High-pressure Wells Research Articles

Study on the Equivalent Density Tool and Depressurisation Mechanism of Suction-Type Depressurisation Cycle

In order to further regulate equivalent circulating density (ECD), a novel downhole apparatus for reducing circulating pressure in high-temperature and high-pressure wells, the suction-type ECD reduction tool, was devised. The utilisation of this tool enables the bottomhole pressure of the equivalent circulating density to be attained in close proximity to its hydrostatic pressure, thereby facilitating the attainment of deeper drilling depths. The tool is composed primarily of a screw motor, scroll blades, annular seals, universal joints, and drilling columns. The tool operates by utilising the suction effect and hydraulic energy extracted from the circulating fluid by the screw motor, which is then converted into mechanical energy to create suction and enhance the flow energy of the drilling fluid within the annulus at the bottom of the well, thereby reducing the equivalent circulating density. Furthermore, based on ANSYS-FLUENT analysis simulations, the alteration of pressure drop characteristics in response to varying drilling fluid densities, displacements, and tool sizes was modelled. The simulation results demonstrate that the pressure drop effect is 1.0 MPa when the drilling fluid density is 1.2 g/cm3, 1.7 MPa when the drilling fluid density is 1.5 g/cm3, and 1.9 MPa when the drilling fluid density is 1.8 g/cm3. A pressure drop of approximately 2.3 MPa was observed when the drilling fluid density was 2.0 g/cm3. The maximum pressure drop is achievable with a flow rate ranging from 1500 to 2500 L/min. A maximum pressure drop of 2.3 MPa is observed when the flow rate is within the range of 1500 to 2500 L/min. Two distinct viscosity values (0.02 and 0.06 kg/(m·s)) were employed to assess the impact of viscosity on pressure drop characteristics in a suction-type ECD tool. The results demonstrated that the pressure drop remained largely unaltered, indicating that viscosity had minimal influence on this parameter. The flow rate emerged as the primary factor affecting pressure drop, with viscosity exerting a relatively minor effect.

Research and Application of Temporary Plugging Agent Technology for High-Pressure Wells in Gas Storage Facilities

Before various construction of gas storage well, in order to ensure safety, the reservoir must be temporarily blocked, degassed by circulation and no gas in the well can be operated. There are many temporary plugging methods for oil and gas wells. This paper studies the more advanced micro mesh gel temporary plugging technology in the industry and its application in gas storage wells, which mainly solves the problems of poor degradation backflow effect and difficult permeability recovery caused by weak formation stability after temporary plugging of gas storage wells. Research points: (1) On the basis of ordinary gel, through the fusion with cross-linking agent with special structure, a micron network polymer with significant steric hindrance effect on water molecules is finally formed, which improves the strength and stability of the gel system. (2) Add hexamethylene tetramine, bisphenol propane, delayed cross-linking agent and stabilizer into the polymer aqueous solution. It is verified by laboratory tests that the micron mesh gel can be formed after constant temperature coagulation for 3h~70h at ambient temperature of 90°C~170°C. (3) The temperature resistance, permeability and gel breaking of micron mesh gel are tested in the laboratory, and the results can meet the construction requirements. (4) After the temporary plugging operation of Well Su 49K-2X in the gas storage reservoir of Huabei Oilfield is completed, the degradation products of gel breaking will flow back smoothly to ensure that the well can be put into normal injection and production quickly. The test results show that: (1) Micron mesh gel has the advantages of long plugging validity, high temperature resistance, low viscosity after gel breaking, no residue, thorough gel breaking, no formation plugging pollution, and no impact on the original reservoir permeability. It is a new green plugging technology suitable for deep buried high-temperature depleted oil and gas reservoirs. (2) Before construction, the well temperature shall be measured to conduct test injection, so as to prevent gas invasion from affecting the construction effect. The pump injection displacement is designed to be redundant, so as to prevent the low molecular solution from not reaching the design position in the well on time, and the formation of solid rubber plugs at other positions in the well from affecting the construction.

Emergency Pump-Rate Regulation to Mitigate Water-Hammer Effect—An Integrated Data-Driven Strategy and Case Studies

Pump-rate regulation is frequently used during hydraulic fracturing operations in order to maintain the pressure within a safe range. An emergency pump-rate reduction or pump shutdown is usually applied under the condition of sand screen-out when advancing hydraulic fractures are blocked by injected proppant and develop wellhead overpressure. The drastic regulation of the pump rate induces water-hammer effects—hydraulic shocks—on the wellbore due to the impulsive pressure. This wellbore shock damages the well integrity and then increases the risk of material leakage into water resources or the atmosphere, depending on the magnitude of the impulsive pressure. Therefore, appropriate emergency pump-rate regulation can both secure the fracturing operation and enhance well-completion integrity for environmental requirements—a rare mutual benefit to both sides of the argument. Previous studies have revealed the tube vibration, severe stress concentration, and sand production induced by water-hammer effects in high-pressure wells during oil/gas production. However, the water-hammer effect, the induced impulsive pressures, and the mitigation measures are rarely reported for hydraulic fracturing injections. In this study, we present a data-driven workflow integrating real-time monitoring and regulation strategies, which is applied in four field cases under the emergency operation condition (screen-out or near screen-out). A stepwise pump-rate regulation strategy was deployed in the first three cases. The corresponding maximum impulsive pressure fell in the range of 3.7~7.4 MPa. Furthermore, a sand screen-out case, using a more radical regulation strategy, induced an impulsive pressure 2 or 3 times higher (~14.7 MPa) than the other three cases. Compared with the traditional method of sharp pump-rate regulation in fields, stepwise pump-rate regulation is recommended to constrain the water-hammer effect based on the evolution of impulsive pressures, which can be an essential operational strategy to secure hydraulic fracturing and well integrity, especially for fracturing geologically unstable formations (for instance, formations near faults).

Application of separate layer water injection in high differential pressure wells

With the development of a heavy fine-RRB-layering system and dynamic adjustment, the number of large differential pressure wells increases gradually. The effect of high-pressure difference wells on water injection development is that it is difficult to separate water injection allocation, low pass rate of layers and short effective period of separate sealing, which affects the development effect of water flooding. For this reason, the research on stratified water injection technology with large pressure differences is carried out using step-by-step throttling. The throttling pressure difference borne by the water nozzle is reduced. The large throttling pressure difference produced by the water nozzle is realized. The qualified rate of the layer section is increased to improve the anti-creep performance of the expansion Packer and the sealing effect of large pressure difference injection wells and to extend the service life of the Packer. The field application results of 216 wells in the Shengli Oil Field show that the technique can effectively improve the pass rate of the layers and the sealing effect of the layers and prolong the life of the string.

Research on the Suitability of High-Density Leakage Plugging in Offshore High Temperature and High Pressure Wells

A large number of fractured formations are developed in the high-temperature and high-pressure formations of the Yingqiong Basin in the South China Sea. During drilling, the risk of lost circulation is ex-tremely high, which will cause complex downhole accidents and seri-ously affect the drilling speed.In order to realize safe and efficient plugging of HPHT Wells, the following studies are carried out in this paper: Firstly, the characteristics of leakage, types of leakage and plug-ging and prevention mechanism of HPHT formation in Yingqiong Ba-sin are clarified based on core and indoor rock mechanics experiments. Secondly, a simulated plugging evaluation device with high tempera-ture resistance of 180 °C and high pressure resistance of 20Mpa was in-vented and applied to accurately evaluate the reservoir leakage behav-ior in Yingqiong Basin. Finally, a series of anti-high temperature plug-ging agents adapted to different loss types are systematically selected for the first time for different formation fracture types and the plugging effect is evaluated. In this study, through mechanism research, device research and development, accurate evaluation, the shaft wall pressure equivalent increased to 0.1g/cm3 without leakage. It provides technical support for the subsequent ultra-high temperature and high pressure stratum with weak leakage and narrow pressure window.

Research on Wellbore Integrity Assurance Technology for Deepwater High-Pressure Oil and Gas Wells

Annulus pressure control is critical to well safety in deepwater oil and gas wells, and it is crucial for deepwater high-pressure oil and gas wells, which are related to production safety. At present, the deepwater annular pressure analysis model is mainly based on the trapped annulus principle. For the high annular pressure of deepwater high-pressure oil and gas wells, it brings great management and control challenges. This paper proposes a deepwater high-pressure oil and gas well annular pressure analysis method considering formation connectivity. According to the existing measures of annular pressure management and control, the differences between various types of annular pressure management and control technology are systematically analyzed and expounded, and the annular pressure management and control technology of deepwater high-pressure oil and gas wells is proposed accordingly. At the same time, combined with the actual case of a deepwater high-pressure well in the South China Sea, the annular pressure considering different influencing factors is analyzed, and the appropriate management and control methods of annular pressure are recommended. This paper systematically summarizes and studies the analysis and control technology of annular pressure in deepwater high-pressure oil and gas wells, which provides a technical basis for China’s deep water to move from conventional deepwater to deepwater high-pressure, and can provide a reference for the management and control of annular pressure in oil and gas wells in subsequent deepwater projects.

The deposition of asphaltenes under high-temperature and high-pressure (HTHP) conditions

In this work, the factors affecting asphaltenes deposition in high-temperature and high-pressure wells were studied using backscattered light and PVT equipment customized to suit the well conditions. In an examination of the intensity of backscattered light, it was revealed that there exists a linear relationship between temperature and asphaltene precipitation within a specific temperature range. Within this range, a decrease in temperature tends to accelerate asphaltene precipitation. However, the impacts of pressure and gas-oil ratio are more pronounced. The pressure depletion induces the asphaltenes to precipitate out of the solution, followed by the formation of flocs below the bubble point. In addition, an increase in the gas-oil ratio causes a more severe asphaltene deposition, shifting the location of asphaltenes to deep well sections.

Selection of key additive materials for white oil – based drilling fluids

The selection of key additive materials for a new type of oil-based drilling fluid was studied in this paper. The oil-based drilling fluid can strengthen well walls and ensure safety. It is suitable for high-temperature and high-pressure wells, deep wells and ultra-deep wells. A new type of high-temperature white oil-based drilling fluid was prepared by using 5# white oil as continuous phase, HIS as thickening agent, SDBS as emulsifier, and asphalt powder oxidized at 180°C as filtration agent. The results showed that the saturation concentration of sodium dodecyl benzene sulfonate (SDBS) was 4%, the saturation concentration of asphalt powder oxidized at 180°C was 4%, the saturation concentration of Tween-80 was 10%. The final resistance of high temperature and high pressure oil based drilling fluid formulation material is: No. 5 white oil + 4% SDBS + 5% modified bentonite + 4% asphalt powder oxidized at 180°C + 10% Tween-80 + 1.5% Barite + CaO. The performance evaluation of the new oil-based drilling fluid shows that shale expansion is 0.21mm, anti-temperature up to 220°C, and anti-pollution ability is good. The rheological properties, resistance of high-temperature high- pressure have been greatly improved. Therefore, the new white oil-based drilling fluid can resistance of high- temperature and also has low toxicity, which can meet the exploration and development of more complex wells.

Designing Mesh Turbomachinery with the Development of Euler’s Ideas and Investigating Flow Distribution Characteristics

This research discusses developing an Euler turbine-based hybrid mesh turbomachinery. Within the framework of mechanical engineering science, turbomachinery classification and a novel method for mesh turbomachinery design were considered. In such a turbomachine, large blades are replaced by a set of smaller blades, which are interconnected to form flow channels in a mesh structure. Previous studies (and reasoning within the framework of inductive and deductive logic) showed that the jet mesh control system allows for operation with several flows simultaneously and provides a pulsed flow regime in flow channels. This provides new opportunities for expanding the control range and reducing the thermal load on the turbomachine blades. The novel method for performance evaluation was confirmed by the calculation: the possibility of implementing pulsed cooling of blades periodically washed by a hot working gas flow (at a temperature of 1000°C) and a cold gas flow (at a temperature of 20°C) was shown. The temperature of the blade walls remained 490–525°C. New results of ongoing research are focused on creating multi-mode turbomachinery that operates in complicated conditions, e.g., in offshore gas fields. Gas energy is lost and dissipated in the throttle at the mouth of each high-pressure well. Within the framework of ongoing research, the environmentally friendly net reservoir energy of high-pressure well gas should be rationally used for operating a booster compressor station. Here, the energy consumption from an external power source can be reduced by 50%, according to preliminary estimates. Doi: 10.28991/CEJ-2022-08-11-017 Full Text: PDF

Kick Prediction Method Based on Artificial Neural Network Model

Kick is one of the most important drilling problems, and because its occurrence makes drilling engineering extremely complex, it is essential to predict the possibility of kick as soon as possible. In this study, k-means clustering was combined with four artificial neural networks: regularized RBFNN, generalized RBFNN, GRNN, and PNN, to estimate the kick risk. To reduce data redundancy and normalize the drilling data, which contain kick conditions, k-means clustering was introduced. The output layer weights were then determined using a brute-force search with different Gaussian function widths, resulting in a series of artificial neural networks composed of different clustering samples and different Gaussian function widths. The results showed that the prediction accuracy of regularized RBFNN + k-means model was the highest, that of the GRNN + k-means model was the lowest. The kick prediction accuracy for regularized RBFNN, generalized RBFNN, GRNN, and PNN were 75.90%, 65.20%, 51.70%, and 70.16%, respectively. This method can be used to enhance the speed and accuracy of kick risk prediction in the field while facilitating the use of and advances in risk warning technology for deep and high-temperature and high-pressure wells.

Analysis and Mitigation of High-Pressure and High-Temperature Well Completion Design of Elkin/Franklin Fields in the North Sea

The development of High-Pressure and High-Temperature (HP/HT) wells is accompanied by high risk, and still represents one of the greatest technological challenges for the oil and gas industry related to the equipments used and their ability to sustain these conditions. The results analysis of data is key to investigating reasons for bad performances and failures of well completion design and detecting at an early stage potential downhole events.This paper applies machine learning to the results of real data analysis of deep and deviated well in the HP/HT environment. It presents techniques used to analyze design limits for the tubing string of the well with different rates of production and water injection, and predict pressure and temperature when multiple operations are applied to the tubular string during the well's lifetime. It also analyzes the most important parameters that impact the tubular string, such as temperature effect, safety factors, and tubing length change. A simulation model for a well has been developed to accomplish the objective of this work by using WellcatTM software modules (Prod & Tube) based on real data from the Elgin/Franklin fields in the North Sea. Two designs of tubular string were used to analyze design limits; the first included a tubing size of 4 ½ in and a latched permanent packer, and the second was identical to the first one but included an expansion joint tool to allow free movement of the tubing, and it was used to mitigate the first well completion design failure. Based on the results of this paper, three load cases (produce-6 months, tubing leak, and water injection) failed in the first design when the rates of oil production and water injection were increased to 12000 bbl/d and 5000 bbl/d respectively, whilst all load cases fell into the triaxial envelope and met the axial criteria in the second design. Furthermore, the predicted results of pressure and temperature for the tubing and surroundings indicate the tubular string could be exposed to buckling problems and serious thermal expansion in the annulus. As well, tubing length can be changed (elongated or shortage) owing to thermal effects during multiple load cases.

Prediction of annulus liquid level depth in high-temperature and high-pressure gas wells based on sustained casing pressure

Annulus liquid level depth is used to describe the variation of sustained casing pressure, calculate the leakage location, and reflect the hydrocarbon content in annulus. There are currently no theoretical prediction methods for it. Thus, a prediction model and numerical solution method for the annulus liquid level depth are established, and this model is then utilized to analyze the effects of various factors on the annulus liquid level depth. The research results show that the wellhead temperature, initial tubing-casing annulus pressure, and the amount of annulus gas released have a significant influence on the annulus liquid level depth by changing the annulus liquid compression and string deformation. The impact of a huge annular pressure change on the annulus liquid compression is noticeable, which is beneficial to improving the prediction accuracy of the annulus liquid level depth. Therefore, this prediction method is better suited to high-pressure wells than the echo-sounding method.

Development of a New Technique for Emulsifiers Optimization

Summary The primary and secondary emulsifiers of the oil-based muds (OBMs), which are the main expensive chemicals, need to be added to control the emulsion stability and the mud properties. Invasion of the filtrate introduces excess emulsifiers in the reservoir and leads to formation damage in forms of wettability alteration and permeability reduction, hence resulting in a decrease of the well productivity. This is recognized as one of the major mechanisms of the formation damage during overbalanced drilling, having significant economic impact on the petroleum industry, particularly for high-pressure and high-temperature wells. In the present work, experimental study has been carried out to assess the performance and the influence of the emulsifier’s concentration on the emulsion stability and the formation damage. A new technique has been developed based on the particle size analyzer (PSA), which can be used for optimizing emulsifier’s concentration and assessing the quality performance of various emulsifiers. The optimization and the emulsion stability results have been validated by standard American Petroleum Institute (API) testing procedure and return permeability tests. The key parameters which are useful and relevant to optimum emulsifier’s selection are to prevent the barite sag and to minimize the formation damage to increase the well productivity.

Research on Non-Linear Flow Characteristics for the Expandable Packer Rubber in High Temperature and High Pressure Wells

Research on Non-Linear Flow Characteristics for the Expandable Packer Rubber in High Temperature and High Pressure Wells

Application of combined test string of RD bypass pressure test valve and RD safety circulation valve

At present, in the test construction of high temperature, high pressure and high hydrogen sulfide wells, in order to simplify the pipe string structure and improve the process success rate, the combination of RD safety circulation valve and OMNI multiple circulation valve is often used to carry out the triple operation of perforation+acid fracturing+test, which can realize the operation of one opening and one closing. However, due to the complex structure, high failure rate and high construction cost of the OMNI multi-cycle valve, most operators are unwilling to use it, but without the pipe string of the OMNI multi-cycle valve, the slurry replacement operation cannot be completed. This paper introduces an RD bypass pressure test valve which can replace OMNI multi-cycle valve. It can not only realize the function of slurry replacement, but also increase the success rate of operation because of its simple structure, so it is more and more favored by users.

Force Analysis of Logging Cable in Deep Well

With the increase of deep wells, high temperature and high pressure wells and complex wells, the demand for logging is also increasing. Wireline logging is an important technical means to obtain downhole data in the process of petroleum testing. This paper establishes a cable mechanics model by analyzing the main influencing factors of the cable force in the inclined well section or the vertical well section. Calculate the lifting power of the tool. Through logging calculation, the force change law of the downhole cable and tool string is obtained when the wellhead pressure changes.

Formation Pressure Estimation Method for High Temperature and High Pressure Wells in Ledong Area of South China Sea

Formation Pressure Estimation Method for High Temperature and High Pressure Wells in Ledong Area of South China Sea

The detection and distribution of formation pressure with Fan simple method in Yingxiongling Area

In the Yingxiongling Area of Qaidam Basin, the formation pressure system is complicated in vertical, and the high pressure mechanism has not been made clear, which has brought a great challenge to the drilling work. To solve this problem, in this study, an advanced method with acoustic velocity-density crossplot has been used to analyze the abnormal formation pressure in the Yingxiongling Area of the Qaidam Basin. The results have shown that the abnormal high pressure in the Yingxiongling Area is mainly caused by the under-compaction, and is mainly concentrated in the layers form N22 to E32. According to the pressure mechanism, the Eaton method and the Fan simple method have been selected to calculate the formation pressure in the typical high-pressure wells in the Yingxiongling Area of Qaidam Basin. By comparing with the formation pressure control data, it has been found that the Fan simple method is more consistent with the actual situations and the accuracy is higher. With the Fan simple method, the vertical and lateral distribution of the formation pressure in the Yingxiongling Area have been obtained. The pressure distribution is consistent with the actual drilling conditions, which provides good guidance and reference for the smooth drilling of the Yingxiongling Area. The application results indicate that this method has a good prospect for promotion and application, laying a good foundation for next work.

Integrity Analysis of Casing Premium Connection under High Compression Load

With the increasingly harsh conditions of complex oil and gas wells such as high-temperature and high-pressure deep wells and long-distance horizontal well, the integrity of casing string puts forward higher requirements for compression performance of premium thread connections. The requirements of high compression resistance of connection is complicated, including ensuring the integrity of structure and sealability for thread at the same time under high compression load being equal to the bearing capacity of casing body, and considering the structural fatigue, environmental fracture and seal failure caused by the weakening of thread bearing performance under cyclic load. Based on the failure cases of some casing connections, laboratory tests and finite element analysis results, this paper discusses the key technical points in the above mentioned problems, and provides the suggestions for the performance optimization of high-performance casing premium connections based on failure prevention.

Low-Force Shear Blades Developed for High-Strength Coiled Tubing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204403, “Development of Low-Force Shear Blades for High-Strength Coiled Tubing,” by Scott Sherman, Nexus Energy Technologies, prepared for the 2021 SPE/ICoTA Virtual Well Intervention Conference, 22–25 March. The paper has not been peer reviewed. As coiled tubing (CT) grades have evolved during the past 20 years and wall thicknesses have increased, the resulting force required to shear coil has more than doubled. An industry need existed to develop a shear blade for blowout preventers (BOPs) that could cut high-strength CT using legacy pressure-control equipment already in use. The paper describes the iterative process of development of a novel shear blade able to cut high-strength CT with 50% of the normal shear force. Objective The objective of the work detailed in the complete paper was to develop a novel CT-shearing system capable of cutting high-strength heavy-wall CT with reduced hydraulic pressures. Considering that CT will continue to evolve in terms of yield strength, the goal of the study was to future-proof BOPs wherever possible to protect customers from the liability of obsolete equipment. The authors write that, ultimately, BOPs will need to cut 175-grade CT strings with a 7-mm wall thickness with 103 MPa of wellbore pressure and less than 17.2 MPa hydraulic pressure. Development Process Initially, the following five options were considered: - Larger-diameter cylinders. This seemingly simple option, which would generate more shear force, was ruled out because the implementation would not be backward-compatible with existing well-control equipment and the larger cylinder volume would result in slower cycle times. - Boosted actuators. These could double shear force while maintaining piston diameter. While this solution is simple, theoretically, these actuators require twice as much hydraulic fluid from the accumulator to function. This results in a closing time that is nearly double that of a nonboosted actuator. - Pressure-balanced actuators. With this option, hydraulic forces would not need to overcome the forces related to wellbore pressure in addition to providing sufficient force to shear CT. These actuators do increase the amount of shear force available to cut CT when used on high-pressure wells. However, they increase complexity, cost, and weight and could result in trapped wellbore fluids within the actuator that could lead to corrosion-related issues. - Increasing hydraulic pressure to a given set of rams using a pressure multiplier for the shear rams or a similar system. This solution was deemed unsuitable because the hydraulics of most BOPs are designed for 150% of their rated pressure. Doubling the hydraulic pressure available to the BOP could damage the hydraulic cylinders and associated actuators, resulting in a catastrophic well-control situation. - Modifying shear blade geometry to reduce the shear force needed to cut CT using existing equipment. This was selected as the most-logical approach because the modified shear blades could be retrofitted into existing BOPs. Furthermore, this solution would not require modification to existing wellsite equipment such as accumulator skids and would not increase the weight or size of the BOP stack.