2020 Vol. 37, No. 6

2020, 37(6)
2020, 37(6): 809-812.
New Progresses Made in the Study of Minimizing Damage to Oil and Gas Reservoirs with Micronized Manganese Ore Weighting Agent
LIU Fengbao, WU Xingxing, XU Tongtai, WANG Wei, WANG Danbin
2020, 37(6): 677-684. doi: 10.3969/j.issn.1001-5620.2020.06.001
Barite used in drill-in fluids causes damage to the reservoir formations and the permeability impaired by the damage is quite difficult to recover. Micromax, a new acid soluble micronized manganese ore weighting agent, has recently been used in drill-in fluids. This paper summarizes the effects of Micromax weighted drilling fluids on the protection of reservoirs and analyzes the mechanisms with which the Micromax is used to improve the performance of drilling fluids in protecting hydrocarbon reservoirs. Micromax after invading into the reservoir formations can be flowed back because of its particle properties such as uniformity, high hardness and high sphericity, which are helpful to the mitigation of formation damage. Micromax is acid soluble. Acids suitable for the acidification of Micromax are investigated and the effects of Micromax before and after acidification on the physical properties of the reservoirs are compared. Reservoir damage can be eliminated by acidification with a suitable acid fluid of proper concentration.
Dissolution of Barite Filter Cake Using Chelating Agents: A review of Mechanisms, Diagnosis and Removal Strategies
WEI Zhongjin, ZHOU Fengshan, XU Tongtai
2020, 37(6): 685-693. doi: 10.3969/j.issn.1001-5620.2020.06.002
As a weighting agent of drilling fluid, barite is easy to migrate, transform and precipitate in the reservoir to form acid insoluble barite mud cake, which causes serious damage to oil and gas reservoir. Therefore, it is necessary to remove the blockage of barite safely and reliably. However, many reasons, such as put too little emphasis on barite blocking, unclear mechanism of barite blocking and removal, improper design of removal methods, large investment but poor output, confidentiality of business, et al, have restricted the progress of remove barite blockage technology in China. The chelating agent with amino polycarboxylate as the main component is the most promising process choice for removing the barite blockage, while the chelating agent structure (amino group type, carboxyl number, ring chain size, chemical stability, et al), the properties of metal ions (charge, ion radius, ionization potential or alkalinity, co-associated metal ions, et al), medium environment (pH, temperature, pressure, et al) and so on, have a profound influence on the dissolution of barite. The economic and efficient design of chelating barite blocking remover and its removal process must take removal characteristics of different chelators, concentration, catalyst, converting agent, polymer breaker, bottom temperature, environment friendly, corrosiveness, formation rock matrix, secondary reservoir damage caused by removal process and other factors into account. With the help of modern experimental technique evaluation, such as filtrate cake dissolution, dissolution product composition and morphology, core flow, et al., and carefully design the details of chelating removal process, such as injection volume, injection pressure, soaking time, flow-back fluid treatment, et al, so as to fully understand the mechanism of barite blocking, the design of chelating removal agent and its application in oil and gas fields. In this paper, the systematic work of removing the blockage of barite filter cake is reviewed, which done by the previous researchers in recent years. Hoping to provide a new perspective for the readers, so as to improve the technical innovation level of drilling fluid and completion fluid in China.
Study and Application of an Ultra-High Temperature High Density Drilling Fluid
LI Xiong, DONG Xiaoqiang, JIN Junbin, YANG Xiaohua
2020, 37(6): 694-700. doi: 10.3969/j.issn.1001-5620.2020.06.003
Most of the high-density drilling fluids weighted with barite are often faced with high temperature problems such as difficulty in rheology control, high HTHP filter loss and barite sag etc. A drilling fluid design clue is presented to deal with these problems. An ultra-high temperature high density drilling fluid SMUTHD was formulated with a self-developed ultra-high temperature filter loss reducer SMPFL-UP, a self-developed dispersant for use in ultra-high temperature high density fluids, a high temperature plugging antisloughing agent SMNA-1, a high temperature stabilizer GWW and a high-efficiency lubricant SMJH-1 etc. The SMUTHD drilling fluid can be used at high temperatures up to 220 ℃. At density of less than 2.40 g/cm3, the SMUTHD drilling fluid had stable rheology, HTHP filter loss of less than 12 mL and extreme friction coefficient of 0.178 after aging at 220 ℃. The settling factor (SF) of SMUTHD standing for 7 d at 220 ℃ was less than 0.54. These data indicate that the SMUTHD drilling fluid has good rheological and filtration control properties as well as high temperature settling performance when its density is not higher than 2.40 g/cm3. The SMUTHD drilling fluid has been successfully used in drilling the 5th interval of the well Shunnanpeng-1, with total footage of 581 m drilled. The bottom hole temperature of this well was 207.4 ℃, and the density of the drilling fluid was 1.75-1.80 g/cm3. Drilling fluids in different operational stages all had SF of less than 0.52. The properties of the drilling fluid were stable and no downhole troubles happened during drilling. Coring operation was performed smoothly. The development of SMUTHD has not only greatly ensured the exploration and discovering of deep oil and gas reservoirs, the increase of petroleum reserves and production as well as oil and gas development with low cost and high efficiency, it has also improved the level of autonomy of China’s ultra-high temperature and high density drilling fluid technology.
Oil Base Drilling Fluid Technology for Drilling Broken Ordovician Formation in Shunbei Block
WU Xiongjun, LIN Yongxue, SONG Bitao, JIN Junbin, DONG Xiaoqiang
2020, 37(6): 701-708. doi: 10.3969/j.issn.1001-5620.2020.06.004
Several ultra-deep wells were drilled in the Shunbei Block with water base drilling fluids, resulting in borehole wall collapse and mud losses in the Ordovician formation. Based on the analyses of the mechanisms of borehole wall collapse, a Gemini type high temperature emulsion stabilizer and a branched flow pattern additive with three heads and two tails have been developed. Using microencapsulation treatment method, a temperature-sensitive expandable lost circulation material was developed. This lost circulation material, when excited at 156 ℃, can expand to a volume that is 5.37 times of its original volume. With these additives, a high temperature oil base drilling fluid was formulated. This drilling fluid has low viscosity, high gel strength and strong sealing capacity. Laboratory evaluation results showed that this drilling fluid can be used at 180 ℃. The sizes of the emulsified droplets are in a range of 1.2-26.9 μm. The HTHP filter loss, plastic viscosity and yield point/plastic viscosity ratio of the drilling fluid are 2.4 mL, ≤40 mPa.s and 0.31-0.40 Pa/mPa·s, respectively. The plastic viscosity of the new oil base drilling fluid is 10%-15% lower than that of the conventional oil base drilling fluids, while the yield point of the new oil base drilling fluid is 15%-25% higher than that of the conventional oil base drilling fluids, demonstrating an excellent low viscosity high yield point characteristics and capabilities of plugging microfractures by size matching. Application of the new oil base drilling fluid in the well Shunbei-55X showed that the average percent hole enlargement in broken formations was only 7.77%. Apart from a momentary mud loss into a cave during drilling, there was no other obvious mud losses encountered. Use this new oil base drilling fluid, collapse of the Ordovician formation during drilling was avoided, mud losses into the fractured reservoir were reduced. It also helps set a record of the deepest onshore directional well in Asia and develop the oil and gas resources in Shunbei Block with high speed and high efficiency.
Application of a High Temperature High Density Oil Base Drilling Fluid in Well Dabei-12X in Tarim Oilfield
ZHAO Wen, SUN Qiang, ZHANG Heng
2020, 37(6): 709-714,720. doi: 10.3969/j.issn.1001-5620.2020.06.005
The Well Dabei-12X, located at the east high of the Dabei 12# structure in the Kuche depression, is a high temperature high pressure (HTHP) appraisal well drilled in Tarim oilfield in 2018. This well penetrated the gypsum and salt zones of the Kumugeliemu formation (4267-5287 m) in which high pressure and ultra-high pressure prevail. Also exist in this section are high-pressure saltwater zones and mud loss zones. In previous drilling operation, borehole wall collapse, mud losses and saltwater invasion have been occurring all the time. Based on the geologic characteristics and operational requirements in this area, the technical difficulties in using oil base drilling fluids at HTHP were analyzed and a high temperature high density oil base drilling fluid was formulated. Laboratory experiments were performed to simulate the possible risks in drilling the HTHP sections. Experimental results showed that the high temperature high density oil base drilling fluid had stable properties; the electric stability was 1562 V, and the HTHP filter loss was 1 mL. When contaminated with 30% (Vol.%) nearly saturated saltwater, percent change in the apparent viscosity of the oil base drilling fluid was less than 10%, the filter loss was less than 2 mL and the electric stability was 1002 V. The oil base drilling fluid had good high temperature stability; after being aged at 170 ℃ for 10 d, the rheology of the drilling fluid was still stable. The settling factor of the drilling fluid was 0.522. Field application indicated that this oil base drilling fluid can be used to solve the problems encountered in drilling the HTHP and ultra-high-pressure salt/gypsum zones in the Kelasu structural belt in Kuche depression, Tarim Basin. The density of the drilling fluid in the fourth interval was 2.43 g/cm3 and the drilling fluid still retained good flow property, low viscosity, low gel strengths and ECD, no mud losses resulted from high viscosity and high gel strengths were encountered. In drilling the 2135 m salt/ gypsum zones, the rheology of the mud was very stable because of the high resistance of the mud to salt and gypsum contamination.
Evaluation and Field Application of Weighting Agents for Ultra-High Density Oil Base Drilling Fluids
LIU Zheng, LI Juncai, XU Xinniu
2020, 37(6): 715-720. doi: 10.3969/j.issn.1001-5620.2020.06.006
The pressure coefficient of the Paleogene, Cretaceous and Jurassic systems in the south rim of the Junggar Basin is in a range of 2.40-2.65 g/cm3. An ultra-high density oil base drilling fluid with excellent performance is in urgent need to ensure safe drilling in this area. Using environmental scanning electron microscope and laser particle size analyzer, the micro morphology and particle size distribution of the common barite, micronized manganese ore and micronized barite were analyzed. The principles of reducing the viscosity of drilling fluids with micronized weighting agents are also analyzed. A mixture of different weighting agents in optimum ratio for formulating ultra-high density oil base drilling fluids was made through laboratory experiment, that is, common barite: micronized manganese ore = 7∶3. An ultra-high density oil base drilling fluid was formulated and its high temperature settling stability and water contamination resistance were evaluated. The experimental results showed that the ultra-high density oil base drilling fluid has good high temperature settling stability; after standing for 24 h at a constant temperature, the difference between the density of the top and the density of the bottom of the oil base drilling fluid was 0.01-0.02 g/cm3. After standing for 120 h at a constant temperature, the difference between the density of the top and the density of the bottom of the oil base drilling fluid was 0.10-0.14 g/cm3. The oil base drilling fluid is resistant to the contamination of 15% water invasion. Field operation showed that a 2.65 g/cm3 ultra-high density oil base drilling fluid manifested itself good performance in the whole drilling process, with no troubles encountered downhole.
Laboratory Study on Water in Oil Drilling Fluid Formulated with Biodiesel Oil
LUO Xuwu, ZHAO Xionghu, YU Jiashui, LIU Junyu, CAO Jiajun, HE Gang
2020, 37(6): 721-725. doi: 10.3969/j.issn.1001-5620.2020.06.007
Biodiesel, mainly composed of fatty acid alkyl esters, is a good base fluid for making ester-base drilling fluid because of its many advantages, such as high closed-cup flashing point (thus can avoid catching fire), no or a small amount of sulfur and aromatic hydrocarbons contents, stable properties, low toxicity and non-fluorescence. It has no impact on wireline logging. Several oil base mud additives, such as the primary emulsifier TC-PEM, the secondary emulsifier TC-GSEM, the gelling agent UP-GEL and filter loss reducer XXX were optimized to overcome the poor compatibility of the oil base mud additives with biodiesel. Three biodiesel oil base drilling fluids were formulated with these additives through property evaluation. These biodiesel oil base drilling fluids have good thermal stability (resistant to temperature of 120 ℃), good performance in resisting fresh water invasion (15%) and CaO contamination (2%). The biodiesel oil base drilling fluids have a degradability level of “easy to degrade”, and are thus environmentally friendly.
Research and Development of a Novel Internal Rigid External Soft Plugging Agent
XU Zhe, SUN Jinsheng, LYU Kaihe, LIU Jingping, HOU Delin, KE Can, SUN Yuanwei
2020, 37(6): 726-730. doi: 10.3969/j.issn.1001-5620.2020.06.008
Rigid plugging agents have high strength and are difficult to adapt themselves to the sizes and shapes of the formation pores; Soft plugging agents, on the other hand, have strong self-adaptive capacity, but their compressive strength is low. Effective and efficient plugging cannot be obtained by the rigid or the soft plugging agent only. By combining the advantages of the soft and the rigid plugging agents, a new “soft outside rigid inside” plugging agent was developed through solution polymerization. This new plugging agent was made with calcium carbonate as the rigid core material, acrylamide and 2-acrylamido-2-methylpropane sulfonic acid as the main polymerization monomers, N,N-Methylene-bisacrylamide as the crosslinking agent, and ammonium persulfate-sodium bisulfite redox system as the initiator. The new plugging agent has small expansion ratio when water is absorbed, high compressive strength, good thermal stability and little impact on the rheology of the drilling fluid. Compared with soft plugging agents, this new plugging agent has better filtration control capacity and plugging performance in sand-bed test.
Evaluation on the Ability of a New Self-Degrading Lost Circulation Agent to Plug Fractures and Protect Reservoirs
YE Lian, QIU Zhengsong, CHEN Xiaohua, ZHONG Hanyi, ZHAO Xin, BAO Dan
2020, 37(6): 731-736. doi: 10.3969/j.issn.1001-5620.2020.06.009
When drilling in fractured reservoirs, consideration has to be given to both the plugging of the fractures to control mud losses and the removal of the plugging agents after completion of the well. Conventional temporary plugging agents do not degrade by itself and do not have enough strength to withstand the formation pressures of the reservoirs. A new environmentally friendly self-degrading lost circulation agent SDPF was analyzed for its performance as a lost circulation material (LCM). The self-degrading mechanisms, ability to control mud losses under pressure and reservoir protection by self-removal of SDPF were investigated through pressure bearing test and with Fourier infrared spectrometer, thermogravimetric analyzer (TGA) and scanning electron microscope (SEM). Experimental results have shown that under 25 MPa, the percentage of SDPF that was broken under pressure was less than 5%. The percentage of self-degrading increases with temperature, acidic and basic conditions help accelerate the self-degrading of SDPF, and inorganic salts play no role in the self-degrading of SDPF. A self-degrading mud loss control slurry was formulated with SDPF as the bridging particles and other acid-soluble materials as synergy materials. Micrometer and millimeter sized fractures can be plugged with the slurry, and fractures plugged with the slurry can withstand pressures up to 7.5 MPa. Experiment on the removal of mud cakes and core flowback have shown that rock cores after self-removal of the slurry had percent recovery of permeability of at least 85%. These experimental results have proved that the mud loss control slurry formulated has the ability to control mud losses under pressure and good performance in reservoir protection by self-removal. The development of the new self-degrading LCM is expected to solve mud losses into fractured reservoirs and reservoir protection, two problems that have been difficult to solve simultaneously previously.
The Properties of an Environmentally Friendly High Temperature Salt Resistant Micrometer and Nanometer Filter Loss Reducer
WANG Yanling, JIANG Baoyang, LAN Jincheng, MENG Lingtao, XU Ning, LI Qiang
2020, 37(6): 737-741. doi: 10.3969/j.issn.1001-5620.2020.06.010
Presently there are fewer environmentally friendly high temperature salt resistant filter loss reducers available in China, and the molecular structure of the filter loss reducers are also quite simple. In our studies, MND-1, a new environmentally friendly high temperature salt-resistant micrometer and nanometer filter loss reducer, was developed by the modification of hydroxyl ethyl cellulose (HEC), with 1-bromododecane as the initiator for the reaction. Graft copolymerization of HEC and nanometer CaCO3 produced a product of macro molecules. Association among the macro molecules or among the different molecular chains of a single macro molecule produced supramolecular network structure of different morphologies. The interaction between the graft copolymer and the nanometer CaCO3 helped stabilize the molecular structure of the final product and also enhanced the relevant properties of the final product. The filter loss reducer developed has small molecular volume and high specific area. The molecules of MND-1 can form a spatial network structure through hydrogen bonds and Van der Waal’s force among the hydroxyl groups in the molecules. The strength of this spatial network is not strong enough to resist high shear rates, and the viscosity of the MND-1 solution is thus decreased at high shear rates. When shearing stops, MND-1 regains its spatial network structure formed through the association forces among the molecules of MND-1, and the MND-1 solution resumes its viscosity. This is the so-called shear thinning effect formed through a dynamic equilibrium between the destruction and recovery of the spatial network structure. With this excellent shear thinning effect, MND-1 can effectively seal the voids in mud cakes, thereby reducing the rate of filtration. Laboratory evaluation experiment showed that MND-1 has excellent filtration control capacity in freshwater, saltwater and saturated saltwater drilling fluids. The API filter loss of an MND-1 treated saturated saltwater base drilling fluid aged at 180 ℃ for 16 h was only 6.8 mL. MND-1 is environmentally friendly and easy to biodegrade, it has an EC50 of 4.3×104 mg/L.MND-1 can be used in drilling high temperature salt formations in environmentally sensitive areas.
Study and Application of “All-in-One Bag” Multi-Function Drilling Fluids
HE Ruibing, LAI Quanyong, XU Jie, XIU Haimei, CHEN Zenghai
2020, 37(6): 742-745,752. doi: 10.3969/j.issn.1001-5620.2020.06.011
A new environmentally friendly multi-function drilling fluid additive PF-MFA was synthesized through dispersion polymerization. PF-MFA can be used as viscosifier, gelling agent, shale encapsulator, shale inhibitor and filter loss reducer. A new “all-in-one bag” drilling fluid was formulated with PF-MFA as the unique core additive, seawater and weighting agent as the auxiliary additives. This new drilling fluid has simple composition and high performance. A drilling fluid treated with 1% PF-MFA, after hot rolling at 80 ℃, still had high viscosity, gel strengths and strong inhibitive capacity, the API filter loss was controlled at less than 6.5 mL. The salt, clay and calcium(CaCl2) resistance of this drilling fluid were 20%, 15% and 2%, respectively. This drilling fluid is also biodegradable and is thus environmentally friendly. This “all-in-one bag” drilling fluid has been successfully used in the well V40 in the Block PL19-3 in Penglai, Bohai. Field operation showed that less amount of drilling fluid additives was required for the “all-in-one bag” drilling fluid to achieve the same goal. Stable and easy to maintain properties as well as simple composition of the “all-in-one bag” drilling fluid can satisfy the needs of drilling production wells and adjustment wells penetrating relatively easy-going formations.
Study and Application of Drilling Fluid Technology for Slim Hole Drilling in Changqing Gas Field
WANG Qingchen, ZHANG Jianqing, HU Zubiao, WANG Weiliang, SHI Deyi, WEI Yan
2020, 37(6): 746-752. doi: 10.3969/j.issn.1001-5620.2020.06.012
Mud loses, formation ballooning, borehole wall destabilization, difficulty in cuttings carrying and low success rate of wireline logging are problems encountered in slim hole drilling in the Changqing gas field. Technical measures have been taken to solve these problems. For example, reasonable flow rates can be used to prevent mud losses and formation ballooning, taking into account the reduction of circulation pressure and the improvement of hole cleaning. Also, in selecting the drilling fluid that was suitable for drilling the slim hole, new mud additive evaluation methods were used, taking into account the operational characteristics of slim hole drilling fluids, to select CQFY as the main inhibitor, a natural polymer NAT20 as the filter loss reducer and a non-fluorescence white asphalt NFA-25 as the sealant. Using these additives, a drilling fluid was formulated through optimization. The drilling fluid technology aforementioned has been used to drill the φ165.1 mm hole section andφ152.4 mm hole section since year 2018. Field operation showed that the drilling fluid technology effectively mitigated the drilling problems previously encountered; totally 235 wells of φ165.1 mm in diameter and 7 wells of φ152.4 mm in diameter were drilled successfully, borehole wall collapse, mud losses, formation ballooning were avoided and ROP increased. Success rates of wireline logging for the φ165.1 mm andφ152.4 mm wells were 84.7% and 100%, respectively.
Laboratory Study on Temperature Sensitive Gel Lost Circulation Material
ZHANG Kun, WANG Leilei, SU Jun, MA Hong, LI Yonglong, XUE Yongbo, LIU Yanqing
2020, 37(6): 753-756. doi: 10.3969/j.issn.1001-5620.2020.06.013
Gel lost circulation materials (LCM) currently in use have some deficiencies such as poor gelling controllability and weak structural strength at high temperatures. To deal with these problems, a temperature sensitive gel lost circulation material (LCM) BZWNJ was developed with Curdlan gum. Laboratory study showed that BZ-WNJ forms solid gel between 80 ℃ and 180 ℃, and has broad-spectrum temperature sensitivity. Compared with Curdlan gum, the gel strength of BZ-WNJ is increased by 137%. Meanwhile, using BZ-WNJ, the effects of large particle solids on high temperature gelling are minimized, making BZ-WNJ compatible with other particulate LCMs and fibrous LCMs in sealing off fractures through which the mud is lost, increasing the viscous resistance in mud loss channels and enhancing the pressure-bearing capacity of the formation.
A Well Cementing Slurry Used in Arctic Permafrost
ZHANG Fuming, QI Ying, CHEN Xiaohua, MA Xiaokang, CUI Xinsen
2020, 37(6): 757-762. doi: 10.3969/j.issn.1001-5620.2020.06.014
Petroleum exploration and development in the Arctic area in recent years has been accelerating. Well cementing operation in this area has long been facing with ultra-low temperature (-9 ℃) and the precious time available for operation; the cement slurry is required to have strength development in 24 hours at temperatures below zero. Using a self-developed low temperature gelling agent C-SE8 and a self-developed retarder H10S, several ultra-low temperature cement slurries were formulated with class G cement and other additives in fresh water, sea water and 14% NaCl solution. Evaluation of the cement slurries showed that a cement slurry of 1.50 g/cm3 had 24 h compressive strength of at least 3.6 MPa at -10 ℃; another cement slurry of 1.90 g/cm3 had 24 h compressive strength of at least 6.8 MPa at -10 ℃. The working temperatures of the cement slurries were between -10 ℃ and 30 ℃. The cement slurries had good rheology, and the thickening time can be easily adjusted, making them suitable for well cementing in arctic permafrost.
A Failure Criterion of Oil Well Set Cement Based on Porous Media Theory
DING Jiadi, SHEN Jiyun, ZHANG Shuo, JI Hongfei, WANG Linlin
2020, 37(6): 763-770. doi: 10.3969/j.issn.1001-5620.2020.06.015
Set cement is a porous medium comprising cement skeleton and pores. When becoming solidified after hydration, the set cement in a well still has free water in its pores, and the free water is connected with fluid in the formations. Hence, the mechanical behavior of a set cement is influenced by the pore pressure of the formation and the external loads. To further reveal the mechanical performance of set cement in actual working conditions, triaxial mechanical experiment was conducted on set cement based on the guidance of the theory of porous media mechanics. Data obtained from the experiments were used to determine the Mohr-Coulomb failure criteria taking into account the pore water pressure. The experiments were conducted on Jiahua oil well cement. By changing the confining pressure, water drain conditions and pore water pressure, various mechanical parameters of the set cement were obtained. It was found from the experimental results that the pore water pressure is an important factor affecting the failure strength of the set cement. The Mohr-Coulomb criteria model not taking into account the porous media mechanics of the set cement are non-linear, while the Mohr-Coulomb envelope taking into account the porous media mechanics of the set cement are linear, from which the criterion formulae were calculated.
A Cementing Slurry Used in Alternating Ultra-High Temperatures
ZHANG Hong, YANG Yan, YU Wenyan, LI Lukuan, ZHANG Xingguo
2020, 37(6): 771-776. doi: 10.3969/j.issn.1001-5620.2020.06.016
Alternating ultra-high temperatures in heavy oil thermal producers have significant effects on the mechanical performance of set cement. In developing a high temperature cement slurry, XRD, TG nitrogen adsorption and SEM were used to study the effects of metakaolin and graphite on the compressive strength of set cement, the chemical structure and micro-structure of the hydration products of the cement under alternating ultra-high temperatures. The study showed that alternating ultra-high temperature can change the pattern of the C-S-H bonds of a sand-contained set cement from “chain” or “network” to “particle”, thereby damaging the structure integrity and reducing the compressive strength of the set cement. After blended with metakaolin and graphite, the set sand-contained set cement has its ability to resist alternating ultra-high temperature improved, and the metakaolin and graphite have only minor effects on the phase composition of the set cement. The metakaolin has particle filling effect and volcanic ash effect, the graphite has good bonding with the cement body; these two factors help enhance the structural integrity and mechanical property of the set cement in two dimensions. All these research findings have provided references to the performance evaluation and composition optimization of cement slurries for heavy oil thermal producers.
Effects of Physical Properties of SiO2 Crystalline State on Mechanical Properties of High Temperature Set Cement
GENG Chenzi, YAO Xiao, DAI Dan, LI Xuenian, JIANG Tao, YAN Lianguo, WU Xuechao
2020, 37(6): 777-783. doi: 10.3969/j.issn.1001-5620.2020.06.017
The decline of the high temperature mechanical properties of set cement in oil wells has significant influences on the safety of deep reservoirs and the life span of the wells. Studies on the decline patterns of set cement’s high temperature strengths help to improve the long-term high temperature mechanical properties of the set cement. Silica leaching, one of the important factors leading to the decline of cement’s high temperature mechanical properties, has not yet been taken seriously. In this study, the effects of temperature on the solubility of different crystalline silicas have been investigated, and the compressive strength of the set cement with sand at elevated temperatures analyzed. It was proved that the solubility of silica increases with increase in temperature, and the solubility of non-crystalline silica is much larger than the solubility of crystalline silica. With the increase in the solubility of silica, the dissolution of silica in the early stage of hydration promotes the development of the early-stage high temperature compressive strength of the set cement. In the late stage of the high temperature reaction, silica leaching takes place in the hydration products, resulting in decline of the high temperature strength of the set cement. The high temperature compressive strength of set cement in static water is higher and more stable than the high temperature compressive strength of set cement in dynamic water. A high silica saturation in a curing environment helps make the high temperature mechanical properties of set cement more stable. Based on the analysis of silica leaching at high temperatures, it was found that treatment of cement slurries with sand comprising mainly crystalline silica and minor content of non-crystalline silica help improve the stability of high temperature mechanical properties of the set cement.
Study on Controllable Slick Water Based on Stimulus Response Strategy
LI Yuanzhao, LI Ting, WANG Li, DAI Shanshan
2020, 37(6): 784-788. doi: 10.3969/j.issn.1001-5620.2020.06.018
In some areas with complicated geological conditions, low porosity, low permeability and low formation pressures, tough problems such as gas reservoirs developed with micron and nanometer sized pores, narrow pore throats, high displacement pressures and poor connectivity etc. are often encountered, which inevitably result in serious damage to water block ability and more difficulties in flowing back fracturing fluids. To solve these problems, stimulus response surfactants were introduced into the water solution of hydrophobic associating polymers to render slick water controllable viscosity. The friction of the slick water formulated can be reduced by 78.1%. The difficulties of flowing back the slick water were greatly mitigated through regulation and control, and formation damage was further reduced. Dynamic light scattering experiment was used to prove that the molecules of the surfactants can be assembled into different structures at different pH values. The hydrophobic associating polymers can interact with these structures to realize the viscosity control of the slick water. The slick water system formulated has good friction reducing property and swelling inhibition ability.
Research and Application of FHG Fracturing Fluid
Wang Muqun, Wu Guodong, Yao Xuyang, Zhou Xingwang, Maieryemuguli·Anwaier
2020, 37(6): 789-793. doi: 10.3969/j.issn.1001-5620.2020.06.019
In order to meet the requirements of continuously mixing fracturing fluid of volume fracturing for horizontal wells and alleviate the shortage of HPG, the paper studied the FHG fracturing fluid. Through the fineness classification and surface treatment of guar gum, it could quickly disperse and hydrate, and replaced the conventional quick soluble HPG, which provided a new path for the fracturing fluid system of volume fracturing for horizontal wells. In this paper, the matching bactericide was optimized, the stability of fracturing fluid was increased by 70% in 72 hours; the matching crosslinking agent was prepared, which could effectively reduce the concentration of thickener, solved the problems of high viscosity of base fluid, fast crosslinking speed of gel, high residue content, and improved the sand mixing state, construction friction and reservoir damage.The results showed that swelling rate of FHG fracturing fluid was more than 90% in 3 minutes, viscosity retention rate of 72 h base fluid is over 85%, the viscosity reached 200 mPa·s after shearing for 1 hour at 120 ℃and 170 s-1, and the residue content after breaking was less than 400 mg·L-1, which could be applied to fracturing operation at 30-120℃. The fracturing fluid had been used in 5 horizontal wells of Xinjiang Oilfield, and the effect of operation and production was good.
Study on Weighted Slick Water Fracturing Fluid for Deep Buried Oil and Gas
WANG Liwei, YANG Jingxu, GAO Ying, YANG Zhanwei, TENG Qi, HAN Xiuling, XU Minjie
2020, 37(6): 794-797,802. doi: 10.3969/j.issn.1001-5620.2020.06.020
In fracturing the ultradeep gas reservoirs in the piedmont structure in Kuche, Tarim Basin, 75% of the wells were operated at pump pressures above 100 MPa, the highest pump pressure being 136 MPa. The development of the gas reservoirs has long been limited by the fracturing operation because of the high pump pressures. Statistic data showed that when fracturing ultradeep wells, an increase in the density of the fracturing fluid did not result in the designed pump pressure decrease. Based on theoretical analysis and problems encountered in fracturing with high density fracturing fluids, a weighted slick water fracturing fluid was developed with several agents selected such as a weighting agent, a salt resistant friction reducer and a cleanup additive. In developing the slick water fracturing fluid, experiences of successfully using slick water in shale gas development were borrowed, and the advantages of weighted fracturing fluids were taken. The slick water fracturing fluid has a density of 1.35 g/cm3 and is resistant to the contamination by 35×104 mg/L of CaCl2. With this slick water, the operation pressure can be effectively reduced and operation risks minimized. Similar to conventional guar gum fracturing fluids, this slick water can reduce friction by 62%. The slick water has good high temperature stability and cleanup ability. It is resistant to shearing. Cores tested with this slick water had permeability impairment of only 11.2%. The development of the slick water fracturing fluid has provided a technical support to the stimulation of ultra-high pressure and ultradeep reservoirs.
Study on Dynamic Characteristics of Acid Rock Reaction and Acid Fracturing Countermeasures in Complex Heterogeneous Carbonate Reservoirs
ZHONG Xiaojun, ZHANG Rui, WU Gang, YIN Zheng, WANG Xiaochao, LU Hao, GAO Yuebin
2020, 37(6): 798-802. doi: 10.3969/j.issn.1001-5620.2020.06.021
Different from the domestic and overseas large seam hole type carbonate reservoir, northern Langgu depression Yangshuiwu buried hill in Jizhong depression has its own unique characters such as high buried depth, high temperature, low permeability, dense reservoir spaces and strong heterogeneity. Under those circumstances, fracturing acidizing transformation became the necessary technology in order to improve the single well production but it still has shortcomings like poor pertinence due to the different lithology and fracture development, complex acid-rock reaction.From the analyses of the reservoir characters of Yangshuiwu buried hill fengfeng group, upper majiagou group, lower majiagou group, and liangjiashan group, this essay carried out the study on acid rock reaction controlling factors, build up acid-rock reaction kinetics equation in different types of reservoirs. According to the results of acid-rock reaction experiment and fracture conductivity evaluation, this essay put forward personalized acid fluid formula and countermeasures of the above four sets of reservoirs. It has efficiently guided the reconstruction of 13 Wells in those blocks. Beside providing a technical support for the use of reservoirs in 100-million-ton scales, this essay also provided a reference for the design of the similar matrix of fractured carbonate rock reservoir reconstruction in domestic field.
A High Temperature Block Removal Fluid for Offshore Application
MA Shuangzheng, ZHANG Yaoyuan, ZHANG Guochao, WANG Guanxiang, CHEN Jinding, NAN Yuan, LI Yuankui
2020, 37(6): 803-808. doi: 10.3969/j.issn.1001-5620.2020.06.022
The sandstone reservoir penetrated by the well X-1 in an offshore oilfield has the characteristics of high temperature, abnormally high pressure and low permeability. Dissolution pores are developed in the reservoir rocks. Intergranular fractures in the reservoir rocks are full of various kinds of clays which are easy to cause water sensitivity and flow velocity sensitivity. To solve these problems, a blocking removal fluid was developed for use in the high temperature low permeability sensitive reservoirs. Laboratory experimental results showed that at 170℃, the average corrosion rate of the steel strip in the blocking removal fluid is 62.880 g/cm2·h, meeting the first-grade standard of the industry. The blocking removal fluid has lower surface tension, the surface tensions of the fresh acid and residue acid are all less than 24.0 mN/m. The blocking removal fluid has good ferric ion stability, it can stabilize 263 mg/mL of ferric ions in a system. The blocking removal fluid has good clay swelling inhibition capacity, the final rate of swelling of a sample can be controlled below 32.19%, this is helpful to effectively inhibit water sensitivity impairment to the reservoir. After injecting the blocking removal fluid into a core, the permeability of the core was apparently increasing. The blocking removal fluid is ideal for removing blocks existed in high temperature low permeability reservoirs because the dissolution rates of the blocking removal fluid to clay minerals and the matrix of the rock are high, the blocking removal fluid do not cause pore throats to be blocked by the produced sands, and the permeability of the core can be increased by 3.5 times. Field application showed that the blocking removal fluid removed almost all the blockage near the wellbore. Comparison of the daily gas production rates before and after acidification of the reservoir showed that the acidizing job has done very well in removing the blockage in the reservoir formation.