elevated temperatures of set cement limits its use in thermal production of heavy oils. In laboratory study, a plasma-modified magnesium oxide (MgO) whisker was used to enhance the high temperature mechanical properties of aluminate cement. It was found through the study that the surface microstructure of the plasma-modified MgO whiskers is rougher than that of the original MgO whiskers, and are thus better bonded with cement to form set cement with improved mechanical properties. After aging at high temperature for 7 days, the set cement containing 2% plasma-modified MgO whiskers has more significant improvement in mechanical performance than the set cement containing 2% MgO whiskers without plasma-modification; the compressive strength and tensile strength of the set cement containing 2% plasma-modified MgO whiskers are 24.5% and 14.1% higher than those of the set cement containing 2% MgO whiskers without plasma-modification, respectively. It was also found that the set cement containing 2% plasma-modified MgO whiskers has better stress-strain performance; it has higher peak stresses and lower elastic modulus. Characterization of the micro morphology of the set cement with whickers with SEM and EDS indicated that the whiskers act on the matrix of cement through crack deflection, whisker fracture and bridging, thereby enhancing the mechanical performance of set cement.

Study on Performance of Low-Density Cement Slurry at Big Temperature Differences

TIAN Ye, SONG Weikai, HOU Yawei, SUN Chao, HAN Bing

2021, 38(3): 346-350. doi: 10.3969/j.issn.1001-5620.2021.03.014

Abstract(314) PDF (2992KB)(46)

Abstract:
When cementing a long well section with big temperature difference between the top and bottom of the section in one stage, it is generally difficult for the top cement to develop strengths in a long period of time. Presently studies are focused on the retarders for big temperature differences, other cement additives for big temperature differences and cementing wells with temperature differences bigger than 100℃ receive less attention. To solve problems encountered in cementing wells with big temperature differences between the two ends of the cementing sections, a 1.4 g/cm³ cement slurry with good performance in big temperature differences was developed based on laboratory study on the properties of filter loss reducers, dispersants and retarders at big temperature differences. It was found in the study that the filter loss reducer C-G86L and the retarder C-H42L show very good performance at big temperature differences. Introduction of butylbenzene latex into the cement slurry helps the development of the strength of the set cement at low temperatures. At temperature difference of 110℃, temperature at the top of cement of 20℃, the compressive strength of the set cement in 48 hours reached 5.92 MPa. The cement slurry was successfully used in cementing a well and the job quality was excellent.

Laboratory Research on 0.9 g/cm³ Ultra-Low Density Cement Slurry

HOU Yawei, TIAN Ye, MA Chunxu, SUN Chao, SONG Weikai

2021, 38(3): 351-355. doi: 10.3969/j.issn.1001-5620.2021.03.015

Abstract(262) PDF (5456KB)(46)

Abstract:
Well cementing with low-density cement slurries is faced with many challenges. By analyzing the requirements of cementing wells with ultra-low formation pressures, an ultra-low density cement slurry was formulated with class C cement, a filter loss reducer C-FL712L and a high performance strengthening material BT5. Laboratory test showed that the cement slurry, with density being adjustable between 0.9 g/cm³ and 1.1 g/cm³, has good overall performance. The slurry has good stability, the density difference between the top and the bottom of a slurry column can be controlled within 0.05 g/cm³. The thickening time of the cement slurry is adjustable. The compressive strength of the set cement at 60℃ can be 7 MPa or higher. The gel strengths of the cement slurry develop fast, and is beneficial to the prevention of gas-channeling. This cement slurry can be used in a wide range of pressures and satisfy the needs of cementing reservoirs and ultra-long sections with low pressures in which mud losses are frequently encountered.

Study and Application of an Quick-Setting Cement Slurry in Cementing Shale Gas Wells in Changning, Sichuan

YAO Ming, LIU Jingli, LU Sanjie, ZHONG Xinxin, LI Lei, YUAN Baoning, ZHANG Yuping

2021, 38(3): 356-359. doi: 10.3969/j.issn.1001-5620.2021.03.016

Abstract(375) PDF (488KB)(32)

Abstract:
Lost return of mud in the top-hole section of shale gas drilling in Sichuan Province were frequently encountered and were difficult to control and stop. A quick-setting cement slurry was developed to deal with this problem. The cement slurry was formulated with a liquid accelerating early strength additive ZQ-3 and a liquid colorless nontoxic dispersant ZF-A. The effect of the mixture of ZQ-3 and ZF-A in cement slurry at different concentrations was evaluated. It was found from the evaluation that the addition of the mixture into a cement slurry helped improve the rheology of the cement slurry. The thickening time was significantly shortened. At 30℃, the ratio of the thickening time of the mixture-treated (3%) cement slurry to the thickening time of the original cement slurry is 0.43. The early strength of the set cement was significantly increased by the treatment of the cement slurry with the mixture of ZQ-3 and ZF-A; the 4-hour compressive strength of the set cement is 3.5 MPa and the 8-hour compressive strength is 8.0 MPa. This quick-setting cement slurry was on 7 shale gas wells for 24 times in block Changning in Sichuan, the wait-on-cement time was reduced from 14 hours to 4-8 hours. All the cementing job was conducted smoothly and total hours of wait-on-cement was reduced by at least 200 hours.

Remedy of Sustained Casing Pressure in φ244.5 mm Casing Annulus in South Oilfield of Iraq

WANG Xiangyu, LIU Wenming, LIN Zhihui, LIU Jinpeng, LI Wenwen, SANG ming, LI Zhongguo

2021, 38(3): 360-364. doi: 10.3969/j.issn.1001-5620.2021.03.017

Abstract(413) PDF (4264KB)(51)

Abstract:
Sustained casing pressure was encountered when cementing the wells penetrating abnormally high-pressure salt/gypsum formations in the Halfaya Oilfield and the Missan Oilfield in the south of Iraq. The sustained casing pressure was in a range of 0.69-17.24 MPa, seriously affecting the later development of the oilfields. A curable epoxy resin was used to solve this problem. Laboratory test was conducted to evaluate the thickening time, compressive strength and rheology of the epoxy resin fluid. The test results showed that by changing the concentration of the solidifying agent in the epoxy resin fluid, the thickening time of the epoxy resin fluid can be adjusted between 100 min and 500 min, the 48-hour compressive strength of the epoxy resin fluid can be greater than 50 MPa, the flow index of the epoxy resin is greater than 0.94, and the consistency coefficient is less than 0.10 Pa·sⁿ. In field operation, the epoxy resin was squeezed and injected stepwise into the well and plug it. The total volume of epoxy resin fluid used was more than 100 L and the plugging operation with epoxy resin was done for three times in three wells. After 72 hours of squeezing the epoxy resin, the wellhead pressure was reduced to zero. Using this method, the sustained casing pressure in the φ244.5 mm casing annulus encountered in the south oilfields of Iraq was successfully solved. This technology can be used to solve similar sustained casing pressure problem.

FRACTURING FLUID & ACIDIZING FLUID

Formulation of a New Acid Fluid for Blocking Removal in Carbonate Formations and Analysis of Factors Affecting Blocking Removal

ZHONG Baohong, ZHONG Zhuangzhuang, GAO Yutian

2021, 38(3): 365-370. doi: 10.3969/j.issn.1001-5620.2021.03.018

Abstract(443) PDF (1939KB)(38)

Abstract:
Drilled cuttings and particles from drilling fluids generally cause severe blocking of the pores in carbonate reservoir rocks. A blocking removal acid fluid was developed to cope with this problem. The acid fluid is formulated with a new ethyl iodosulfonate which was synthesized based on the principles of organic chemistry and the principles of preparing acid fluids. In laboratory test, the effect of several factors, such as HCl content, ethyl iodosulfonate content, temperature of the acid fluid and initial permeability, on the blocking removal performance of the new acid fluid was analyzed using the dissolution rate of carbonate rocks and permeability as the evaluation indices. It was found that increases in the contents of HCl and ethyl iodosulfonate, the temperature of the acid fluid and the initial permeability all are beneficial to the increases of dissolution rate and the permeability of the carbonate rocks; Using the new acid fluid containing 7% HCl, the dissolution rate and percent recovery of permeability of the formation rocks were as high as 96.1% and 111.3%, respectively, far greater than these two indices for conventional clay acid, which are 80.3% and 76.1%, respectively. The existence of ethyl iodosulfonate in the acid fluid helps extend the time for the dissolution of the carbonate rocks, and enhance efficiency of blocking removal, exhibiting excellent blocking removal and environment protection performance.

Study on Instant Low Friction Seawater Based Guar Gum Fracturing Fluids

GONG Dajun

2021, 38(3): 371-374. doi: 10.3969/j.issn.1001-5620.2021.03.019

Abstract(492) PDF (4977KB)(33)

Abstract:
To reduce operation cost, sea water is frequently used to formulate fracturing fluids for fracturing offshore wells. Sea water generally has higher hardness and higher salinity, which are adverse to the viscosity development of fracturing fluids. To solve this problem, a guar gum was first physically modified by molecule reconstruction followed by chemical modification with hydroxypropylation. This physically and chemically modified guar gum of a degree of substitution (D.S.) of 0.45 can efficiently viscosify sea water, with rate of viscosification reaching at 90% in 3 min. Compared with conventional hydroxypropyl guar gum of the same D.S., the molecule-reconstructed hydroxypropyl guar gum viscosifies seawater in an obviously fast manner. By testing the performance of different crosslinking agents, the dendrimer organoboron crosslinking agent was selected because the diffusion rate of boron atoms in the course of crosslinking is low, by using scale inhibitor, the crosslinking process can be delayed, and a gel whose average microgrid size of 40-50 nm was formed. The grid size is greater than the grid size of a gel formed by low molecular weight complex agent instead of dendrimers, and this helps delay the crosslinking rate of guar gum effectively and thus reduces the friction and drag of the fracturing fluid. Laboratory evaluation of the seawater fracturing fluid formulated with molecule-reconstructed hydroxypropyl guar gum and dendrimer organoboron crosslinking agent showed that after aging at 120℃ for 2 hours, the viscosity of the fracturing fluid was 200 mPa.s, greater than the value specified in the industrial standard and the flow resistance was reduced by 80%. The viscoelasticity of this fracturing fluid is greater than the boron-complexed guar gum using low molecular weight complex agents.

Study and Application of Normal Pressure Sand Mixing Quasi-Dry Fracturing Technology

LIU Gang, BAI Xiaodan, MA Zhongguo, ZHENG Yan, YANG Hai, ZHANG Ming

2021, 38(3): 375-379. doi: 10.3969/j.issn.1001-5620.2021.03.020

Abstract(285) PDF (742KB)(29)

Abstract:
As a new CO₂ fracturing technology, the normal pressure sand mixing quasi-dry fracturing technology inherited the unique advantages of the CO₂ fracturing technology. The normal pressure sand mixing quasi-dry fracturing technology does not necessitate special closed sand-mixing equipment and the sand can be mixed at normal pressure. With this fracturing technology, sand is mixed with ease, and drag reducing and sand carrying can be done in an integrated manner. In this paper the background, technical ideas and advantages of the normal pressure sand mixing quasi-dry fracturing technology is set out and analyzed, and the performance of the products and the quasi-dry fracturing fluid are systematically evaluated and studied. Meanwhile, based on the present field application of the normal pressure sand mixing quasi-dry fracturing technology, technical support for the promotion of this new fracturing technology in the future is provided.

Analysis and Countermeasures of Corrosion Cracking of an Oil Pipe

MENG Xuangang, WU Wen, PENG Fen, YANG Zhanwei, WANG Liao, GAO Ying, WANG Liwei

2021, 38(3): 380-384. doi: 10.3969/j.issn.1001-5620.2021.03.021

Abstract(342) PDF (8704KB)(22)

Abstract:
Existing acid corrosion inhibitors are ineffective to eliminate the stress corrosion of acidic high-concentration brines on super 13Cr material oil pipes under high temperature environments. In actual production applications, stress corrosion cracking is caused, and new corrosion inhibitors need to be developed to solve high temperature acids and high temperatures. Stress corrosion of acidic high concentration brine. Based on the research on the corrosion inhibition mechanism of existing corrosion inhibitors, the shortcomings are analyzed, and the corrosion inhibition mechanism of polymerized film formation is proposed, that is, some compounds are used to react with each other under certain conditions in an acid environment to produce a solution containing at least 2 An intermediate product of an active functional group can quickly form a polymer film on the metal surface. Based on this theory, a new type of corrosion inhibitor was developed, which was tested by a high-temperature and high-pressure dynamic corrosion rate measuring instrument. At 180℃, the minimum corrosion rate of 15% hydrochloric acid was 16.0 g/m²·h; four-point bending test confirmed that the corrosion inhibitor was significantly eliminated The stress corrosion cracking of the super 13Cr material test piece produced by acidic high-concentration brine in a high-temperature environment. The new corrosion inhibitor can effectively reduce the stress corrosion cracking of super 13Cr material tubing in ultra-deep high temperature and high pressure gas wells.

COMPLETION FLUID

Preparation and Foaming Properties of N-Alkyl-β Aminopropionic Acid

WAN Liping, XIE Meng, WANG Bohui, ZHANG Xiaolong, ZHANG Li

2021, 38(3): 385-390. doi: 10.3969/j.issn.1001-5620.2021.03.022

Abstract(317) PDF (1077KB)(28)

Abstract:
N-alkyl-β-aminopropionic acid (HA) was synthesized from acrylonitrile and aliphatic primary amine in a ratio of 1:1.1. The structure of HA was characterized by paragon-1000 infrared spectrometer. The foaming properties of HA, anionic foaming agent ABS, nonionic foaming agent AEO and cationic foaming agent CTAB were selected. HA with better foam paerformance was selected to evaluate the properties of temperature resistance, salt resistance, calcium resistance and stability. The experimental results show that the foaming power of HA is not obvious with temperature. At 25℃, the maximum half-life is 14 min, and the foam stability is the best. When pH<3 and pH>7, the foaming volume is larger than 540 mL, the half-life is greater than 5.5 min, the foam performance is much higher than pH=3-7, and the volume of foam changes near 720 mL with the increase of salinity. The half-life continued to extend to 10 min, and the salt resistance was good. With the increase of Ca²⁺ concentration, the volume of foam decreased from 700 mL to 380 mL, but the half-life increased from 7.5 min to 17 min, and the foam stability increased, which could meet the downhole operation of foam fluid.

An Integrated Working Fluid for Blocking Removal and Sand Control in Offshore Wells Blocked by Particle Migration

WU Shaowei, ZHOU Hongyu, LIN Kexiong, YUAN Hui, LUO Gang, HU Youlin

2021, 38(3): 391-396. doi: 10.3969/j.issn.1001-5620.2021.03.023

Abstract(375) PDF (1048KB)(39)

Abstract:
In view of the serious decline in productivity of wells blocked by particle migration in offshore oil fields, the conventional technological measures of sand control after acid plugging removal often have shortcomings such as long operation period, high cost and poor construction effect. Therefore, the integrated technological measures of understanding plugging and controlling sand are studied. With compound organic acid HCW-2, resin HWR301S and curing agent HWR302S as main treating agents, a set of integrated working fluid system for removing blockage and controlling sand suitable for wells blocked by particle migration in offshore oil fields was developed, and its comprehensive performance was evaluated. The results show that the system has strong sand control ability and can still maintain high sand control efficiency under high flow rate (120 mL/min) and long time (720 min) displacement. Injection of integrated working fluid for plug removal and sand control can effectively remove the plug damage caused by particle migration, and the greater the injection flow rate, the better the plug removal effect; In addition, the system has low viscosity, pH value and surface tension, which is beneficial to its injection and flowback. The system has good anti-swelling performance, corrosion inhibition performance and stable iron/calcium ion performance, which can ensure the safety of the construction process and will not cause secondary damage to the formation. According to the comprehensive analysis of the research results, the developed integrated working fluid system for plug removal and sand control can not only remove the blockage caused by particle migration, but also play a good role in sand control, thus achieving the purpose of long-term plug removal and increasing production.

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

LinksMore

Email Alert RSS