A facility blowdown in the oil and gas industry is a safety critical operation; required to ensure the safe shut-down of processing facilities during a plant emergency. In a full facility blowdown operation, the entire plant is isolated into a number of segments and then depressurized into the facility’s flare system. The outcome of a blowdown event is dependent on the performance of a number of safety critical control system and final elements in the plant; these are designed to ensure the safe and successful depressurization of the plant without any conspicuous incidents. Blowdown events are inherently fast transient processes, reliant on a large number of valve opening and closing operations with rapid reduction in pressure and temperature. It is critical to ensure that the process is depressurized quickly enough (cf. API 521) but whilst respecting constraints such as minimum design metal temperatures, accoustic and flow induced vibration limits in flare tailpipes and back-pressure constraints throughout the flare system. Blowdown incident investigations typically involve a critical review of the plant historian data and require dynamic simulation studies to adequately assess the event so as to determine whether the blowdown operation proceeded as planned, that no design constraints were violated and to glean any process safety lessons that can be learnt.
In this paper, with reference to a number of recent events on oil and gas facilities, we explain how to carry out a comprehensive blowdown investigation. We discuss a number of case studies from facilities in different parts of the world, including those that have shown operational deviations such as non-closure/partial closure emergecy shut down valves, delays in opening or non-opening of BDVs, and mal-functioning check valves. Some of these deviations caused flare capacity issues in the plant, minimum design metal temperature violation risks to process drums, unexpected pressurization of process drums, flow reversal into low pressure segments causing near miss events, and other violations of recommended practice. We explain how these studies have helped understand the current state of the plant’s safety systems and have been used by operating companies to identify design and operational changes critical for safe plant operation. Finally we discuss how these studies provided input to plant maintenance personnel in order to help prioritize maintenance activities and to make prudent maintenance investment.
Haghighi, M (The University of Adelaide) | O'Reilly, DI (Chevron Australia Pty Ltd, The University of Adelaide) | Hunt, AJ (Chevron Australia Pty Ltd) | Sze, ES (Chevron Australia Pty Ltd) | Hopcroft, BS (Chevron Australia Pty Ltd) | Goff, BH (Chevron Australia Pty Ltd)
This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.
Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.
The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.
The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
Dejia, Di (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering, China) | Wei, Pang (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering, China) | Jun, Mao (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering, China) | Shuang, Ai (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering, China) | Ying, He (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering, China)
Production logging play an important role on dynamic production monitoring and post-fracturing evaluation in shale gas horizontal wells, the technique can realize the rules of gas production and water flowback, in addition, understand the downhole dynamic production. However, the applications of production logging in shale gas play are not mature and still face many technical difficulties and challenges in China.
This paper proposed the technical roads and methods for production logging in shale gas well in Fuling oilfield based on the analysis of technical difficulties. At first, this paper discussed the optimization of downhole tools transmitted, the coiled tubing is more suitable than tractor for conveying the downhole tools, then analyzed how to determine the coiled tubing diameter, and provided coiled tubing mechanics simulation in a shale gas well. Secondly, we analyzed the selection of well control equipment, mainly focus on the optimization of pressure index of BOP. Thirdly, we analyzed the characteristics of array logging tools that produced by Schlumberger and Sondex, and illustrated the array tools have the potential risks that blocked and destroyed by debris of bridge plug, thereby the borehole cleaning is needed before testing. At last, we researched the calculation principle of flow rate with array tools and analyzed the data interpretation process according to the status of shale gas well and the principle of gas and water mix flow.
One case well in Fuling shale gas play shows that it is feasible to use coiled tubing conveyed array tools for production logging in shale gas well. The testing data interpretation results demonstrate the reliability of data interpretation method and the significance of production logging. For the case well, one half (6 stages out of 11 stages) fractures produce gas and the other half contribute nothing. The productive fractures also present different performance and the most predominant fracture contribute 36.47% of the total production. By production logging, not only fracture contribution to total production rate can be obtained, the flow regime and dynamic liquid level can also be determined. The production logging can be helpful for downhole fluid dynamic analysis and production optimization, and it may partly help the design of horizontal laterals and fractures scenarios.
With the widespread use of downhole pressure gauges (DHPG’s) to measure and record downhole pressures in oil and gas wells, engineers have been able to eliminate/reduce the wellbore effects that can mask true reservoir response. However, not every well is equipped with a downhole gauge; even fewer have the downhole gauge at the mid-completion depth, leaving fluids below the gauge that are subject to frictional pressure drop and changing fluid density/head due to heating/cooling. The reservoir signal (delta pressure vs time) can be slightly masked or completely overwhelmed by the change in pressure head due to changing fluid density as the well bore fluids cool or heat-up. The resultant measured rate of pressure change will therefore, not be representative of the actual reservoir response. In addition, frictional pressure loss as fluids travel up the well bore can appear as pressure loss due to completion skin. This causes wells to have an artifically high skin. Using raw pressure data that has not been accurately corrected for changing fluid head/density and frictional losses below the gauge can lead to inaccurate pressure-transient analysis (PTA) results (Hasan 1998).
This paper will discuss the physics of these processes and explain the reasons for these errors in the PTA results, along with the impact of these errors. Finally, a method for properly correcting the measured pressure to mid-completion pressure will be described. To demonstrate these effects, case studies conducted on two gas wells, a gas-condensate well and an oil well will be presented.
The Natuna Sea in Indonesia contains highly laminated and partly consolidated sandstone, with a combination of highand low-permeability zones, requiring different types of sand control completions (frac packs or high-rate water packs). Previous operators developing the same area have used multizone single-trip completion tools to optimize completion time while tailoring the pumping treatment to each interval’s specific properties. Tailoring the pumping treatment has historically required operators to us rigs with ample deck space or vessels temporarily outfitted with pumping equipment to keep the flexibility of completion types for each zone. In this specific case study, the operator had different constraints but was able to successfully complete the campaign and to overcome the challenges operating from onboard a relatively small jackup rig. The challenges were addressed using an optimized skid-based pumping spread and exclusive carrier fluid technology. In addition, pumping design optimization was done through minifrac analysis to evaluate formation mechanical properties and fluid efficiency to ensure the successful placement of the final treatment. From the completion persepctive, the wells for this campaign were highly deviated, increasing the risk of early screenout due to proppant settling and high tortuosity. Rigorous onsite fluid QA and QC during operations eliminated risks of premature sand settling due to fluid quality, and prefracturing diagnostic tests and use of a low-concentration slurry stage enabled recognition of high near-wellbore friction pressures and then overcoming them when necessary. A total of 24 pumping stages comprised of 16 frac packs and 8 high-rate water packs were successfully placed in eight wells. The treatments used a carrier fluid whose properties were easily adjustable on the fly, enabling appropriate treatments for each zone within the limitations posed by the available equipment and the constraint to optimize completion time. As a main result, production targets have been exceeded by 57% versus initial expectations.
Fuchao, Sun (Research Institute of Petroleum Exploration and Development, PetroChina) | Deli, Jia (Research Institute of Petroleum Exploration and Development, PetroChina) | Jiaqing, Yu (Research Institute of Petroleum Exploration and Development, PetroChina) | Xiaohan, Pei (Research Institute of Petroleum Exploration and Development, PetroChina) | He, Liu (Research Institute of Petroleum Exploration and Development, PetroChina) | Lichen, Zheng (Research Institute of Petroleum Exploration and Development, PetroChina) | Shujun, BAO (State Key Laboratory of Simulation and Regulation of Water Cycle in River Basin, China Institute of Water Resources and Hydropower Research)
The IOR is permanently issue for oil development. Zonal Water Injection Technology is a key technic about IOR. The zonal water injection technology faces several challenges for offshore oil field, such as numerous highly-deviated wells, complicated inter-layer contradiction, high cost, low operation efficiency, etc. High efficiency, low cost and low risk are crucial targets for offshore water-flooding. To achieve this target, CNPC developed a new offshore water injection technology featuring bridge concentric structure. It can realize multi-layer flow rate testing and adjusting efficiently and accurately with low cost and low risk. The system is composed of downhole bridge concentric regulator, downhole control instrument and surface control equipment. It can obtain multiple downhole critical parameters on line such as layer flow rate, tubing pressure, formation pressure and temperature. Also it can realize downhole flowrate dynamic adjustment automatically with no need to run and fish downhole valve. A steel cable with single core is employed for two-way data transmission. Concentric connection and adjustment between regulator and instrument is adopted to ensure successful connection for offshore deviated wells. The eccentric valve is designed as a innovation point with low leakage and low regulation torque. High-precision electromagnetic flow meter is employed to obtain layer flow rate directly to ensure test accuracy in deviated wells. Until recently, this technology has been applied in eleven wells including five in jidong offshore highly-deviated wells with maximum deviation 55 degree, maximum pressure 50MPa and maximum temperature 120 degree. The application successfully achieved the parameters of flow rate, tubing pressure, formation pressure and temperature. Besides it realized flow rate adjusting automatically. The whole process of water allocation and packer seal test were finished on line and the efficiency was significantly improved.
Wei, Chenji (Research Institute of Petroleum Exploration & Development, PetroChina) | Li, Yong (Research Institute of Petroleum Exploration & Development, PetroChina) | Song, Benbiao (Research Institute of Petroleum Exploration & Development, PetroChina) | Tian, Changbing (Research Institute of Petroleum Exploration & Development, PetroChina) | Li, Baozhu (Research Institute of Petroleum Exploration & Development, PetroChina) | Zhou, Jiasheng (Research Institute of Petroleum Exploration & Development, PetroChina) | Zheng, Jie (Research Institute of Petroleum Exploration & Development, PetroChina) | Luo, Hong (Research Institute of Petroleum Exploration & Development, PetroChina) | Lan, Jun (Research Institute of Petroleum Exploration & Development, PetroChina)
Accurately understanding the geological and dynamic characteristics determines the recovery and life cycle of a reservoir. Several uncertainties and risks exist during the development especially for giant multi-layered sandstone reservoirs. Pilot is one of the most effective steps to manage risks and reduce uncertainty, which help better understand the reservoir, expose the conflict during development, propose corresponding surveillance plan, determine development plan, and eventually improve the reservoir performance.
This study focuses on a giant Cretaceous multi-layered sandstone reservoir in the Middle East, which started to produce since 1960s without any energy supply, and the current reservoir pressure is approaching the bubble point pressure. Therefore, water flooding is urgently needed. In order to reduce uncertainty and risks, criteria and workflow of selecting waterflood pilot is proposed by integrating the geology, dynamic data, well status, and existing facilities etc.. 4 pilots are selected and each pilot represents a typical reservoir type to better understand the performance and adaptability of different development plan. Each pilot has its own specific objectives and detailed operation plan. Finally, surveillance plans are proposed based on geological understanding, dynamic behavior, and simulation results.
According to the proposed criteria and workflow, pilots are selected to represent good, medium, and poor reservoir quality respectively. Pilot I is selected as an example to be discussed in detail. The reasons to select this pilot, well pattern and spacing, and perforation strategy discussion are presented. Finally, surveillance is divided into different groups, and implementation plan of different types of surveillance is determined.
This study offers a comprehensive case study that supports the engineers and geologists for better understanding the reservoir and optimizing waterflooding plan for this reservoir. Moreover, it offers an integrated methodology of pilot selection and surveillance proposal for other similar oilfields.
Song, Zhaojie (China University of Petroleum) | Hou, Jirui (China University of Petroleum) | Liu, Zhongchun (Sinopec Petroleum Exploration and Production Research Institute & Sinopec Key Laboratory of Marine Oil & Gas Reservoir Production) | Zhao, Fenglan (China University of Petroleum) | Huang, Shijun (China University of Petroleum) | Wang, Yong (China University of Petroleum) | Wu, Jieheng (China University of Petroleum) | Bai, Baojun (Missouri University of Science and Technology)
Tahe Naturally Fractured Carbonate Reservoir has implemented nitrogen gas flooding since 2013, with daily oil production of 7580 bbls and oil recovery increment of 0.83% by the end of 2015. However, the presence of fractures significantly affects gas swept volume and production performance, so large amount of oil reserves is poorly flooded due to gas channeling through fractures. The fluid flow mechanisms in fractured models were discussed in order to improve field gas flooding efficiency. Based on the geological constrains of Tahe Oilfield, fractured models with different apertures were fabricated using acrylic glass to model carbonate matrix wettability and for a better observation on fluid flow behavior. The models were placed vertically and horizontally to simulate the high-angle and low-angle fractures in the formation. Gas displacing oil experiments were performed at different injection velocities. The oil displacement characteristics were depicted and the production performance was recorded and discussed. Experimental data were history matched through numerical simulation, and thus a sensitivity study was conducted via design of experiments. For downward gas injection in the high-angle fractured model with a given aperture, a critical injection velocity was obtained below which piston-like displacement was observed. Channeling factor was defined to characterize the injected gas channeling features. It gradually increased and reached its maximum value with increasing injection velocities. The relationship between channeling factor and injection velocity was well fitted by Langmuir equation, and the mechanism behind it was elucidated. Based on their relationship, three gas/oil flow regions were illustrated including non-channeling, transitional channeling, and stable channeling. For all fractured models, the critical injection velocity increased and the maximum channeling factor declined with the increase of fracture aperture. A standard curve was plotted, which enables us to determine different flow regions according to the fracture aperture and injection velocity.
For oil displacement in the low-angle fractured models, the top part was flooded at a specific range of injection velocity. Gravity effect was weakened and the middle part was flooded at relatively high injection velocities.
Numerical fractured models were built and thus calibrated by history matching all the experimental data at different fracture apertures and injection velocities. A sensitivity study was conducted and the weighting of different variables was emphasized via DOE. Previous studies were mostly focused on gas flooding efficiency in naturally fractured carbonate reservoirs; however, this study visually depicted the gas-oil flow behavior through lab experiments, and demonstrated the weighting of different variables via numerical simulation using DOE. This paper could provide an insight into field gas injection projects and the development of the commercial numerical simulator that is specialized for naturally fractured carbonate reservoirs.
Wijaya, R. (Total E&P) | Muryanto, B. (Total E&P) | Wahyudhi, F. (Total E&P) | Isdianto-Maharanoe, M. (Total E&P) | Styward, B. (Total E&P) | Kadrie, M. (Total E&P) | Al-Sakaf, N. (Total E&P) | Dahnil-Maulana, M. (Total E&P) | Saputra, R. (Total E&P) | Az-Zariat, A. (Total E&P) | Armelia-Suska, R. (Total E&P) | Anggiriani-Putri, A. (Total E&P) | Eko-Jatmiko, C. (Total E&P)
Tunu is a giant gas field located in Delta Mahakam, East Kalimantan, Indonesia operated by Total E&P Indonesie. The field development targets two domains: Tunu Shallow Zone (TSZ) and Tunu Main Zone (TMZ). The primary objective of TSZ completion is to have a cost effective sand control methodology to ensure economic vialibility of the wells since TSZ consist of small elliptical shaped deltaic sand bodies containing low reserve gas pockets with a typically short production life.
Multi zone single trip gravel pack (MZ-STGP) systems have been utilized as sand control completion methodology. Technical limitations of these techniques in terms of zone spacing, number of zones and well deviations drove the need developping an alternative completion technique. Using short screen assembly and open-hole isolation technology, a unique multi zone open hole stand alone screen (MZ- SAS) system was developed.
The initial development consists of 14 wells. Both low and high angle deviated wells, numbers of different completion jewelries and different type of reservoir drill-in fluids (RDIF) have been used over the initial phase of the development. The objective of this paper is to review the evolution and improvements in the drilling, fluid, completion and specific post well completion strategy. This has provided a best practice for future completions in the development of similar reservoirs in the portfolio.
He, Liu (Research Institute of Petroleum Exploration and Development) | Shujun, BAO (State Key Laboratory of Simulation and Regulation of Water Cycle in River Basin, China Institute of Water Resources and Hydropower Research) | Zixiu, Yao (Research Institute of Petroleum Exploration and Development) | Fuchao, Sun (Research Institute of Petroleum Exploration and Development) | Jiaqing, Yu (Research Institute of Petroleum Exploration and Development) | Deli, Jia (Research Institute of Petroleum Exploration and Development) | Yang, Gao (Research Institute of Petroleum Exploration and Development)
As the exploration degree and strength are continuously increased, both average water cut and natural decline rate have the tendency for increase. Hence various problems and contradictions are exposed, it's increasingly difficult to offset the influence of production decline and water cut increase on petroleum production, which severely impacts reservoir development efficiency and economic benefit. Prominent contradictions are as follows. 1) After an oilfield enters into a high water cut stage, the conflict between injection and production is very serious, such as unequal water-flooding producing reserves, high injection pressure of some water-injecting wells, low productivity of partial oil wells because of blocking created by mechanical impurities, and poor layering water-injection technique. 2) Affected by reservoir heterogeneity and water injection, Injection profile is non-uniform in longitudinal direction, water-flooding hierarchy and degree of reserve recovery of high permeability layer is relatively high as a result. The water flooding development effect of high water cut oil field is in urgent need of improvement. 3) Influenced by reservoir's poor connectivity and injection water quality, the injection pressure is high for some injection wells, resulting to a decline of injected water volume, which couldn't meet the demand of injection allocation. To solve the above problems, it is necessary to build an integrated management system for injection, which could both cover the underground and above-ground. In the meantime, technical efficiencies should also be improved. Injection-production network is further perfected, which aids to solve the problem of lack of water injection well spots and unbalance of injection and production; Based on hydrodynamic principle, kinds of injection allocation regimes are implemented; Injection of under-injected wells is enhanced, which increases the water-drive swept volume; Tests of layering distributional injection and profile control are also conducted using various methods; Finally, quality analysis & investigation and compatibility research of injected water are completed, reasonable treatment is done according to the compatibility, which improve the quality of injected water.