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Results
Cable Deployed ESP System Applied with Conventional ESP Assembly: A New Generation of Rigless ESP Technology
Zhao, Mengpan (Chengdu Vertechs NOVA Technology Co., Ltd) | Zhang, Qiang (Chengdu Vertechs NOVA Technology Co., Ltd) | Wei, Ping (Best Win Energy Service Co., Ltd) | Hong, Yuandong (Chengdu Vertechs NOVA Technology Co., Ltd) | Li, Qijun (Chengdu Vertechs NOVA Technology Co., Ltd) | Zhu, Lisha (Chengdu Vertechs NOVA Technology Co., Ltd)
Abstract A new generation of Rigless ESP technology, Cable Deployed ESP (CDESP) System uses specialized cable to replace ESP, which saves rig cost and reduces production deferment tremendously. However, most CDESP in the market are applied with inverted ESP assembly, which has high requirements and more uncertainties on customized ESP. This paper will introduce the design philosophy of a CDESP applied with conventional ESP assembly, which is more compatible. Rounds of multiple factory tests were successful, pressure test of hanger assembly and penetrator system were up to 7,500 psi,cable connector tension tests meet the specialized cable and ESP weight requirement. Also, the electrical tests were qualified. The factory tests and field applications verified the reliability and robustness of this new generation of Rigless ESP technology.
First Experience Matter: The Valuable and Great Learnings from Unfavorable Mud Acid Stimulation in S Field Gravel Pack Wells, East Malaysia
Bakar, Hasmizah (Petronas) | Ravichandran, Narindran (Hibiscus Petroleum) | Hassan, Hamidah (Petronas) | Abu Bakar, Mohamad (Petronas) | Idris, Khairul Nizam (Petronas) | Masoudi, Rahim (Petronas)
Abstract Most of the S oil field producers experienced rapid decline in production and this is suspected due to fine sediment particle migration and plugging. The S field team had carried out external formation damage study as they have no expertise and field experience to determine the damage mechanism and evaluate the best acid treatment recipe for their formation damage. Recently, mixtures of traditional hydrochloric and hydrofluoric acids have been used for the removal of near-wellbore damage in S field sandstone formations. The stimulation campaign in this field which has turbidite reservoir, high clay content predominantly by kaolinite and illite with high siderite mineralogy applied both bullheading and coiled tubing squeezing techniques. The treating fluid selection is highly dependent on mineralogical data and laboratory works. Based on the core flood testing performed, high strength mud acid is chosen as the main treatment fluid and gave superior result in permeability recovery as compared to milder organic acid and HF. Unfortunately, the actual field stimulation turned out to be opposite from the core flood testing outcomes. The situation is worsened in multistage treatments, which traditionally involve many repeat stages of preflush, main treatment, overflush and diverter. The mud acid stimulation prompted more water production and fine migration that is ended up with production curtailment. Only one out of four of the treated candidates resulted significant gain after gas lift valve change took place. This paper also will outline the reviews on results of laboratory testing and field actual performance together with the recommendations for future improvement. Stringent candidate selection, improved treatment fluids cocktail, operational challenges such as unanticipated longer flow back period, post treatment unwanted precipitation, ineffective diverter placement and skin build up post treatment are among of the learning points captured in this paper. From this unfavorable mud acid stimulation campaign which cost USD4million value leakage, our team comes out with best practices for future stimulation and key learning to share with industry colleagues who has no field background to combat with fine migration issue in their sandstone asset. Laboratory works is not the only paramount to any stimulation, success in stimulation is a journey, not a destination. The doing is often more important than the outcome.
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.91)
Novel Candidate Screening and Successful Implementation of Stimulation in Screen Completed Wells to Double Production in Brown Fields – A Case Study from Offshore Malaysia
Anand, Saurabh (PETRONAS Carigali Sdn Bhd) | Mat Khair, Nusheena (PETRONAS Carigali Sdn Bhd) | Azhar B. Abu Bakar, Khairul (PETRONAS Carigali Sdn Bhd) | Madon, Bahrom (PETRONAS Carigali Sdn Bhd) | Kin Chun, Kok (PETRONAS Carigali Sdn Bhd) | M. Adib, M. Syamil (PETRONAS Carigali Sdn Bhd) | Rahim, M. Ikhlas (PETRONAS Carigali Sdn Bhd)
Abstract Majority of wells completed offshore Malaysia have downhole screens installed for sand and fines control. It is however observed that the PI of most of these wells drop multifold times within first few years of production. This paper illustrates the workflow with novel technique of screening such wells for stimulation to restore well production. This paper will also illustrate a few examples of actual implementation of the stimulation jobs and the excellent results from these jobs. Hundreds of strings operated by PETRONAS in Malaysia Offshore across various fields have some form of downhole screen (standalone or as part of the gravel pack) installed to control sand and fines. Although these completions remain effective initially, but water break through results in significant PI decrease. It has been established that the predominant cause of this decline is the screen or gravel pack plugging by the fines mobilized by water which is followed in many cases by deposition of inorganic or organic scales. A workflow was developed using data from existing digital production monitoring system to identify wells showing the plugging behaviour. The workflow used several factors such as liquid rate decline, GOR, water cut, reservoir pressure, artificial lift performance etc to shortlist a list of wells on which a detailed nodal analysis was applied to estimate gains assuming 70% skin reduction. The wells which passed the workflow and showed maximum benefit from stimulation were then grouped together such that a campaign-based execution could be done to optimize cost. Detailed customized stimulation recipe for each well was prepared and optimized well level operation program was prepared. Optimization such as using bullheading technique instead of using coil tubing in some cases was done. Stimulation treatment in 4 of the wells has been pumped successfully with excellent results and an estimated 1,000 bopd total gains. The post job oil rate is double the initial rate in many cases and even 200% more in some of the cases. Post job nodal analysis suggests up to 90% damage skin removal in these wells. Optimized operation program and campaign-based execution coupled with other cost saving measures implied that the payback time was less than 1 month. PDG data from one of the wells was used extensively to evaluate pre & post stimulation well behavior. The high damage skin in the screen completed wells is one of the most pertinent issues which leads to significant production loss in wells offshore Malaysia. This paper details a quick and robust method to identify such wells for stimulation. The results from these stimulation jobs on candidate wells are very encouraging particularly considering the economics of the jobs. Following the success of the initial jobs, many more candidate wells have been lined up for execution in near future.
- Asia > Malaysia (1.00)
- North America > United States > Texas > Terry County (0.40)
- North America > United States > Texas > Gaines County (0.40)
- Europe > United Kingdom > North Sea > Southern North Sea (0.40)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.48)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 186 > Field A Field > Silurian Tanezzuft Formation (0.97)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation (0.97)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field B Field > Silurian Tanezzuft Formation > B27 Well (0.93)
Assessing the Impacts of Groundwater Intrusion to Production Efficiency and Proposing Solutions to Enhance Oil Recovery from Fractured Basement Reservoir in SuTuDen Field, Offshore Vietnam
Tran, Xuan Van (HoChiMinh City University of Technology, VNU-HCM) | Nguyen, Tuan Van (Cuu Long JOC) | Nguyen, Tuan (HoChiMinh City University of Technology, VNU-HCM) | Nguyen, Kha Xuan (HoChiMinh City University of Technology, VNU-HCM) | Thai, Ngoc Ba (HoChiMinh City University of Technology, VNU-HCM) | Truong, Thanh Quoc (HoChiMinh City University of Technology, VNU-HCM)
Abstract Based on the observed phenomenon of formation water intrusion in SuTuDen oilfield, i.e., high reservoir pressure, high constituent percentage of formation water in produced water, stable isotopes tracing, as well as strong-water drive mechanism confirmed by matching & calibrating the production parameters, the authors assessed the impacts of water drive to the production and proposed methods to enhance recovery. The results of water analysis with low TDS (12g/l) indicate the formation water accounts for a significant ratio of the produced water. Among factors affecting production efficiency, the critical ones are fault-fracture characteristics, origins of water, range of hydrodynamic relationship, design plans and well completion. In order to mitigate the negative impacts and increase the positive impacts of these factors, a series of intervention solutions must be considered including combined ESP-Gaslift installation, gas assisted gravity drainage, water or gas injection in selective zones, infill drilling in poorly connected areas. The basement reservoir SuTuDen oilfield is affected by natural water aquifer hence it is necessary to implement recovery solutions such as adjusting the design, maintaining the reservoir pressure, in-fill drilling, artificial lift, stimulating the near-wellbore zone, optimizing the production-injecting regime. When the wells have already been invaded by water, it is very difficult and costly to maintain the cumulative production. Therefore, the mitigation measures should be applied early from the design stage, especially the compatible operating regime, help reducing the water invasion and achieving optimal production. The result of the methods should allow an increase in the overall recovery factor from 36.1% to 39.8%, equivalent to 18.52 MMbbl.
- Asia > Vietnam > South China Sea > Cuu Long Basin > Block 9-2 (0.99)
- Asia > Vietnam > South China Sea > Cuu Long Basin > Block 15-1 > Su Tu Den Field (0.99)
An Efficient Gas-Lift MPD Based On Dual-Channel Drillpipe
Kang, Bo (China University of Petroleum Beijing and Sinopec ShengLi Drilling Research Institute) | Fan, Honghai (China University of Petroleum Beijing) | Liu, Jinge (Sinopec Research Institute of Petroleum Engineering) | Wen, Zixiang (China University of Petroleum Beijing) | Deng, Song (Changzhou University) | Wang, Shujiang (Sinopec ShengLi Drilling Research Institute) | Chen, Yongming (Sinopec ShengLi Drilling Research Institute) | Zhou, Yanjun (Sinopec ShengLi Drilling Research Institute) | Feng, Guangtong (Sinopec ShengLi Drilling Research Institute) | Li, Zongqing (Sinopec ShengLi Drilling Research Institute) | Yan, Xiuliang (Sinopec ShengLi Drilling Research Institute)
Abstract When drilling in the open hole with negative density window, which occurs leakage in the upper section and collapse in the lower section, it will lead to many problems using the conventional method to seal the formation with technical casing, such as high cost,complex casing structure and small completion size. It is difficult to meet the needs of low cost and high efficiency development in the deep wells. This paper presents a new Gas-Lift MPD drilling method based on Dual-Channel compound Drillpipe (DCP), which can solve the above problems. The DCP is composed of the 139.7mm DCP, the gas lift joint and the conventional 139.7mm drill pipe. It has two circulating channels. Channel 1 is for drilling fluid circulation and channel 2 is directly connected with the upper borehole annulus. The advantage of this method is that it can change the upper wellbore annulus into gas-liquid two-phase flow by injecting gas the channel 2 when the drilling fluid is circulating in the channel 1. It can develop different annulus ECD gradient (small to large) profile and complete complex pressure formation drilling operation in the same open hole section. According to the design of SBX-5H well, the article uses OLGA to carry out dynamic simulation and analysis of the construction plan of the Gas-lift MPD based on Dual-Channel Drillpipe. The simulation results show that it has great advantages in reducing the number of casing layers, shortening the drilling cycle and enlarging the completion size. Firstly, the control requirements of the ECD profileare is satisfied, which is that the ECD<1.28g/cm in the upper section and ECD>1.32g/cm in the bottom of the open hole (collapse ECD=1.31g/ cm, leakage ECD=1.29cm) by simulating and adjusting drilling pump flow, injected gas flow rate, Dual-Channel Dirllpipe length and drilling fluid density. Secondly, the complicated drilling problem is expected to be solved,such as repeated leakage in the long open hole section. The number of casing layers can be further reduced from 4 to 3 and the drilling cycle is expected to be reduced by more than 20%. Finally, the completion well bore size will be expanded from 149.2mm to 165.1mm (enlarged 11%), which can better meet the requirements of the next production and reservoir transformation. Through the simulation analysis, it is proved that the Gas-lift MPD technology based on Dual-Channel Drillpipe can effectively solve the problem of negative density window in deep well drilling operation. It not only reduces the drilling difficulties and the drilling cycle, but also is economical and efficient. Therefore, it has a good market prospect.
- Phanerozoic > Paleozoic > Permian (0.49)
- Phanerozoic > Paleozoic > Silurian (0.47)
- Geology > Rock Type > Igneous Rock (0.69)
- Geology > Rock Type > Sedimentary Rock (0.47)
The Platform to Optimise the Stranded Well Potential
Bakar, Hasmizah (PETRONAS Carigali Sdn Bhd) | Watchawong, Dangchin (PETRONAS Carigali Sdn Bhd) | Sahar, Raja Nor (PETRONAS Carigali Sdn Bhd) | Saleh, Malaz (PETRONAS Carigali Sdn Bhd) | Muhaimin, Wan Firda (PETRONAS Carigali Sdn Bhd) | Jeffrey, Suzanna Juyanty (PETRONAS Carigali Sdn Bhd) | Yahia, Zaidil (PETRONAS Carigali Sdn Bhd)
Abstract During the low oil price period, PETRONAS Carigali Sdn Bhd (PCSB) embarked on an intensified approach to prioritize the production enhancement and idle well reactivation (PE/IWR) activities in its Malaysia operations. To monetize the remaining reserves from these 2,000 active and idle strings, comprehensive opportunity management system which covers opportunity identification, evaluation and prioritization, planning, execution and tracking the activities are implemented. The identified opportunities from the active and idle wells inventory and integrated field review are initially assessed at a high level based on three criteria, value (the estimated Unit Enhancement Cost, UEC), probability of success and doability which indicates how quickly it will be restored. After the due diligence work completed, the opportunities will progress to the multi-disciplinary technical commercial value assurance committee for approval then followed by planning and scoping the detailed execution. All prioritized, approved and planned opportunities are then turned into execution pipeline and properly tracked into a systematic methodology for post job analysis, evaluating the success of the jobs and recording the lessons learnt for improved future jobs is also addressed in this article. This article also outlines the examples of comprehensive and successful approach of idle string reactivation activities which gone through this opportunity management system via fishing operation, scale removal treatment, gas lift optimization, behind casing opportunities, acid matrix stimulation and surface facilities rejuvenation. This approach has significantly improved the percentage of active wells in entire domestic operation from 50 to 53%.
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 186 > Field A Field > Silurian Tanezzuft Formation (0.99)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation (0.99)
Application of Velocity String to Improve Productivity from Bottom pays after Hydraulic Fracturing in Multilayered Low Permeability Reservoir
Anand, Saurabh (Cairn Oil & Gas) | Johri, Nitin (Cairn Oil & Gas) | Chandak, Krishana (Cairn Oil & Gas) | Vijay, Rachit (Cairn Oil & Gas) | Tiwari, Shobhit (Cairn Oil & Gas) | Bohra, Avinash (Cairn Oil & Gas) | Vijayvargiya, Utkarsh (Cairn Oil & Gas) | Khemchandani, Jivesh (Cairn Oil & Gas) | Singh, Ishaan (Schlumberger) | Agarwal, Arpit (Schlumberger)
Abstract Raageshwari gas field is located in RJ-ON 90/1 Block in western India with Cairn Oil & Gas, a vertical of Vedanta Limited as operator of the field. Multistage hydraulic fracturing is required to achieve commercial production from the highly laminated retrograde gas condensate reservoir. It has been observed in almost all wells that the top high PI zones produce a majority of the gas. The wells have a water column across bottom few fracs which prohibits production from these zones. Water unloading through increased drawdown was not successful because of higher PI of the upper fracs. Coiled tubing-based nitrogen lift of the water column is not commercially feasible. It is important to find a low-cost solution for water unloading since bottom zones account for approximately 30% of total gas in place. A solution has been developed using a customized velocity string design, which can unload the water while maintaining high well production. Conventional velocity strings are only installed in late life of gas wells when liquid loading is observed. These conventional designs limit the maximum rate to 2-3 MMSCFD and therefore cannot be used in Raageshwari gas field for water unloading as high individual well rates (8 to 12 MMSCFD) is required to meet field plateau production. After reviewing various options, an innovative and unique velocity string system design was developed which incorporates a customized surface spool and string hanging system. This customized design allows combined or independent gas flow conduits as described below: Through the annulus of velocity string and tubing when higher gas rates are required. Through the velocity string to facilitate liquid unloading due to high gas velocity. Production from both the conduits to meet higher demands than the annulus flow alone. Well integrity was assured by maintaining two independent barriers during commissioning, production phase and also during future string retrieval. This paper will discuss in detail the design considerations of the velocity string and surface hanger system to achieve liquid unloading while maintaining high rate gas production. It will also have details on the dual barrier selection process and the design customization that have been done to ensure cyclic liquid unloading and high rate gas production. This innovative velocity string design is technically a dual completion with a much lower cost and footprint. The same design can be implemented across a wide variety of applications to address well integrity issues, selective zonal production etc. The application of this design in Raageshwari field will ensure planned recovery of gas from the field and will also support plateau production phase. This design can be an efficient and economic technique to develop similar fields.
- Asia > India > Rajasthan (0.74)
- North America > United States > Colorado > Mesa County (0.24)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Raageshwari Deep Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Raageshwari Deep Field (0.99)
Abstract In 2002, during front-end planning for a project in China, the operator Anadarko understood that the electrical submersible pumping (ESP) system run life would be one of the critical factors for the project's success. Therefore, consideration of the complete ESP lifecycle was taken into account. This included design, equipment specification, contracting strategy, installation practices, commissioning procedures, operating practices including optimization and troubleshooting, as well as ESP teardown and inspection. The challenge was to provide ESP systems that could: Cover initial low productivity index (PI) / low fluid rates Cover final high PI / high fluid rates Produce heavy oil Meet all the above conditions while keeping the ESPs within their operating envelopes This drove the concept developed for the ESP design. The principle is still being used more than six years since its first production. The final design included the following features: Encapsulated ESPs to assist with motor cooling at lower fluid rates and heavy oil production Pumps with abrasion-resistant technology selected to cover the required large range of flow rates Geothermal-specification motors to allow operation at higher temperatures Comms-on-power down-hole sensors for continuous monitoring and optimization Since coming on line, ESPs have been installed and operated very successfully in the CFD group of fields and have been exceeding all run life expectations. Of the 110 ESPs operating, the average run life since the start of production is 3.5 years, with 30 (28%) running more than four years and the longest ESP run life so far at 6.1 years.
Copyright 2010, IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition This paper was prepared for presentation at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition held in Ho Chi Minh City, Vietnam, 1-3 November 2010. This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited.
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- (4 more...)
Abstract The Handil field is a giant mature oil field in Indonesia. It has been producing since 1975 with current recovery factor for oil is 49% and gas is 57%. Cumulatively, oil had been produced around 855 MMstb and gas around 1.68 Tcf. Now, from this field, oil is being produced at 20,000 bopd, gas at 75 mmscfd and water at 130,000 bwpd. One of the feasible and economic ways to recover the remaining oil at this late stage of field production is by doing a Light Workover technique. This technique aims to change the well status without pulling out the existing completion. This technique is considered the optimum way to maintain the field production performance up to now. One of Light Workover technique is to do re-completion by inserting smaller completion inside existing completion. An innovative spool adapter was utilized to be able to run smaller completion and sit above existing wellhead. Hence, from three (3) depleted gas wells that were converted into oil wells, all wells are still producing and economically had been paid out the intervention cost. This technique is considered applicable for a mature oil field where some gas wells had been depleted and oil layers are exist.