Khare, Sameer (Cairn Oil & Gas vertical of Vedanta Limited) | Baid, Rahul (Cairn Oil & Gas vertical of Vedanta Limited) | Prusty, Jyotsna (Cairn Oil & Gas vertical of Vedanta Limited) | Agrawal, Nitesh (Cairn Oil & Gas vertical of Vedanta Limited) | Gupta, Abhishek Kumar (Cairn Oil & Gas vertical of Vedanta Limited)
The objective of the paper is to present the methodology adopted for dual artificial system modeling in Aishwariya field– an onshore oil field located in prolific Barmer Basin, India. This paper presents a conceptual and feasibility study of combination of Jet pump (JP) and Electrical Submersible Pump (ESP) together as means of artificial lift for production enhancement in a well. It discusses the workflow to model a well producing on dual artificial lift (ESP producing in combination with Jet-Pump) via industry standard software and demonstrates the same with a successful case study.
Requirement of ESP change outs to restore/enhance well production in cases such as undersized pumps, pump head degradation requires an expensive work-over. However, an option for secondary additional lift (JP) installation along with primary lift (ESP) in completion system can eliminate the costly wok-over requirement if both lifts can operate simultaneously.
The procedure to model the dual artificial lift (JP and ESP) has two major components: a) Psuedo IPR at ESP discharge node and b) Standard JP modeling using pseudo IPR. Pseudo IPR is generated by modifying well specific IPR using ESP pump curve for a specific frequency. The down-hole ESP pump intake & discharge pressure sensors help calibrate the model accurately for further prediction.
The existing completion in the Aishwariya field is ESP completion with the option of JP installation in cases of ESP failures as contingency. Moreover, jet pump can be installed using slick line with minimum well downtime (∼ 6 hrs). Therefore, installing and operating the Jet pump above a running ESP will not only increase the drawdown but will result in production enhancement with minimal cost.
Kommaraju, Srinivas Rao (Kuwait Oil Company) | Garcia, Jose Gregorio (Kuwait Oil Company) | Al-Bahri, Abrar Marwan (Kuwait Oil Company) | Al-Faudari, Mohammad J M E J (Kuwait Oil Company) | Al-Naqi, Ahmad Mohamad Hasan (Kuwait Oil Company)
The drilling of shallow horizontal wells in unconsolidated sand formations faces the particular challenge of achieving proper well trajectory, needed that minimizes dog leg severity and if not accomplished can increase well intervention frequency. These well complexity challenges may result in improper wellbore sand clean outs that can promote early failure of the artificial lift equipment and increase the frequency of interventions that cause production deferment. Wellbore clean out operations are risky because of potential fluid losses and low reservoir fracture pressures, which limit downhole clean-out circulating pressures.
Concentric Coiled Tubing (CCT) technology has been used to clean out horizontal slotted liner sections with suspected sand fill. This sand fill reduces well productivity due to sand bridging within the slotted liner. The application of CCT technology reduces the risk of lost or limited fluid returns and provides an effective clean out method. In addition, it can also provide drawdown at the CCT power head, resulting in lost workover fluids from the wellbore effectively removed by using the system under vacuum-mode. The multiple operating system modes provide the benefit of cleaning and treating the wellbore in the same run.
Workover interventions using conventional CT have been used in the past with limited success. Moreover, in some cases, these wells have showed sharp production declines after post CT clean-out operations. It was suspected that in addition to sand fill issues, formation damage has occurred in these wells due to the fluids used during those interventions. The application of CCT has resulted in the removal of sand and lost clean-out fluids previously used.
This paper reviews the wells, which have had conventional cleanout methods done that were unsuccessful and provides the results of using CCT technology to restore well production thus reducing well interventions by 50% and OPEX savings up to 15%.
Wells in the South Ratqa field often fill with sand. Ultra low bottom-hole pressure did not allow efficient sand cleanouts in several wells. Despite using massive amounts of nitrogen during clean out, and largest available CT size (2.375") to ensure enough annular velocity; severe fluid losses occurred into the formation, which resulted in decreased well production post clean outs, moreover handling energized returns has always been a logistic and safety hazard Recently, concentric coiled tubing (CCT) technology was employed for the first time in Kuwait and five wells were identified as viable fill cleanout candidates for which traditional cleanout methods had proved inefficient at best and many times unsuccessful. The system uses concentric coiled tubing and a special vacuum tool designed to apply a localized drawdown, which would deliver the sand particles through the Coiled Tubing / Coiled tubing annulus to surface. Returns were handled using H2S resistant lines into a desander. A carefully engineered cleanout program enabled removal of more than 12 MT of sand from four vertical wells, and also identified the formation damage in a horizontal wellbore. The identification of wellbore damage revealed the best intervention to cure the damage and eliminated speculative remedies that sometimes increased the damage done to reservoir. Additionally, the layout of well plots was designed in a very congested way to maximize output but made it impractical to have return pits, requiring mobile tanks to handle returns, while the energized nature of returns in conventional nitrogen jobs are dangerous to handle in a closed tank environment. CCT eliminated that hazard as the returns are not energized.
Mittal, Saumya (Cairn Oil & Gas, Vedanta Ltd) | Anand, Saurabh (Cairn Oil & Gas, Vedanta Ltd) | Venkat, Panneer Selvam (Cairn Oil & Gas, Vedanta Ltd) | Mathur, Vinay (Cairn Oil & Gas, Vedanta Ltd) | Zagitov, Robert (Cairn Oil & Gas, Vedanta Ltd) | Subramanian, Jaisankar (Cairn Oil & Gas, Vedanta Ltd) | Patel, Nilay (Scaled Solutions LLC) | Hammonds, Paul (Scaled Solutions LLC)
Cairn Oil & Gas, Vedanta Limited has implemented full field Polymer Flooding in Mangala Field and is currently injecting nearly 400,000 bpd of polymerized injection water with average polymer concentration of ~2500 ppm. Partially hydrolysed polyacrylamide (HPAM) Polymer is mixed with source water to create a mother solution of 15,000 ppm concentration at Central Polymer Facility (CPF) and is distributed through a pipeline network to 15 well pads where it is diluted to achieve a viscosity of ~30 cP for injection.
Artificial lift in Mangala is either by Jet Pump or Electrical Submersible Pump (ESP). In producers, a wide range of polymer concentrations are observed in the produced brine. Maximum polymer concentration measured is ~972 ppm and average polymer concentration is ~280 ppm.
Recently, during well intervention activities, it is frequently observed that polymer like waxy deposits are obstructing the free movement of wire-line tools. During jet-pump redressing, polymer deposition was observed in the Body X-over (Reservoir liquid path), check valve assembly, throat and spacer nozzle to throat inside jet-pump. In addition, an agglomerated polymer substance was also observed in the slick line tool string. A general observation is that after a jet pump change, production rate increases sharply followed by rapid decline. This requires Jet Pump Change Out (JPCO) job at regular intervals (every 20 days in few wells). Furthermore, semi soft to hard polymer deposits have been observed in surface facilities i.e. injection water booster pumps, injection water filters and heat exchangers.
Laboratory analysis of the samples collected indicated that the deposit consists of Hydrocarbon, Inorganic Scales and polymer agglomeration. Based on further studies it is observed that the degree of hydrolysis of the polymer deposit significantly increases between 50-80% in Jet pump deposits and up to 90% in heat exchanger samples. Increasing degree of hydrolysis reduces the polymer cloud point below reservoir temperature and heat exchange skin temperature.
Solution to the problem can be identified by controlling the degree of hydrolysis in fresh polymer below 25 mol% and cloud point greater than 120°C, addition of scale inhibitor to the system upstream of scale formation, removal of deposit with a combination of oxidizer and chelant; other options continue to be studied.
Nagar, Ankesh (Cairn Oil and Gas, Vedanta Limited) | Dangwal, Gaurav (Cairn Oil and Gas, Vedanta Limited) | Pandey, Nimish (Cairn Oil and Gas, Vedanta Limited) | Jain, Akanksha (Cairn Oil and Gas, Vedanta Limited) | Parasher, Arunabh (Cairn Oil and Gas, Vedanta Limited) | Deshpande, Mayur (Halliburton) | Gupta, Vaibhav (Halliburton) | Pande, Karan (Halliburton)
Increasing water cut in oil-producing zones is a common issue faced by operators, particularly for mature fields. Currently, where most of the decisions are governed by economics, incurring additional expenses with activities such as handling produced water becomes extremely undesirable. Depending upon the nature of the zone, one effective solution to this issue is chemical isolation. This paper undertakes this issue, discussing a case study of a successful zonal isolation operation using an organically crosslinked polymer sealant in a fractured zone with a gravel pack and screen completion for a reservoir with a subhydrostatic nature.
This zone was an initial oil producer in FM-01 sand of the Mangala onshore oil field and had been stimulated in 2011 with a fracture-pack completion. The zone was completed with screens and a gravel pack with 16/30-mesh sand and 5.5-in. screens across the producing interval. During a period of time, the zone (FM-01) began to produce a significant amount of water, resulting in excessive water cut. To mitigate the issue, it was decided to completely isolate the zone using an organically crosslinked polymer system as a porosity fill sealant. When prepared in the appropriate concentration, subject to reservoir temperature, this low-viscosity formulation (40 to 80 cp) turns into a permanent rigid gel with time. The particular challenges of this operation were the presence of high permeability streaks because of stimulation by hydraulic fracturing, extra pore space because the perforated interval lay within the gravel-packed screens, and the subhydrostatic nature of the reservoir. Extensive laboratory testing was performed to optimize the formulation at the desired temperature, measuring the time necessary for the viscosity to begin increasing and the minimum total time necessary to form a rigid gel.
The case study discussed in this paper features the successful application of the treatment using the spot-and-squeeze method with coiled tubing (CT) for the isolation of the zone. After allowing the setting time, pressure tests were performed, indicating positive isolation of the zone. After the pressure test, a jet pump was installed, and a drawdown was created to flow the zone. It was observed that production post operation was almost 95% less than production before operation at the same pressure drawdown, indicating approximately 100% zone isolation.
Uetani, Takaaki (INPEX Corporation) | Kai, Jyunichi (Nippon Kaiji Kentei Kyokai) | Hitomi, Tomoko (Nippon Kaiji Kentei Kyokai) | Seino, Hitoshi (Nippon Kaiji Kentei Kyokai) | Shinbori, Kiyomasa (Nippon Kaiji Kentei Kyokai) | Yonebayashi, Hideharu (INPEX Corporation)
This paper presents the results of a laboratory case study that was initiated to understand the main causes of the crude oil emulsion for an onshore oil field in Japan. The factors investigated on the influence of emulsion stability were oil and brine compositions, content of asphaltene, wax and toluene-insolubles, temperature, shear-stress, and water-cut. The results showed the emulsion was stabilized by multiple factors, indicating that multiple preventative approaches are required to sustain stable production, free of emulsion.
Several methods have been deployed for artificial lift in deep long horizontal wells completed in unconventional reservoirs. Some methods have been successful whereas some others have failed. In our study, we investigated the various lift mechanisms and derived an envelope for their application to such horizontal wellbores using a sensitivity study through a transient fluid- flow wellbore model.
A calibrated earth model from the Eagle Ford Shale basin with hydraulic fracture geometries in the horizontal wellbore was used for the sensitivity study. The wellbore profile was changed in the simulation model to four different types of profiles: toe up, toe down, toe up with hold trap, and toe down with hold trap. Other factors such as location of the artificial lift equipment in the wellbore, reservoir performance, and deliverability were considered for the deployment of the artificial lift method. Transient fluid-flow wellbore simulations and numerical reservoir simulations were used to determine the performance potential and effectiveness of the artificial lift mechanism for long-term productivity.
Multiphase fluid flow and transient flow phenomenon are critical modeling considerations for horizontal wellbores. It was found that the critical flow rate in horizontal wells can vary considerably when the well profile is considered. As the drilling dogleg severity increases, the chances of wellbore slugging and liquid holdup increase. Additionally, with producing time, the conditions change. In a gas lift well, if the gas injection rate is maintained above the critical rates as determined in this study, the production issues can be controlled. Therefore, it is clear from this study that the well trajectory and drilling uncertainty window must also account for the artificial lift method that is planned to be deployed. Adjustments to the artificial lift method placement in the wellbore would help offset negative impacts if the wells are poorly drilled.
Recommended practice for drilling, completion, and artificial lift can be derived from this study. Integration of the artificial lift selection to the earth model, drilling trajectory and landing, hydraulic fractures, and the completion model is paramount to improve the efficiency of artificial lift in the unconventional reservoirs.
Thorough workflows such as the one presented by Oyewole (2016) in Figure 1 are tailored for the design and selection of artificial lift systems in unconventional wells. Oyewole's work covers technical, surface, drilling, reservoir, and geological and geophysical considerations together with economic factors.
While the oil and gas sector is facing one of its most significant slumps, producers have moved their focus in optimizing production of their existing wells rather than drilling new wells. Artificial Lift Systems (ALS) have played a significant part in optimizing and enhancing the production of existing assets. The primary scope of ALS is to maximize productivity; however, there are many such systems applicable, the selection of the most suitable lift system plays a vital role in cost optimization of the well.
A primary type of ALS is hydraulic lift, which has been recently applied successfully in north Iraq. A special form of hydraulic lift is the jet pump. This technology has proved to be one of the best lift types for the operator in the region, with the unique concept of no moving parts inside the downhole pump, which has dramatically reduced downtime and the need to move a workover rig to the well site. A jet pump can be installed in a well using a variety of techniques, depending upon the well completion and can be customized easily depending upon downhole conditions. However, if one does not monitor the operation and working parameters continuously, the performance of a jet pump will be reduced as well conditions change.
A jet pump was optimized as a test project for a well which was not producing naturally. This study was based on a variety of operational conditions of the well, such as injection parameters, flow restrictions and paths, surface pumping unit power, nozzle throat combinations, vessel operating pressures, and the productivity of nearby wells to calculate the reservoir potential. The evaluation, analysis, and design of a jet pump for this well were carried out on Jet Pump Evaluation and Modeling Software (JEMS). The most suitable nozzle throat combination for this well was 10D, which was used successfully to lift production to approximately 2,000 bpd.
This study describes the process and gives the results for successfully reviving production in a well with hydraulic lift. It also depicts the improvements of the optimized input power for each well depending upon the design selected. In the end, a methodology towards the selection of the best design and operating parameters of the jet pump for the mentioned well is discussed. The installation, types, and operation of the jet pump system are discussed in detail for a proper understanding of the lift method.
Drozdov, A. N. (Gubkin Russian State University of Oil and Gas (National Research University), RF, Moscow) | Vykhodtsev, D. O. (Gubkin Russian State University of Oil and Gas (National Research University), RF, Moscow) | Goridko, K. A. (Gubkin Russian State University of Oil and Gas (National Research University), RF, Moscow) | Verbitsky, V. S. (Gubkin Russian State University of Oil and Gas (National Research University), RF, Moscow)
The PDF file of this paper is in Russian.
Nowadays the most actual problems for oil producing from marginal wells are under-stream period increasing and specific energy consumption decreasing to raise fluid to the surface. The hydro jet method of the well operating allows solving the above oil production tasks. Despite of the advantages of the hydro jet method of operation, such as the fluid production with high gas content and mechanical impurities, the ability to drain formations with a low inflow, one of the problems is the lack of a simple engineering technique for calculating the hydraulic jet pumps (HJP) characteristics adapted for downhole conditions. In this article we present testing industrial HJP results with different values of the basic geometric parameter in a wide range of the active (7.2-13.1 MPa) and the passive (0.2-3.1 MPa) flow pressures simulating downhole conditions. 120 characteristics of the hydraulic jet pump operation were obtained. Based on the results of processing the experimental data, the influence of the above parameters on the HJP characteristics was determined: 1) the smaller the value of the basic geometric parameter provides the higher the pressure developed by the GOS; 2) the passive flow pressure increasing at the intake of the HJP leads to a more significant expansion of the cavity-free operation area than a decreasing of the active flow pressure ahead of the nozzle. There were generalized data of experimental hydraulic jet pump characteristics studies, which were obtained in this range of baric conditions. As a result of the experimental data processing, nomograms of the hydraulic jet pump cavitation operating modes were obtained. Also an engineering methodology for calculating the hydraulic jet pump characteristics, which can be used both for selecting the HJP to the wells and for assessing the current operation was developed. Based on the regression analysis, we obtained analytical dependencies of the cavitation parameters of the hydraulic jet pump (cavitation injection coefficient and cavitation dimensionless pressure drop) on the maximum dimensionless pressure drop corresponding to the zero injection coefficient. The error of the obtained model with respect to experimental characterization studies was estimated.
В настоящее время актуальными задачами при добыче нефти из низкодебитных скважин являются увеличение межремонтного периода и снижение удельного расхода энергии на подъем продукции. Гидроструйный способ эксплуатации скважин позволяет решить указанные задачи. При всех известных преимуществах гидроструйного способа эксплуатации, таких как добыча продукции с повышенным содержанием газа и механических частиц, возможность дренирования пластов с низким притоком, одной из проблем является отсутствие простой инженерной методики расчета характеристик гидроструйных насосов (ГСН), адаптированной для скважинных условий. В статье представлены результаты проведения испытаний промысловых ГСН с различными значениями основного геометрического параметра в широком диапазоне давлений активного (7,2-13,1 МПа) и пассивного (0,2-3,1 МПа) потоков, которые моделируют скважинные условия. Получено 120 характеристик работы ГСН. В результате обработки экспериментальных данных определено влияние указанных параметров на характеристики работы ГСН: 1) чем меньше значение основного геометрического параметра, тем больше напор, развиваемый ГСН; 2) увеличение давления на приеме ГСН приводит к более значительному расширению бескавитационной области работы, чем снижение давления активного потока перед соплом. Обобщены экспериментальные исследования характеристик ГСН, полученные в указанном диапазоне барических условий. В результате обработки экспериментальных данных получены номограммы кавитационных режимов работы ГСН. Разработана инженерная методика расчета характеристик ГСН, которая может использоваться как для подбора ГСН к скважинам, так и для оценки их текущей эксплуатации. На основе регрессионного анализа получены аналитические зависимости кавитационных параметров работы ГСН (кавитационного коэффициента инжекции и кавитационного безразмерного перепада давления) и максимального безразмерного перепада давления, соответствующего нулевому коэффициенту инжекции. Оценена погрешность полученной модели относительно экспериментальных исследований характеристик.