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This paper explains the design and the execution of a rigless intervention to resume production from a dry completion offshore installing successfully a Sucker Rod Pump (SRP) system replace a faulted redundant Electrical Submersible Pumping (ESP) system.
Nowadays all oil companies need to work with small budgets and must search for methods of well intervention that reduce operational costs. Considering an offshore field, any intervention is very expensive. In the present case, in a unique well located in caisson platform, a conventional workover would consist recovering and replacing ESP system set at 3.350 ft that operated for about 10 years. To change the bottom hole equipment, a jackup rig was needed, but such a ring was not available and, even if available, its cost probably would be prohibitive for production maintenance. The solution adopted was to run SRP system with an insert pump anchor enabling it to be set at any depth inside the tubing, above the failed ESP assembly. A Linear Rod Pumping (LRP®) was chosen because its profile and its small footprint that allowed its installation with the small Caisson Platform topside area. A structure ("portico") was built on the caisson to perform the new system installation. The successful use of the SRP system permitted to resume production with short well downtime and reduced intervention costs, eliminating the need for a the workover jackup rig.
Even though the outcome of the installed SRP system is around 50% of the last ESP registered flow rate, the solution was an economically attractive option to keep production and also allows future changes of the lifting system without the need of a workover rig.
Nader, Lukas (Upwing Energy) | Biddick, David (Upwing Energy) | Artinian, Herman (Upwing Energy) | Kulkarni, Pandurang (Equinor) | Van Hoy, Bob (Riverside Petroleum) | Zdan, Steve (Riverside Petroleum)
Unconventional oil and gas development revolutionized the energy sector in North America and has been transforming the world's energy markets. Notwithstanding the enormous potential, unconventional resource development presents unique challenges to production and long-term hydrocarbon recoveries. As market dynamics are shifting, technologies are advancing, opening up new opportunities in areas once considered out of reach. This paper describes a new technology, a subsurface compressor system, which simultaneously removes liquids, increases gas production, and improves recoverable reserves in gas wells. The subsurface compressor can reverse the vicious cycle of liquid loading, which decreases gas production from a gas well and leads to premature abandonment, by creating a virtuous cycle of increased gas and condensate production. The complete process from well analysis, performance projection, deployment, commissioning to operation are discussed. A recently completed the world's very first field trial in an unconventional shale gas well supports the mechanism of subsurface gas compression and its impacts and benefits on unconventional gas production.
After years of testing and development, the rodless artificial lift technology for low production wells including submersible plunger pump and ESPCP is going into scale applications stage in CNPC. About 150 ESPCP field applications have been used, the performance of system showed longer running time, great energy saving and less workload of maintenance compared to the previous rod pumping unit. But from the statistic of field applications, the cable failure is one of the most common failures. So, we proposed a new cable installation equipment and method with submersible cable plug with ESPCP in this paper.
Compared to the traditional method that the cable is fixed outside the tubing, we located the cable in the tubing. There is a cable socket above the pump. In this way, the cable plug was lowered down into the tubing with the cable after putting the tool string downhole. The plug was put into the socket by the gravity force. Therefore, there was a heavy-weight part above the cable plug to guarantee the high successful rate of lowing and plug-in process. Up to now, we have used this submersible motor cable plug technology in seven wells in Xinjiang oil field.
The results show that the cable can connect to the socket successfully in ESPCP field applications. There are lots of advantages compared to the traditional operation technology. First, the operation time was shortened from 3 days to 1.5 days by eliminating the installation of cable clips and insulation test when each 10 tubings were lowed in. It can enhance the operation efficiency and reducing the operation time. Second, there was less cable clip using in this technology. It can decrease the operation cost of cable clip. At last, it avoided the cable abrasion from the tubing when lowed the string into the well, which is one the most likely failure reasons. In this way, it enhances the safety factor of operation and the cable can be reused in another well.
This technology makes the operation safer and more efficient. It can be used with not only ESPCP technology, but also other submersible artificial lift technologies.
The objective of this study is experimental and theoretical investigation of the fall mechanics of continuous flow plungers. Fall velocity of the two-piece plungers with different sleeve and ball combinations and bypass plungers are examined in both static and dynamic conditions to develop a drag coefficient relationship. Dimensionless analysis conducted including wall effect, inclination and liquid holdup correction of fall stage. The fall model is developed to estimate fall velocities of the ball, sleeve, and bypass plungers. Sensitivity analysis is performed to reveal influential parameters to the fall velocity of continuous flow plungers.
In a static facility, four sleeves with different height, weight, and OD, three balls made with different materials and a bypass plunger are tested in four different mediums. The wall effect on settling velocity is defined, and it is used to validate the ball drag coefficient results obtained from the experimental setup. Two-phase flow experiments were conducted by injecting gas into the static liquid column and liquid holdup effect on drag coefficient is observed. Experiments in a dynamic facility are used for liquid holdup and deviation corrections. The fall model is developed to estimate fall velocities of the continuous flow plungers against the flow. Dimensionless parameters obtained in the experiments are combined with multiphase flow simulation to estimate the fall velocity of plungers in field scale.
Reference drag coefficient values of plungers are obtained for respective Reynold number values. Experimental wall effect, liquid holdup and inclination corrections are provided. The fall model results for separation time, fall velocity, total fall duration, and maximum flow rate to fall against are estimated for different cases. Sensitivity analysis showed that the drag coefficient, the weight of plungers, pressure, and gas flow rate are the most influential parameters for the fall velocity of the plungers. Furthermore, the fall model revealed that plungers fall slowest at the wellhead conditions for the range of gas flow rates experienced in field conditions. Lower pressure at wellhead had two opposing effects; namely, reduced gas density, therefore reducing the drag, and gas expansion, increased the gas velocity, therefore increasing the drag.
Estimating fall velocity of continuous flow plungers is crucial to optimize ball and sleeve separation time, plunger selection and gas injection rate for plunger assisted gas lift (PAGL). The fall model provides maximum flow rate to fall against, which is defined as the upper operational boundary for continuous flow plungers. This study presents a new methodology to predict fall velocity using drag coefficient vs. Reynolds number relationship, wall effect, liquid holdup, deviation corrections and incorporating multiphase flow simulation.
Rod Pumping and Progressive Cavity Pumping Artificial Lift Systems have sucker rods as one of their main components exposed to failure. Given the different available brands, metallurgies and even conventional or unconventional options, a necessity emerged to develop an analysis that integrated the concepts of production engineering, artificial lift engineering, corrosion engineering, metallurgic engineering and reliability with failure history and different additional calculations, to conform a tool capable of statistically predict what type of sucker rod to use on each well according to specific characteristics.
Towards September of 2016 in La Cira Infantas Field sucker rod failures reach around 150, which were associated to corrosive fluids and wear-friction between the tubing and the sucker rod. The analysis had a mathematical-statistical approach with mainly predictive characteristics based on the historic behavior of the wells and associated to different parameters of the production and operation fluids. This set of variables returned a specific behavior in some cases better than others when using certain types of materials.
Once obtained all parameters of the study, it was stablished a valuation of the different sucker rods used on the field. The result of the analysis was the matrix of selection of the sucker rods with best performance, this gave way to the unification and standardization of the different sucker rods to use depending on the conditions and scenarios that they will exposed and submitted to on each particular well of the La Cira Infantas field. This allows to take short- and long-term action plans, where budget proposals can be reviewed, which will be reflected on the failure index decrease and a better technical-economical evaluation.
The development of the project along with other studies and practices on the La Cira Infantas field, achieve to reduce approximately 40% the failures with respect to its previous year and in the following year 10%. This allowed to reduce the failure expending and the deferred production.
Conventional artificial lift selection tools often involve cursory table lookups with interdependent variables and generous design value ranges. This paper describes a semiautomated selection tool created to perform a screening level of analysis for several industry available artificial lift alternatives to quickly direct users towards preferred methods for further investigation. This approach takes the user provided well, fluid and field data, and applies a series of filters, resulting in a summary page displaying feasible and preferred well-specific artificial lift solutions for further investigation.
Tavares, Alexandre (Enauta) | Rocha, Paulo Sérgio (Enauta) | Santos, Marcelo Paulino (Enauta) | Neto, Salvador Alves (Enauta) | Matos, João Siqueira (Enauta) | Lemos, Daniel Gruenbaum (Baker Hughes) | Freitas, Marcelo Matheus (Baker Hughes) | Martins, Luiz Alexandre (Baker Hughes) | Daun, Leandro (Baker Hughes)
Atlanta is a post-salt oil field located offshore Brazil in the Santos Basin, 185 km southeast of Rio de Janeiro. The combination of ultra-deepwater (1,550 m) and heavy and viscous oil (14 °API and 228 cP at reservoir conditions) composes a unique challenging scenario for Electrical Submersible Pump (ESP) application. The paper discusses the performance of the ESP system utilizing field data and software simulations.
The in-well ESP is the main production method and mudline ESP boosting is the backup one. Both concepts proved to be effective artificial lift solutions for the harsh flowing conditions. The in-well ESP is installed inside a capsule in a close to horizontal slant section of around 70 m. The mudline ESP boosting is readily available to become the main production method in case the in-well ESP fails.
This paper discusses the challenges and solutions that proved to be successful after more than 18 months of continuous production. Software simulations and continuous production monitoring were key factors for system modeling and optimization.
One of the most powerful ESPs installed inside a well worldwide to produce heavy and viscous oil from an unconsolidated reservoir represents a step forward in ultra-deepwater production system boundaries. The concept of having the mudline system as backup is also an innovative step for the offshore oil and gas industry.
Two production periods are presented with very distinct and unusual characteristics: (i) one producing 12,500 bpd of a high viscous, high Gas Void Fraction (GVF), low inlet pressure and temperature crude through two mudline ESP boosting systems and (ii) another one producing 30,000 bpd through three in-well ESPs.
Plunger lift is a form of artificial lift popular due to its low installation and operating costs. Historically plunger lift was reserved for low producing stripper gas wells due to limitations on liquid rate and gas volume requirements. More recently, the use of continuous run plungers and SCADA systems have extended application of this method of artificial lift to wells producing higher volume of liquids. Today, gas-assisted plunger lift (GAPL) and plunger-assisted gas lift (PAGL) technologies allow wells with insufficient gas volume produced by the reservoir or low gas-liquid ratios (GLR) to also lift liquids to the surface with plungers. Plunger lift is currently used in every major shale play in the U.S.
While plunger systems are attractive for their low cost and relative simplicity, several challenges prevent engineers and optimizers from operating wells equipped with these systems at peak production with minimum lifting cost ($/Mcf). One of the primary challenges encountered by plunger lift operators is selecting the appropriate algorithm to control the various aspects of a plunger cycle. Once selected, frequent setpoint adjustments are often necessary to accommodate varying well conditions and production loss as the well moves along its own natural decline curve.
Dozens of plunger lift control algorithms have been developed to account for different well conditions and optimization protocols. However, challenges exist that prevent optimization at scale which include: varying degrees of operator knowledge, time availability, number of wells, changing well conditions, data quality, data accessibility, varying plunger lift controllers, lack of API standards, limited understanding of downhole conditions, etc.
To address these challenges, a plunger lift optimization software was developed. One aspect of the software is enabling setpoint optimization at scale. This paper will present the methodology to do so, detailing three separate areas working in unison to offer significant value to plunger lift well operators. First, a novel physics engine was developed to deliver superior downhole insights. The physics engine incorporates improved analytical models for horizontal wellbores from literature and implements improved mass balance and thermodynamic equations of state, which allow for improved calculations of critical flow rate, critical lift pressure, and plunger fall velocity. Second, dynamic well optimization was employed to drive optimization decisions and provide anomaly detection to users. The well optimization model dynamically runs calculations over the data, alerting users to key anomalous conditions and provides insights into well instability and sub-optimized states. Third, artificial intelligence was deployed to drive further optimization and allow setpoints to optimize continually over time. Layered on top of improved physics and well insights, artificial intelligence and numerical optimization continually search for the optimal setpoint values and plunger selection to maximize production rates across entire fields.
Progressing Cavity (PC) pumps evolved from their industrial pump origins to a diverse range of geometries and configurations that satisfy a variety of oilfield artificial lift applications including several where no other lift systems had proved effective. While these downhole PC pump designs provide options for end users, the numerous products combined with a lack of industry standardization has the potential to make pump selection and application challenging. The first part of this paper describes the fundamental PC pump geometry parameters along with various other design parameters and provides context for how they are incorporated in downhole PC pump design. A second part demonstrates how the PC pump design flexibility can be deployed to address specific operational challenges through a synopsis of the design and field experience of two novel PC pump configurations. The first new configuration uses a modified rotor geometry with alternating sections of interference and clearance fits with a standard stator. Since the clearance sections of the stator do not experience contact and as a result normally no elastomer damage, the associated section of stator remains intact in most cases even after prolonged pumping under problematic operating conditions. After the initial interference sections of the stator have been damaged, an adjustment to the rotor position can be made to the non-damaged section of the stator by lifting the rod string a short distance at surface, thus restoring pumping operation without surfacing the pump. The second novel PC pump configuration employs a modified low eccentricity large cross-section rotor geometry. Potential benefits of this configuration are a strong rotor that is less prone to breaking when operating in highly directional wellbore segments; reduced eccentric pump movement that minimizes rod breaks and vibration above the pump; a rotor profile that when sanded-in pulls free easier at lower safer loads for flushing/coiling; and a wider seal line profile that makes the rotor less prone to severe damage and results in higher salvage rates for rechroming. Several different models of both novel pump configurations have been developed and run in the field to confirm benefits.
Variable Frequency Drives (VFDs) are an advanced type of beam pump-off controller with the ability to increase or decrease pumping speed. This facilitates drawing down the fluid level to near pump off conditions and maintaining a constant bottom hole pressure, all while running 24 hours per day. VFDs have been successfully utilized over the last few years to reduce the failure frequency in the most problematic wells, and in some cases, increase production as well.