2017 Vol. 34, No. 4

Display Method:
2017, 34(4)
Mechanisms and Evaluation of Coal Gas Bed Damage
YOU Lijun, LIN Zilan, JIANG An, KANG Yili, CUI Kaixiao
2017, 34(4): 1-8. doi: 10.3969/j.issn.1001-5620.2017.04.001
Coalbed methane (CBM) has great reserves in the world, and thus has great development potential. Unlike the production of conventional oil and gas, there still have no methods and performance parameters for evaluating damages caused to CBM-bearing formations. In this paper, based on the characteristics of coalbed gas formations, the types and mechanisms of formation damages are analyzed, and single-parameter evaluation methods presently used worldwide are summarized. These methods have been used to evaluate the damages caused to coalbeds with a single parameter, such as the desorptivity, diffusivity and filtration performance, respectively. The advantages and disadvantages, and the applicability of each method are also analyzed. The main damages to coalbed include stress-induced damage, solids invasion into and block of fractures in coalbed, retention of adsorbed polymer molecules, alkalinity-induced damage, and damage caused by migration and block of coal powders etc. Formation damage to coalbed not only affects water drainage, it also affects gas production, and the water draining ability of coalbed also affects gas production. Coalbed damage evaluation with measuring of single-process mass transfer is not an all-round method, and a method combining single-process mass transfer and the multiple-process mass transfer is urgently needed. Nonetheless, the evaluation of the coalbed permeability is the key to a method. Damage to the flow of water in coalbed with gas adsorption is another factor that should be considered in designing the evaluation method.
Synthesis and Evaluation of a New Graphene Oxide High Temperature Filter Loss Reducer
QU Jianfeng, QIU Zhengsong, GUO Baoyu, ZHONG Hanyi, WANG Weiji, MAO Hui
2017, 34(4): 9-14. doi: 10.3969/j.issn.1001-5620.2017.04.002
A GO/polymer filter loss reducer GOJ was made through copolymerization of graphene oxide (GO), acrylamide (AM), 2-Acrylamido-2-methylpropane sulfonic acid (AMPS), dimethyl diallyl ammonium chloride (DMDAAC) and vinyl acetate (VAC). Characterization of the synthesized product with IR and TEM photography showed that there are pentacyclic structure and amide group, sulfonic group, hydroxyl group in the GOJ molecules. GOJ has relative molecular weight of about 3.63×105. Observed under the microscope, GOJ has dark color and a levelling platy structure. Drilling fluid laboratory experiment showed that GOJ has good filtration control property. A fresh water base drilling fluid treated with 0.2% GOJ has its API filter loss reduced by 70%, indicating that the performance of GOJ is better than PAMS601 and JT888. GOJ has good salt resistant, and can be used in saturated salt drilling fluid. At the same concentration in drilling fluid, the filtration rates of the drilling fluids treated with GOJ under 180℃, 200℃ and 220℃ are all lower than that of the drilling fluids treated with Driscal-D under the same temperature, respectively. Graphene oxide has the ability to enhance the temperature resistance of GOJ; when GOJ contains 0.32% graphene oxide, the temperature resistance of GOJ is increased by about 20℃, and with the increase of the content of graphene oxide in GOJ, the high temperature filtration control performance of GOJ is also increased.
Synthesis and Evaluation of a Submicron Solid Flocculant GCS
JIANG Guancheng, LI Xinliang, PENG Shuanglei, ZHAO Li, LI Gongrang, ZHANG Jinghui
2017, 34(4): 15-19. doi: 10.3969/j.issn.1001-5620.2017.04.003
Submicron solids laden in drilling fluid as drilling proceeds greatly affect the properties of the drilling fluid, and are thus needed to be removed with flocculants dedicated for the submicron solids. GCS is such a flocculant synthesized with chitosan. The optimum synthetic conditions determined through orthogonal experiment were as follows:3% chitosan, mass ratio of chitosan and crosslinking agent=1:0.28, pH=7. Particle size analysis and sedimentation test were done to evaluate the flocculating effect of GCS, and the flocculating mechanisms of GCS were determined through IR spectroscopy, zeta potential measurement and SEM. It has been found that GCS has good flocculating ability, 95% of submicron kaolinite particles can be flocculated. Compared with other flocculants, such as polyacrylamide, GCS does not viscosify drilling fluids; the sizes of the flocs are narrowly distributed and are thus easy to be separated from drilling fluid. GCS has better flocculating effect in alkaline environment. At higher pH value and GCS concentrations, better flocculation can be achieved, and the flocs become more compact. GCS has -OH, -NH, -C═N and -NH2 functional groups with which GCS is tightly adsorbed onto the surface of kaolinite particles through these groups, neutralizing the electric charges on the surface of the kaolinite surface, hence increasing the potential of kaolinite particles, thereby coalescing the particles to form flocs.
Research and Application of High Temperature Inverse Emulsion Viscosifier DVZ-1
2017, 34(4): 20-25. doi: 10.3969/j.issn.1001-5620.2017.04.004
A high temperature inverse emulsion viscosifier DVZ-1 has been developed to resolve the mud rheology deterioration at elevated temperatures in deep wells drilled in the east Tarim area, Xinjiang. DVZ-1 was synthesized with AMPS, DMAM and NVP through inverse emulsion polymerization (a redox system), with white oil as the oil phase. The optimum ratio of the monomers, initiator and reaction temperature for the polymerization were studied, and the synthesized product was characterized with IR spectroscopy, thermogravimetric analysis and gel chromatography. The viscosifying performance, high temperature stability and filtration control ability of DVZ-1 were evaluated, and the working mechanisms of DVZ-1 analyzed through laboratory experiments. The optimum polymerization conditions were as follows:monomers' mass fraction=50% (based on the mass of the water phase), concentration of the initiator=0.2%, oil/water ratio=11, mass fraction of the compound emulsifier=7% (based on the mass of the oil phase), molar ratio of the monomers was AMPS:DMAM:NVP=1:4:0.5, pH=8, reaction temperature=50℃, and reaction time=6 h. DVZ-1 has good thermal stability, and properly functions at 220℃. DVZ-1 is a good viscosifier and a good filter loss reducer in fresh water, saltwater and saturated drilling fluids. It has been used successfully on 6 wells, such as the well GC14 (east Tarim, Xinjiang) and the well XS7-H1 (Daqing oilfield). Problems such as mud thinning at elevated temperatures and difficulties in cuttings carrying through narrow annulus were resolved, ensuring the success of the drilling operation.
Research and Application of OBM-like Water Base Drilling Fluid
XIE Jun, SI Xiqiang, LEI Zumeng, LI Hongxing, JIA Baoxu
2017, 34(4): 26-31. doi: 10.3969/j.issn.1001-5620.2017.04.005
An OBM-like water base drilling fluid has been formulated for use in shale gas development to replace the expensive pollutional oil base drilling fluids (OBM). The OBM-like drilling fluid, formulated with NAPG (a polyether amino alkyl glucoside) as the main additive, is an environmentally friendly water base drilling fluid having inhibitive capacity and lubricity that are similar to those of an oil base drilling fluid. Laboratory study showed that this OBM-like water base drilling fluid can be used at 140℃. It is resistant to contaminations such as clay, drilled cuttings, crude oil and water. EC50 of the drilling fluid is 128,400 mg/L, meaning that it is none bio-toxic. Recovery of core permeability tested with this water base drilling fluid is more than 90%. In field application, this OBM-like water base drilling fluid showed stable properties, strong inhibitive capacity and good lubricity. The second interval of the well Yunyeping-6 has been successfully drilled with this drilling fluid, resolving these problems such as high friction in build-up section and difficulty in exerting drilling pressure in directional drilling section. This OBM-like drilling fluid is worth popularizing.
Mud Loss Control while Drilling with Oil Base Drilling Fluid
TANG Guowang, YU Peizhi
2017, 34(4): 32-37. doi: 10.3969/j.issn.1001-5620.2017.04.006
Oil base drilling fluids are generally the first choice in shale drilling because of their advantages such as low friction and weak shale swelling. Coexisting with the advantages of the oil base drilling fluids are their disadvantages, such as high drilling cost, especially when mud losses are happening, which always cause serious economic loss. To control losses of oil base drilling fluids into formations, a type A lost circulation material (LCM) has been developed, and its particle sizes analyzed. Experiments have been conducted to optimize the particle sizes for the effective and efficient control of oil base mud losses at different loss rates. The experimental results showed that the type A LCM has good compatibility with the drilling fluid used, good dispersity and high oil absorption rate. The type A LCM is resistant to high temperatures to 150℃, and penetrates into a sand bed for 1.0 cm with almost zero filtration. This LCM performs better than the same types of other LCMs in controlling seepage loss and mud losses into fractures. In flow experiments, the forward displacing pressure was 13 MPa, and the reverse breakthrough pressure was 1.2 MPa, indicating that the loss zones deposited with the type A LCM had high pressure bearing capacity and the deposited LCM was easy to remove. Composite LCM formulated with the type A LCM and other LCMs can resolve mud losses into fractures of 1-3 mm in size effectively. The mud loss control technology has been successfully used on the well Jiaoye195-1HF, reducing the drilling cost and the time required for drilling.
Development and Evaluation of a New Water Swelling Lost Circulation Material
YING Chunye, GAO Yuanhong, DUAN Longchen, LIU Peng, WANG Hongmin, CAI Jihua
2017, 34(4): 38-44. doi: 10.3969/j.issn.1001-5620.2017.04.007
A new swelling lost circulation material (LCM) has been developed to replace LCMs presently in use which have these drawbacks such as polluting clad material, low strength and high cost. The new LCM is synthesized though solution free radical polymerization of acrylic acid (AA), acrylamide (AM), bentonite, inert material (such as walnut shell, mica, and polypropylene fiber), N, N-methylene-bis-acrylamide, potassium persulfate and sodium bisulfite. The synthesized product is cladded with environmentally friendly plant capsule. Evaluation of the LCM developed showed that in a 15% Na-bentonite slurry, the LCM can absorb water of 113 times of its own volume. The elastic modulus of the LCM is 4.46 kPa. The LCM has temperature tolerance of 100℃, NaCl resistance of 15%, and ordinary CaCl2 resistance. The plant capsule contains no heavy metals, and is quite environmentally friendly. In cladding the LCM, it is shattered for 8-30 min at ambient temperature, and 517 min at 70℃, and the final product will satisfy the need for filed operation. When used alone, the LCM plugs fractures of 1-2 mm in width, and has pressure bearing capacity of 3 MPa. When used in combination with 20% coarse inert particles, it plugs fractures of 1-4 mm in width, and the pressure bearing capacity will be 4 MPa. If 20% fine inert particles are used with the high concentration of LCM (4%, for instance), the compounded LCM is not able to plug fractures of 1-2 mm. When mixed (compounded) with inert particles, the pressure bearing capacity of the compounded LCM can be greatly enhanced (above 5 MPa), and less LCM (0.3%-0.5%) will be needed to plug fractures of 1-4 mm in width. Compared with other conventional lost circulation materials, this new LCM saves drilling cost by RMB 2 000-4 000 per ton, and is of great prospects in field application.
Application of Lubricating Drilling Fluid Technology in Drilling the Fahliyan Formation of Block Y
CHAI Jinpeng, QIU Zhengsong, GUO Baoyu, WANG Xudong, CAI Yong
2017, 34(4): 45-48. doi: 10.3969/j.issn.1001-5620.2017.04.008
Fahliyan Formation, the main target zone in the Block Y, is a permeable limestone formation with developed porosity, small amount of micro-fractures and high permeability. High pressure and low pressure layers are coexisting in the same formation with high pressure existing in the upper part of that formation. Pipe sticking is easy to happen under high differential pressures. To solve these problems, a drilling fluid with high lubricity and high plugging capacity was developed based on the analysis of the characteristics of the Fahliyan Formation and the mechanism of pipe sticking. The lubricity of the drilling fluid came from a high performance vegetable oil lubricant developed. Laboratory studies showed that at 25℃, 6% bentonite slurry treated with 1% vegetable oil lubricant, had its extreme pressure friction coefficient and adhesion coefficient reduced by 88.57% and 86.67%, respectively. The treatment of the bentonite slurry with a nonionic surfactant tween-80 and a Gemini surfactant C12-2-12 enhanced the high temperature stability of the bentonite slurry to 170℃. A lubricating drilling fluid was formulated with these additives and a plugging agent. This drilling fluid had mud cake friction coefficient that was less than 0.05, extreme pressure friction coefficient less than 0.2, and effectively functioned at 170℃. The application of this drilling fluid, together with a set of appropriate engineering measures in 9 wells (penetrating the Fahliyan Formation) proved successful. No pipe sticking accident occurred during drilling, ensuring the success of the drilling operation.
Application of a New Highly Efficient Anti-wear Friction Reducer in Donghai Oil and Gas Field
HUANG Zhao, HE Fuyao, LEI Lei, DING Jianping, YAN Weifeng, XIE Zhongcheng
2017, 34(4): 49-54. doi: 10.3969/j.issn.1001-5620.2017.04.009
In Donghai Oil and Gas Field, more and more extended reach wells, high angle deviated wells and multilateral horizontal wells have been drilled in recent years. During the drilling operations, high torque and wear-and-tear experienced by the drill pipes and the casing strings have impacted on the safety and the efficiency of the drilling operations. A highly efficient anti-wear friction reducer, ARDR LUBE-100 was found, after extensive investigation and experiments, to be effective in dealing with the problems aforementioned. ARDR LUBE-100 is a compound of organic anions and organic metals, and is a product of anti-wear materials such as alcohols and esters through esterification reaction or condensation reaction at high temperatures. Organic metal ions are generated in intermediate synthesis reaction, and anti-wear inert ions are added into the reactants. ARDR LUBE-100 can be adsorbed onto the surface of a pipe, where rolling friction takes place between the ARDR LUBE-100 particles and the surface of the pipe, thereby effectively reducing wear-and-tear and friction. Laboratory evaluation and field application proved that the ARDR LUBE-100 has good compatibility with drilling fluids, and 1% of ARDR LUBE-100 in drilling fluid has reduced the coefficient of friction by 60%, and rate of wear between drill pipe and casing string reduced by 99.64%, indicating that the use of ARDR LUBE-100 can remarkably wear-and-tear and friction.
Compound Lost Circulation Control Technology for Lost Return in the Sufyan Sub-Block in the West of the 6th Block in Sudan
YANG Guotao, LONG Yingquan, ZHOU Youyuan, WANG Jianwen, WANG Yang, XU Jinyong
2017, 34(4): 55-58. doi: 10.3969/j.issn.1001-5620.2017.04.010
Well NW-1 is located in the Sufyan sub-block in the west of the 6th block in Sudan. Lost return has been encountered in the 2nd interval of the well, and LCM slurries and cement slurries have been used to stop mud losses, but all failed. Borehole wall collapse resulted from mud losses led to sidetrack of the well. In the 3rd interval, lost return happened again. Conventional lost circulation materials, cement slurries, stone particles and rubber fragment, which had been tried 30 times in total, failed to stop the mud losses. The mud losses were finally successfully controlled with a reversed-phase gel LCM in one try, and the well was drilled to the designed depth. The use of reversed-phase LCM successfully in controlling mud losses on the well NW-1 is of great importance and has provided good experience and technical support for the operation in Sufyan sub-block of the 6th block in Sudan.
Resource Utilization of Pyrolyzed Oil Cuttings (I):Study on Solidification of Oil Cuttings with Waste-slag Solidifier
CAI Hao, YAO Xiao, XIAO Wei, DONG Wei, HUA Sudong, GU Zhong
2017, 34(4): 59-64. doi: 10.3969/j.issn.1001-5620.2017.04.011
Hazardous and waste residue resulted from pyrolyzed oil cuttings were solidified with a waste-slag solidifier CS. Laboratory studies have been conducted on the effect of the amount of CS on the unconfined compressive strength, water stability, frost resistance and the characteristics of the leached pollutants of the solidified cuttings. Using XRD, SEM and MIP, the solidification mechanisms of the prolyzed oil cuttings with solidifiers were studied. It has been discovered that prolyzed oil cuttings solidified with CS had higher compressive strength and coefficient of water stability (0.87) than those of the reference samples. After alternate freezing and thawing for 15 times, the solidified prolyzed oil cuttings treated with CS still had higher compressive strength, lower mass losses and good integrity. Leached liquids from the prolyzed oil cuttings treated with solidifiers containing 6%-15% CS conforms to the class I requirement of the standard GB 8978-1996. After the solidification treatment, there were large amount of C-S-H gels and small amount of Aft in the solidified cuttings, making them much denser. The solidified cuttings have higher compressive strength, better water stability and frost resistance, and the leaching of pollutants from the prolyzed oil cuttings is also inhibited.
Study and Application of Low Temperature Early Strength Low Density Cement Slurry
GENG Jianwei
2017, 34(4): 65-68. doi: 10.3969/j.issn.1001-5620.2017.04.012
The early strength of conventional low density cement slurries developed very slowly at low temperature, and the poor cementing ability of these slurries negatively affect the quality of well cementing. In shallow wells with frequent mud losses, this problem is quite common. To resolve this problem, studies have been conducted on low temperature early strength low density cement slurry. Based on the close packing theory and laboratory experimental study, low temperature early strength low density (1.30-1.50 g/cm3) cement slurries were developed. Ultra-fine gelled material and an early strength agent made by compounding lithium salts were used to improve the soundness and early strength of the low density set cement. The setting time of the low density cement slurry at 25℃ is 13 h, and the 24 h strength is 10.2 MPa. This low density cement slurry has high early strength at low temperatures, short setting time and good stability. It has been used on 2 wells in Daqing Oilfield with great success, and the well cementing jobs were 100% qualified.
A New Fuzzy Mathematics-based Method for Anti-channeling Performance Evaluation and Its Application
LI Jin, GAO Bin, GONG Ning, XIE Zhongcheng, CHEN Yi, HAN Yaotu
2017, 34(4): 69-74. doi: 10.3969/j.issn.1001-5620.2017.04.013
Gas channeling in annular spaces is a difficult problem seriously harmful to cementing almost all gas wells. Accurate evaluation of cement slurry's anti-channeling performance is one of the key technologies for the prevention of gas channeling in annular spaces. There are several factors which affect gas channeling in annular spaces in a combined way, while the evaluation methods presently in use do not take them all in consideration and have limited accuracy, and hence they cannot give a full view of the problem they are trying to reveal. In this study, fuzzy mathematics has been used in establishing a model used in predicting comprehensively the anti-channeling performance of a cement slurry. This model takes into account the characteristics of gas channeling in annular spaces. Five commonly used evaluation methods, such as GFP method and SPN method etc., are integrated into an evaluation factor set, "good", "medium" and "poor" anti-channeling capacity are used as an evaluation set. Based on the characteristics of each factor, a corresponding membership function is determined. Use the principles of analytic hierarchy process, the weighted fuzzy set of each factor is calculated, and according to the "maximum subordination principle", the overall risk of sand production is determined. It has been proved that this evaluation method can be used to effectively predict gas channeling in well cementing. It provides a more comprehensive and integrated evaluation method for optimizing cement slurry formulation to prevent pressurized wellhead after well cementing, thereby to ensure the quality and safety of a cemented well.
Study and Evaluation of a New Anti-Water Channeling Material for Well Cementing
LU Haichuan, ZHAO Yue, SONG Weibin, GAO Jichao, HU Zhonghua, HUO Mingjiang
2017, 34(4): 75-79,84. doi: 10.3969/j.issn.1001-5620.2017.04.014
Water channeling in well cementing has been a difficult technical problem remained unsolved in petroleum industry till now. In a study on anti-water channeling cement slurry, structural design of anti-water channeling additives were done, and based on the design, several anti-water channeling raw materials were selected and mixed in a certain ratio to form a new compounded anti-water channeling additive. According to the water-channeling mechanisms in different stages of well cementing, the effect of the anti-water channeling additive was evaluated with different evaluation methods. The evaluation results showed that the anti-water channeling additive developed is able to strengthen the interior structure of cement slurry, shorten the transit time of static gel, avoid contracting of set cement, thereby avoiding water-channeling of cement slurry at different cementing stages. The evaluation also demonstrated that the new anti-water channeling additive is able to shorten thickening time of cement slurry, increase compressive strength of set cement, and improve the stability of cement slurry; it has no bad effect on the thickening time, rheology and filter loss of cement slurry, exhibiting good overall properties.
Liquid Cementing Fluid Reduced Lightened Deep Water Light-weight Cement Slurry
FENG Yingtao, SONG Maolin, ZHANG Hao, LI Houming
2017, 34(4): 80-84. doi: 10.3969/j.issn.1001-5620.2017.04.015
Contrary to the surface hole cementing operation, deep water surface hole cementing imposes new requirements on well cementing operation because of the deep water environment and the operation condition. A new liquid light weight agent PC-P81L has been developed for use in cementing the surface hole in deep water drilling, and a cementing fluid was formulated with PC-P81L. Laboratory experimental results showed that PC-P81L can be used to adjust the density of cement slurry between 1.30 g/cm3 and 1.70 g/cm3. PC-P81L has strong suspending capacity; it can suspend cement slurries with water/cement ratio of 2. PC-P81L is not only a light weight agent, it is also a strength enhancer in cement slurries with conventional densities. PC-P81L can accelerate the setting of cement slurry in deep water low temperature environment. By increasing the water/cement ratio, the density of the deep water low density cement slurry can be reduced, and the yield of the cement slurry increased, thereby reducing the consumption of cement in field application. The formulation of the cement slurry is simple and the properties of the cement slurry are easy to adjust. The additives used are added in liquid form, thereby lightening the field labor intensity. The use of the cement slurry has satisfied the needs for deep water low temperature operation, providing insurance for drilling the deeper formation. Compared with hollow microsphere, the operation cost of the light weight cement slurry is quite lower.
High Temperature Anti Strength Retrogression Cement Slurry with Compounded Silica Powder
LU Feifei, LI Fei, TIAN Najuan, ZHU Wenhao
2017, 34(4): 85-89. doi: 10.3969/j.issn.1001-5620.2017.04.016
Conventional Class G cement with silica powder is not able to satisfy the need of extra high temperature well cementing because of serious retrogression of the high temperature strength of the set cement. The mechanisms of set cement (with 35% silica powder) strength retrogression at 145-180℃, and the effect of particle sizes, concentrations and compounding of silica powder on the development of the strength of set cement at 170-200℃ have been studied to resolve strength retrogression of set cement at elevated temperatures. A high temperature anti strength retrogression cement slurry has been developed. These studies showed that (1) at temperatures above 160℃, the strength of a set cement with 30% silica powder begins to decline after curing for 30 h, and the higher the temperature, the earlier the process of strength retrogression. (2) The ratio of 0.18 mm silica powder, 0.09 mm silica powder and liquid silica is determined to be 30:60:10 based on the effect of coarse and fine particle silica powders on the development of the strength of set cement. When the compounded silica is added at a concentration of 70%, strength retrogression of set cement at 200℃ can be inhibited. (3) a high temperature high density anti strength retrogression anti-channeling cement slurry with compounded silica powder has been developed with density between 2.08 g/cm3 and 2.41 g/cm3, and it can be used at high temperatures such as 170-200℃. Through these studies, the continual strength retrogression of set cement is inhibited, the long-term mechanical performance is improved, and the technology developed can be used in perfectly cementing HTHP gas wells.
Cementing High Temperature Deep Well Antan-1X with Narrow Annular Spaces
LIU Zishuai, LI Yongjun, TANG Shouyong, WANG Dongming, JIANG Shiwei, ZHOU Chongfeng
2017, 34(4): 90-95. doi: 10.3969/j.issn.1001-5620.2017.04.017
The Langgu sag, one of the three sags rich in oil in the Jizhong Depression, north China, is the main oil producing area of Huabei Oilfield. The reservoirs are deeply buried and the formation temperatures are high. The well Antan-1x is an exploratory well drilled in this area. This well had complex well profile, and the φ 127 mm liner (in 4th interval) was run to 5,494 m, at which the formation temperature is 177℃. Gas zones at the completion depth are very active and are difficult to control with high density drilling fluids. Narrow annular spaces and hence thin cement sheaths impose challenges to the high temperature stability and anti-channeling ability of cement slurry, and the compressive strength of set cement. A high temperature anti-channeling cement slurry was formulated for use in the well Antan-1x. This cement slurry has good anti-settling performance and ability in minimizing the amount of free water. Its thickening time is adjustable. The compressive strength of the set cement under 180℃ does not retrograde. A flushing spacer was formulated with high temperature suspension stabilizer, and the settling rate of the spacer under 180℃ was less than 0.03 g/cm3. In cementing the φ 127 mm liner string of the well Antan-1x, high quality cementing job was done with the high temperature cement slurry and the spacer, laying a good foundation for the later exploration and development of the Jizhong depression in north China.
A High Temperature Sand Carrying Acid and its Performance Evaluation
JIA Wenfeng, REN Qianqian, WANG Xu, YAO Yiming, JIANG Tingxue, CHEN Zuo, ZHAO Chuanfeng
2017, 34(4): 96-100. doi: 10.3969/j.issn.1001-5620.2017.04.018
Acid fracturing with sand carrying acid has become one of the important measures in carbonate reservoir stimulation. The key to the success of acid fracturing with sand carrying acid is the selection of a high temperature sand carrying acid with good performance. To deal with problems encountered in fracturing, such as shear-breaking of the crosslinked acid by shearing, serious deacidification, high crosslinking agent consumption and high job cost etc., a new hydrophobically associating thickener (used in acid) and a high performance crosslinking agent have been synthesized, and an optimum crosslinked acid formulation developed with the following composition:20%HCl+0.8%SRAP-1 (thickener) + 0.8% SRACL (2:10, crosslinking agent) +2% SRAC-1 (high temperature corrosion inhibitor)+0.2% DF-1 (iron ion stabilizer) + 1.0% SRCU-1 (cleanup additive)+0.05% JSP-8 (capsule gel breaker). Laboratory evaluation showed that the crosslinking time of the acid formulation was about 89 s even after substantial decrease in the amount of crosslinking agent, indicating that the acid formulation has good delayed crosslinking ability. After shearing for 2 h at 140℃ and 170 s-1, the viscosity of the acid was still greater than 60 mPa·s, and the state of the crosslinking remained stable, no de-acidification was found of the acid. The acid formulation has satisfied the need of field operation, and is worth popularizing.
Mechanisms of CO2 Water-free Fracturing Method in Production Increasing
DUAN Yongwei, ZHAN Jin
2017, 34(4): 101-105. doi: 10.3969/j.issn.1001-5620.2017.04.019
Limited control range of a single well and insufficient formation energy supplement have long been critical problems affecting the development of tight oil reservoirs. Monitoring of downhole micro seism data during fracturing operation indicates that the volume of formation stimulated with CO2 water-free fracturing is 2.5 times of the volume of formation stimulated with conventional hydraulic fracturing using the same volume of water as that of the CO2 used, and the CO2 water-free fracturing creates fractures of increased complexity. Laboratory experiment and crude oil sampling after fracturing operation have proved that CO2 can effectively reduce the viscosity of crude oil. With the water-free fracturing, miscibility of crude oil is realized and oil displacement efficiency is enhanced. Static pressure test after fracturing shows that oil production after water-free fracturing is remarkably increased compared with the oil production before fracturing, an effect that is similar to advanced formation energy supplement of a well. CO2 water-free fracturing technology has been successfully used on 5 oil wells with tight reservoir, remarkably increasing oil production after fracturing. Average oil production increase of 2.31 t/d per well has been gained. The CO2 water-free fracturing also caused adjacent wells to produce more oil and more liquid, demonstrating that CO2 water-free fracturing, a prospective technology in tight oil reservoir development, is effective in well stimulation.
Numerical Simulation and Analysis of Micro Flow of Acids in Fractures Generated in Acid Fracturing
LIU Xiang, Yi Xiangyi, WU Yuanqin, LI Qin
2017, 34(4): 106-111. doi: 10.3969/j.issn.1001-5620.2017.04.020
Acid fracturing is an important stimulation measure used in enhancing oil recovery. The understanding of flow of acids in fractures generated in reservoir fracturing is of great importance. Physical experiments have been conducted previously in the study of acid flow in fractures, and the fracture model used in the experiments are quite different than the actual fractures generated in acid fracturing, the effects of the roughness of the surfaces of fractures on acid flow are seldom considered. This paper introduces the use of a software Fluent to numerically simulate acid flow in fractures, and analyzes the effects of the roughness of the surfaces of fractures on acid flow. Experimental results showed that the flow rate curves of both single-phase flow and two-phase flow along the horizontal central axis demonstrated a shape of "厂", while along the vertical central axis, the curve showed a shape of "几". In single-phase flow, flow rates around wave crest were much greater than the flow rates in other area, and the flow rate along the central axes were low. On the other hand, in two-phase flow, highest flow rates were found along central axes. With an increase in roughness of the surfaces of fractures, the length of flow of acid is extended. At the same roughness, the flow length of acid and acid viscosity are not in linear relationship. When M=6, the flow lengths of acid in fractures with 4 different surface roughness all are the shortest. When M < 6, the flow lengths decrease with increase in viscosity ratio. When M > 6, the flow lengths increase with increase in viscosity ratio. A plateau appears with M between 8 and 11, meaning that the effects of viscosity ratio on acid flow length are becoming weak. Increase in acid flow length increases the length of acid erosion, forms more cannelures, thereby enhancing the flow conductivity of fractures and fulfilling the purpose of acid fracturing. Taking into account operation cost, in selecting prepad fluid and acid, viscosities corresponding to the values around the descending section and the plateau section of the flow rate curve, should not be used.
Experimental Study on Fracture Plugging Performance of Volumetric Expansion Nano Particles Used in Well Fracturing
LI Dan, YI Xiangyi, WANG Yanlong, SHI Li, WEN Xiaoyong, LIU Xiang
2017, 34(4): 112-116. doi: 10.3969/j.issn.1001-5620.2017.04.021
Nano particles as plugging agent used to shut off fractures with small sizes have been frequently studied in recent year, while their use in shutting off water-producing fractures in low-permeability reservoirs in fracturing operation is less studied. In this study nano particles were selected for fracture plugging experiment. Nano particles' ability to shut off fractures producing water and fractures producing oil was evaluated on a self-made core plugging experiment device. Nano particles' expandability, injectability and the resistance to washing in fractures with water flow were also studied. The experimental results showed that the volumetric expansion nano particles absorb water and expand greatly in water environment. In oil environment, the nano particles have very weak expandability. The nano particles can shut off fractures producing water very well. The amount of water shut off at confining pressure of 40 MPa and 50MPa can be as high as 90%. In shutting off fractures with oil flow, there is only 30% of the oil shut off. The nano particles have good injectability; at confining pressure of 40 MPa, 3 PV of fluid containing 2% nano particles were injected into fractures with water flow, and they stayed firmly inside the fractures after expanding for 4 d. These experimental data prove that the volumetric expansion nano particles will shut off water instead of oil, and can be used in well fracturing and water shutoff.
Injected Gas Improves Acidification Job Quality of Sandstone Reservoirs
LIU Yigang, ZHANG Lu, ZHANG Liping, ZOU Jian, ZHANG Yunpeng, GAO Shang
2017, 34(4): 117-121. doi: 10.3969/j.issn.1001-5620.2017.04.022
It has been noticed in well acidification operation that the acidification job quality is not satisfactory, the effective period of the acidification job is short, and the acidified area is limited. In well acidification operations, it has been found that the results of acidifying a gas well penetrating sandstone reservoirs are much better than the results of acidifying an oil well penetrating sandstone reservoirs. This observation has been used in designing oil well acidification program to improve the acidification job quality, that is, a gas can be injected with acid into the well in oil well acidification. The mechanisms and advantages of alternated injection of gas and acid are extensively studied in this paper. In laboratory experiment, the acidification results of undamaged cores and cores damaged by completion fluid under 3 gas injection models were studied, and the effects of different injected gases on the acidification results were analyzed. It is considered that gas injected in well acidification clearly improved the acidification job quality of damaged cores, especially when an acidification mode in which prepad gas plus alternated gas and acid injections was used during well acidification. For undamaged cores, the effectiveness of gas injection with acid in well acidification was not satisfactory. It was also found that the effectiveness of injecting CO2 was better than that of injecting N2. Alternated gas injection with acid in well acidification greatly improves the permeability of the reservoir rocks, and is able to enhance the effectiveness of conventional well acidification job. This technology has a broad development prospect.
Laboratory Study on Recycling of Flowback Fluid of Guar Gun Fracturing Fluid
MA Hong, HUANG Daquan, LI Guanghuan, ZHANG Aishun, LONG Tao, CAO Ziying, WANG Yundong, SU Jun
2017, 34(4): 122-126. doi: 10.3969/j.issn.1001-5620.2017.04.023
Guar gum fracturing flowback fluid has become one of the main pollution sources to oilfield water. If the flowback fluid is used to re-mix fracturing fluid after treatment, it not only protects the environment from being polluted, but also saves water resource and reduces operation cost. To simplify the treatment process and to increase the volume of treatment, a method for the removal of boron and metal ions was introduced to realize the recycling of the fracturing flowback fluid. Sample of fracturing flowback fluid from the well Guanxi-5 was analyzed for the effect of inorganic ions, solid particles and residual boron on the recycling of the flowback fluid. The study showed that 11 inorganic ions in the flowback fluid affect its recycling to varying degrees. The concentration thresholds of these ions affecting the recycling process were summarized. Flowback fluid after gel breaking, flocculation, boron and metal ion removal, has its oil component removed by 91.71%, turbidity reduced by 94.6%, colourity reduced by 95.8%, and Ca2+, Mg2+, Fe2+ and B reduced to 36.07 mg/L, 19.44 mg/L, 44.3 mg/L and 3.35 mg/L, respectively. Boron remover and metal ions removers were added to control the concentrations of boron and metal ions within the acceptable ranges based on their concentrations in the flowback fluid. This experimental method, because of its advantages such as simplicity in operation, large volume of treatment and low cost, is easy to apply in field operation. A guar gum fracturing fluid made from a treated flowback fluid, has its viscosity remained above 100 mPa·s after shearing for 1 h under 100℃, satisfying the requirement of "General technical specifications of fracturing fluids," and realizing the recycling of fracturing flowback fluids.