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Ground Breaking Technology in Artificial Lift; 1st Installation of Full Digital Intelligent Artificial Lift DIAL System at DL field, Brownfield Offshore Malaysia
Ismail, Syahezat (PETRONAS Carigali Sdn Bhd) | Sy Rahim, Sy Puteh (PETRONAS Carigali Sdn Bhd) | Yahia, Zaidil (PETRONAS Carigali Sdn Bhd) | Elshourbagi, Saied Mustafa (PETRONAS Carigali Sdn Bhd) | Ishak, M Faizatulizuddin (PETRONAS Carigali Sdn Bhd) | Roslan, M Rizwan (PETRONAS Carigali Sdn Bhd) | Che Hamat, W Afiq (PETRONAS Carigali Sdn Bhd) | Ben Amara, Abdel (Silverwell Energy) | Faux, Stephen (Silverwell Energy) | Makin, Graham (Silverwell Energy)
Abstract Objectives/Scope Moving to digitalization era in the current low oil price environment, paradigm shift is really crucial in managing brownfield development and production. The challenge is to select the best technology to harvest the optimum production from the field but at the same time reduce potential capital and operating expenditure. Methods, Procedures, Process The paper highlights the technology evaluation of Digital Intelligent Artificial Lift (DIAL) system. This includes it's working principles, candidates screening, risk mitigation plan as well as technology success criteria developed specifically for the technology. DIAL system is an in-well gas lift system that can overcome the well design and operational limitations of existing side pocket mandrels and valves. DIAL enables a better gas lift well design as well as able to interconnect downhole and surface monitoring & control in real-time. It provides opportunity for automation, better subsurface and surface integration as well as minimizing well intervention requirement. Based on the promising technology evaluation, one pilot well was identified by the team at DL field. The well was part of DL drilling campaign executed in Q2 2018. Details of the well design & scope, as well as gas lift design for the well will be shared. Commercial comparison was demonstrated between conventional side pocket mandrel system and the DIAL system. Results, Observations, Conclusions The case study at DL field will be discussed in details, starts from their wells’ design, technology deployment strategy, installation, production test result as well as lessons learnt during installation and operationalization of the system. Moving forward from the pilot application, root cause failure analysis was done, lessons learnt were identified, design improvements were proposed and continuous monitoring of the system will be done, according to the success criteria outlined. Potential replication candidates have also been identified by the team with at least 10 promising potential candidates to be installed within the next 2 years. Novel/Additive Information The technology deployment was the result of collaborative works between PETRONAS, Silverwell Energy and Neural Oilfield Service.
- Asia > Malaysia (0.85)
- North America > United States > Texas > Terry County (0.40)
- Information Technology > Communications (0.49)
- Information Technology > Architecture (0.35)
Abstract In this paper, a state-of-the-art wire rope is chosen for investigation regarding its applicability as a sucker rod string. Finite element simulation with Abaqus has been used for a detailed analysis of the rope's performance and possible failures along with its length. The sucker rod string is a key component of sucker rod pumps, transferring the reciprocating movement of the surface polished rod to the downhole pump plunger. It is, however, exposed to severe cyclic loads, causing several complications from damaged rods and broken couplings to time-consuming workover procedures. Hence, continuous strings like wire ropes can be a convenient replacement for the conventional design. The mechanical properties of the introduced wire rope demonstrate high tensile strength and great resistance against creep and fatigue while its uniform design eliminates the chances of connection failure. The proposed wire rope was designed to work in tandem with a sucker rod anti-buckling pump (SRABS) to facilitate its motion. The performance of this system was then simulated using a combination of MATLAB and Python codes, visualized in the interface of Abaqus. These simulations confirm that this wire rope can indeed replace the rod string in a sucker rod pumping unit. Detailed stress, load, and movement profiles were also compiled to allow for a comprehensive analysis. The results pointed out that pumping with a wire rope can be just as productive, or surpass the productivity of a system using conventional sucker rods. They indicate that the efficiency of this design highly depends on the geometry and depth of the well, type, and size of the pump, the compressibility of the produced fluid and string material elasticity. The optimization of the wire rope's performance could be achieved by using compatible Pumpjacks and proper downhole equipment, such as string protectors, all operating together under an optimum pumping speed. This paper presents a noteworthy comparison between the performance of a conventional rod string and a wire rope at two reference wells. Laboratory and field tests are being planned to investigate the full capacity of the rope.
Abstract A system for reducing solids production in Surat basin coal seam gas (CSG) wells was developed in the laboratory and tested in the laboratory and field trials. Several thousand CSG wells were completed in Surat basin in eastern Australia using what was considered an economic method at a time - an open hole with a predrilled liner. Although the majority of the wells are meeting production expectations, a many wells are producing a substantial amount of solids originating from an interburden rock representing approximately 90% of completed interval length and comprising mudstones, sandstones, and siltstones rich in illite/smectite and other water-sensitive clays. Relatively fresh water, with total dissolved solids (TDS) of approximately 4000 to 7000 mg/l, produced from multiple thin coal seams during dewatering and production phases is causing the interburden rock to swell or disintegrate. Prolific wells with high water rates or high gas velocity are capable of carrying solids to the surface where the solids are deposited in separators, flowlines, and water-treatment settling ponds. Higher solids concentration on lower-rate wells are causing issues with positive cavity pumps (PCP), the artificial lift method of choice in CSG wells. Pump intake plugging with solids, excessive torque and rotation seizure, and wear of tubing/rod strings are frequent causes of workovers and shorter-than-expected pump run-life. Some wells are able to flow freely; however, an extra monitoring program is required to ensure wellheads are not suffering from solids-induced erosion. Recompletion of the wells is not considered practical at this stage because pre-perforated joints form an integral part of the 5 ½-in. or 7-in. casing string, which is cemented above the Walloons subgroup coal seams. An external casing packer (ECP) is often used. Some coal seams were underreamed, thus further complicating recompletion. Plugging existing wells and drilling a pair of wells using same surface location and infrastructure have been considered. A chemical wellbore stabilization solution been developed to alleviate/stop solids production from the interburden rock. The treatment comprises two fluids separated by a spacer that contains clay stabilizer that is typically 3 to 7% KCl, the same as drilling mud base. Proprietary surfactant reduces the possibility of coal damage. Regained permeability testing performed using crushed and sieved coal pack plugs indicated a low level of damage. The wellbore stabilization system could be energized/foamed to reduce hydrostatic pressure and increase compressibility, hence increasing the chance of contacting rock surface in an enlarged wellbore.
- Oceania > Australia > Queensland (1.00)
- Oceania > Australia > New South Wales (0.83)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.96)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.89)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
Abstract In days where the oil price is low, cost optimization is of vital importance. Especially in mature oil fields, the reduction of lifting costs by increasing the mean time between failure and the overall efficiency helps to stay economical and increase the final recovery factor. Today a significant portion of artificially lifted wells use sucker rod pumping systems. Although its efficiency is in the upper range, compared to other artificial lift systems, there is room for improvement and system optimization. This paper presents the benefits of the field-tested Sucker Rod Anti-Buckling System (SRABS), which can entirely prevent compressive loads from the sucker rod string by a redesign of the standing valve, the advantageous use of the dynamic liquid level, and the on a case-by-case basis application of a tension mass. This results in complete buckling prevention and a reduction of the overall stress in the sucker rod string. The resulting reduction in the number of well interventions in combination with the higher overall pumping efficiency prolongs economic production in mature oil fields, even in times of low oil prices. The analysis of SRABS, using simulations, showed a significant increase in the overall efficiency. The SRABS performance and wear tests under large-scale conditions are performed at the Montanuniversitaet Leoben's Pump Testing Facility and in the field. The self-developed Pump Testing Facility can simulate the conditions of a 500 m deep well, including the effects of dynamic liquid pressure and temperature. Testing of SRABS has identified major benefits in comparison to standard sucker rod pumps. The results of intensive testing are used to optimize the geometry of the pump body itself and to improve the wear resistance by selecting optimal materials for the individual pump components. SRABS itself can be applied within every sucker rod pumping system; the installation is as convenient as for a standard pump, and manufacturing costs are comparable with those of a standard pump. This paper shows the high performance of the SRABS pumping system in comparison to a standard sucker rod pump.
Research of Non-Stop Intermittent Pumping Production for Beam Pumping Units
Gong, Hongliang (PetroChina Daqing Oil Field Company) | Sun, Yanan (PetroChina Daqing Oil Field Company) | Zhang, Shujin (PetroChina Daqing Oil Field Company) | Qi, Xing (PetroChina Daqing Oil Field Company) | Shi, Guochen (PetroChina Daqing Oil Field Company) | Sun, Chunlong (PetroChina Daqing Oil Field Company) | Wang, Guoqing (PetroChina Daqing Oil Field Company) | Zhang, Deshi (PetroChina Daqing Oil Field Company) | Wei, Feng (PetroChina Daqing Oil Field Company) | Yu, Hou (PetroChina Daqing Oil Field Company) | Qing, Changrui (PetroChina Daqing Oil Field Company) | Zheng, Guoxing (PetroChina Daqing Oil Field Company) | Zhao, Yulong (PetroChina Daqing Oil Field Company) | Gao, Yang (Reseach Institue of Petroleum Exploration and Development)
Abstract A new technology of the non-stop intermittent pumping production for beam pumping units has been widely used in PetroChina Daqing oil field. This technology solves the problems that existed in conventional intermittent pumping production, such as a large fluctuation in fluid level, a long idle time, high labor intensity, frozen wellhead in winter, and difficulty in management, etc. This technology adopts a new strategy. It transforms a long-period intermittent pumping into several short-period intermittent pumping, and changes the crank from shutdown into low-energy swinging motion, at the same time, the plunger piston at downhole is kept stationary while the crank does do non-stop swing operation. Based on the maximum elastic deformation of sucker rods, the optimal swing range and rotary speed of crank are designed by kinematics and load analysis. Meanwhile, the inverter increases the swinging amplitude of crank to build up the gravitational potential energy. With conversion effects from gravitational potential energy to kinetic energy, as well as active control of swing power, a non-impact low energy swinging scheme is formed. The flexible switch between complete-cycle pumping operation and swing operation is successfully realized. According to the situation of a single well, the corresponding working system is formulated. A total of 124 wells had been used this new technology in petroChina Daqing oil field, the filed application shows that, the non-stop intermittent pumping production stabilizes the fluid level within a reasonable range and guarantees a better pump fillage. Compared with the conventional intermittent pumping prodution, the pump efficiency improved 6.54%, the average energy-saving rate ran up to 34.59%. It is significantly improved the pump efficiency and system efficiency, and achieved the purpose of energy saving. The technology of the non-stop intermittent pumping production for beam pumping units is appropriate for the low-yield well and insufficient liquid well. It will be of great significance for the high-efficiency development of low-yield well.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
The Application of Flexible Coiled Composite Pipe in Onshore Oilfields in China
Ming, Eryang (PetroChina Research Inst Petr Expl & Dev) | Li, Tao (PetroChina Research Inst Petr Expl & Dev) | Li, Yiliang (PetroChina Research Inst Petr Expl & Dev) | Pei, Xiaohan (PetroChina Research Inst Petr Expl & Dev) | Hao, Zhongxian (PetroChina Research Inst Petr Expl & Dev) | Guo, Tong (PetroChina Research Inst Petr Expl & Dev)
Abstract In recent years, the flexible coiled composite pipe (FCCP) has developed rapidly in China. Because of its merit about chemical inertness, it has been introduced to onshore oilfields to endurance some severe situations, such as serving as tubing in corrosive and waxy oil wells, as tubing in scaling water injection wells or as surface gathering pipelines, especially suitable for mountainous areas. This paper will introduce the development status of FCCP in different applications. According to our research and development, for FCCP structure manufacture, there are two main technical routes in China, non-adhesive pipe and adhesive pipe. These two kinds of pipe meet the merits of FCCP, however, there are some differences in technical parameters. Obviously, non-adhesive pipe has smaller bending radius, but the integrity of adhesive pipe is better which is good for fitting installation. In this technical stage, the FCCP has been applied in surface gathering system, general water injection system and rodless artificial lift system. For surface gathering system, this is the most mature application of this technology. It has been laid over 30,000 kilometers. Compared with steel pipe, the equipment of FCCP is simple and high laying efficiency. For general water injection system, the FCCP replaces steel pipe by high working efficiency and long endurance. It has been applied more than 80 wells. For rodless artificial lift system, there are almost 60 wells applied FCCP. It is the severest running condition for FCCP with high temperature, high wellbore pressure and high varies suspension force. This application reveals the advancement of FCCP by twining cables inside the pipe body and adding functions of real-time monitoring and heating. Two typical applications are serving as tubing in cold heavy oil production and acid gas corrosion oil well. The application of FCCP has made great progress. But there are several key issues that need to be resolved in the future research. First, there is lack of post evaluation of performance. Second, the limit of material working temperature shrinks the application scope. Third, the external pressure resistance is limited. This paper shows the applications of flexible coiled composite pipe in onshore oilfields of China in the past 5 years, including a summary of technical experience, and proposing the goal of further research.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > China Field (0.97)
- Africa > Middle East > Egypt > Mediterranean Sea > Nile Delta Basin > Tao Field (0.97)
- Information Technology > Architecture > Real Time Systems (0.55)
- Information Technology > System Monitoring (0.34)
CO2 Tracer Application to Supplement Gas Lift Optimisation Effort in Offshore Field Sarawak
Abu Bakar, Azfar Israa (Petronas Carigali Sdn Bhd) | Ali Jabris, M Zul (Petronas Carigali Sdn Bhd) | Abd Rahman, Hazrina (Petronas Carigali Sdn Bhd) | Abdullaev, Bakhtiyor (Petronas Carigali Sdn Bhd) | Idris, Khairul Nizam (Petronas Carigali Sdn Bhd) | Kamis, Azman Ahmat (Petronas Carigali Sdn Bhd) | Yusop, Zainuddin (Petronas Carigali Sdn Bhd) | Kok, Jason Chin (AppSmiths® Technology) | Kamaludin, Muhammad Faris (AppSmiths® Technology) | Zakaria, Mohd Zulfadly (AppSmiths® Technology) | Saiful Mulok, Nurul Nadia (AppSmiths® Technology)
Abstract Field B, located offshore Malaysia is heavily reliant on gas lift due to the high water cut behavior of the reservoir coupled with low-medium reservoir pressure. The field faces a challenge to efficiently execute production enhancement activities due to its low effective man-hour, a drawback of unmanned operation philosophy. The recent oil price downturn further exacerbates the limitation and calls for an innovative approach to continue the effort for maximizing oil recovery. As majority of the producing wells are gas-lifted, Gas Lift Optimization (GLOP) is an integral part of Field B's routine production enhancement job. The previous practice of GLOP involves data acquisition process of surface parameters and wireline intervention to collect Bottomhole Pressure (BHP), mainly Flowing Gradient Survey (FGS). Relying on wireline intervention limits the number of gas lift troubleshooting activities due to the low man-hour availability. To address this constraint, CO2 Tracer application was implemented in a campaign to supplement Field B GLOP effort. CO2 Tracer is a technology whereby concentrated CO2 is injected into the gas lift stream via the casing. CO2 returns are collected at the tubing end and utilized to diagnose the gas lift performance. The CO2 Tracer campaign was successfully executed in Platform A, B and C, covering 58 strings within an effective period of 3 months. This achievement is a milestone for the field as it opens a new approach in GLOP data acquisition process. Several advantages observed by executing this campaign is as follows: Multiplication of opportunities generation due to quick and simple operations of CO2 Tracer survey compared to wireline intervention for FGS. Reduction in HSE risks and intervention-related well downtime due to minimal intrusive requirement for well hook-up. Better understanding of complex dual gas lift completion due to simultaneous survey execution. Supplement CO2 baseline measurement for flow assurance monitoring. Quick quality check on gas lift measurement device. This paper will discuss on the challenges at Field B to implement GLOP, technology overview of CO2 tracer, the full cycle process of the CO2 tracer campaign and results of the campaign. Several examples of the findings will also be shared.
Systematic Approach in Extending Liquid Loaded Offshore Gas Wells Production in Natuna Sea with Partial and Full Wellbore Water Shut Off: Case Study and Method Selection
Praditya, Yusuf Alfyan (Premier Oil Indonesia) | Satiawarman, Anugerah (Premier Oil Indonesia) | Nurrahman, Fahmi (Premier Oil Indonesia) | Medianestrian, Medianestrian (Premier Oil Indonesia) | Rochaendy, Risnawan (Premier Oil Indonesia)
Abstract Wells which produce dry gas reservoirs usually have low bottomhole pressure. But in many instance liquid is associated with the produced gas, it can come from the liquid in reservoir or condensed production liquid. When more liquid is introduced into the wellbore, the pressure gradient along the wellbore is higher. The increased liquid fraction creates higher backpressure on the reservoir delivering gas. In high pressure gas reservoir the presence of liquid can occur in several degree of bubble and slug flow; in depleted gas reservoir the liquid can kill the well as the gas does not have enough transport energy to lift the liquid. At the point when the gas velocity is insufficient to carry out liquid, liquid will start to drop and accumulate in the bottomhole creating a restriction on the gas flow path, the phenomena is called liquid loading. This paper presents success case studies from Premier Oil Indonesia in handling and reactivating four liquid loaded gas wells in Natuna Sea offshore operation. Wellbore configuration and facility limitations in offshore operation (e.g. maximum deck load capacity, water handling capacity and crane capacity) create more complexity of the method selection in comparison to onshore operation. There are many gas well deliquification methods available in the industry, but not in instance that each method is appropriate for all conditions. The case studies presented in this paper provide description of how Premier Oil Indonesia screened several available gas well deliquification methods in the industry and came up with the water shut off proposal as the best and most proper method for its wells. The understanding of liquid loading indication, liquid source identification and operational details of gas well deliquification methods are the most important factors to determine the most effective and cost efficient method to handle liquid loaded wells. This paper also presents a general guideline in selecting the best gas well deliquification method for some specific cases under several operational conditions for onshore and offshore operations.
- Asia > Indonesia (0.88)
- North America > United States > Texas (0.28)
- Asia > India > Andhra Pradesh > Bay of Bengal > Krishna-Godavari Basin > Block KGD6 > G-1 Well (0.99)
- Asia > Middle East > Iran > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > G 3 Field (0.91)
Abstract The development of a new low-carbon operation mode of artificial lift in high-water-cut oilfields, is significant for reducing energy consumption, improving operation efficiency and lowering production costs of oilfields. The annual electric consumption of the oilfield is increasing year by year. In 2016, the total electric consumption exceeded 35 billion kWh, of which the mechanical production system accounts for 57%. The rodless artificial lift eliminates the use of the sucker rod, and reduces the installed motor power over 50%. The electric consumption is greatly decreased, while tremendous gain is seen in the system efficiency. Moreover, the application performance is especially good for low-production wells. Under such circumstances, the operation cost of the oilfield declines. The current rodless artificial lift is basically based on two types of pumps, namely submersible plunger pump and submersible direct-drive screw pump. The submersible plunger pump lifts liquid via vertical reciprocation of the moving body driven by the motor, with daily electric consumption of an individual well decreasing by 46%, from 133.4 kWh to 72.5 kWh. The reduced annual electric cost per well is RMB 14,000, and the annual single-well carbon emission falls by 17.5 tons. As for the submersible direct-drive screw pump, the rotation of the pump is directly motivated by the downhole submersible motor, through which the downhole liquid is elevated to the surface. The daily electric consumption of an individual well decreases by 38.4%, from 224kWh to 138kWh, contributing to the annual electric cost reduction per well of RMB 13,600 and annual carbon emission decline per well of 17.1 tons. The application of the two types of rodless artificial lift has taken initial shape. The submersible plunger pump has been applied to over 200 wells, and the submersible direct-drive screw pump, over 60 wells. The new low-carbon operation mode of artificial lift is critical for the energy saving, efficiency improvement and consequent cost reduction of oilfields, particularly in cases of the industry downturn triggered by low oil prices.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.31)
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- (7 more...)
Abstract Current market conditions in the oil industry call for cost effective well intervention methods to optimize production in wells completed with Insertable Progressing Cavity Pumps (I-PCPs). Rigless rod-string conveyance of I-PCP's traditionally rely on Pump Seating Nipples (PSNs) or mechanical-set I-PCP anchoring devices in wells without PSN's. Although the installation of an I-PCP on a PSN is a reliable method, it requires a PSN to be originally installed within the production tubing, which limits the I-PCP setting depth to the location of the PSN. Rod-string conveyance of mechanical-set I- PCP anchoring devices is limited by the rod string's effectiveness to transmit the required axial loads to setting depth, which becomes increasingly challenging in extended-reach conditions. Other challenges with I-PCP installations include location of previously installed PSN's and positive anchoring to facilitate disengagement of the rotor without unseating the I-PCP for flush-by operations. An inflatable packer anchoring device has been developed to simplify rigless installation of an I-PCP without the need of a seating nipple. The device relies only on hydraulic pressure while eliminating the need for axial loads during its setting sequence. The rod string deployed inflatable packer I-PCP anchoring device incorporates inflatable packer technology in conjunction with a hydraulically-actuated slip mechanism. It is equipped with seal cups and a shearable intake sub to obtain the required pressure competence to confirm tubing integrity and enable its setting sequence while maximizing flow-through capability after it is set. The system can be retrieved by applying overpull to shear its release pins allowing the inflatable packers to deflate and the mechanical slips to retract. The first installation of this system proved its optimal functionality by successfully setting an I-PCP in 3-1/2" production tubing in a vertical well in Oman's Sadad field. The I-PCP was deployed on rod string in conjunction with the inflatable packer anchoring device to setting depth. The system was set by applying pressure with a flush-by unit pump via the tubing-rod annulus, and the well was immediately placed into production. The objective of this paper is to provide a technical explanation of this innovative and unique technology, share the lessons learned from its first installation, and discuss its potential to improve the current capabilities of I-PCP technology while reducing operational cost and optimizing PCP/I-PCP completion design.