Ali Khan, Farhan (Weatherford) | Antonio Sierra, Tomas (Weatherford) | Gabriel Imbrea, Robert (Weatherford) | Robin Edwards, Michael (Weatherford) | Al-Rushoud, Ali (Kuwait Oil Company) | Al-Abdulhadi, Fahad (Kuwait Oil Company) | Shehab, Abdulaziz (Kuwait Oil Company) | Al-Ajeel, Fatemah (Kuwait Oil Company)
Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline. A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches. Operations were divided into six parallel processes as follows: 1. Equipment logistics 2. Gravel foundation preparations 3. Concrete foundation installations 4. Unit Pre-assembly 5. Pre-assembled units dispatches 6. Final unit installations Daily output targets were set for each process prior to the commencement of operations.
Failures due to solid particles flowing with the production fluid is one of the main causes of interventions in wells with beam pumping systems. When this problem is accompanied with chemical deposition like scale, leads to a very common intervention during well operation. This paper proposes an analytical methodology that consists of evaluation of the particle size distribution, viability for the use of sand screens and centrifugal separation systems for sand control management in wells with short run time. These systems have proven effective for failure wells that requires a sand control management system when if not addressed increase the lifting costs leading many projects to be infeasible from an economic standpoint. All the technical considerations are explained focusing on the information required and the parameters analyzed to recommend the most accurate design for sand control; selected approaches and models that have been developed to improve the run time due to sand issues are shown in this paper. A case study is showed in a well with average run time of 27 days indicating that identification of particle size distribution was a key factor to provide the right solution for sand control management. These novel applications help operators to reduced OPEX (operating expense), by minimizing well Interventions, decreasing failures in the pump; stabilizing the production and reducing the unforeseen interruption.
This paper discusses the application of IIoT in various areas of oil and gas upstream. It elaborates on the drivers of IIoT, presents the advantages and benefits and describes the challenges faced as of today in the implementation. IIoT and cloud computing work hand in hand. IIoT generates huge amount of data and cloud computing provides a pathway to present this data is a useful way and travel to the end user. A detail evaluation of the investment in using this technology and its anticipated returns are demonstrated. IIoT is believed to be an emerging solution for oil and gas complexities. The main drivers behind this technology are data storage, data analytics, reliability improvement and materiality assessment and control. The application of IIoT in areas of artificial lift optimization, Supply chain in real time, cyclic steam stimulation and flow assurance is described. This technology provides real time solution for dynacards interpretation and analysis for Sucker rod pumps, operating point analysis for Electrical submersible pumps and predicted cumulative production for all artificial lift optimization; efficient planning and waste elimination for supply chain and logistics; real time steam quality and quantity check for CSS and a complete digital approach to reservoir management and flow assurance. The main benefits of this technology are reduced MTBF, high efficiency, improved HSE standards, Instantaneous control over production loss, collaborative decisions leading to fast turnaround, highly responsive supply chain and enhancing environmental footprint. This has helped substantially in real time management of wells by exception and alerts in form of intelligent alarms indicating any deviation in the expected behaviour. This has significantly brought down the non-productive time (NPT). However, this paradigm shift comes with a substantial cost. The technical challenges include the data security, protocol non-uniformity, possible data loss and limitations of redundant system.
KOC has been producing oil using dual completions from different pressure regime zones from the same well and South East Kuwait field has many such dual completions wells which are currently being converted from natural flow completion to artificial lift completions. In one of such dual completion naturally producing well, first time in world an artificial lift system - Anchor Pump was installed in Short String (SS) through rigless intervention. Thus project well had un conventional dual completion in the field first of its kind i.e. Sucker Rod Pump (SRP) installed in short string and natural producer through Long String(LS). The well produced for some time through both strings and an intervention by workover rig was required due to high water cut and stuck anchor pump in short string. The paper describes the challenges and initiatives and learnings for safe execution of unconventional dual completion well workover.
Due to combination of natural flow and SRP artificial lift completion, the X-mas tree configuration and associated surface equipment of such well was had several constraints and HSE issues for mobilization of rig and dual production zones with varying pressure regimes have challenges of initial well killing due to plugged short string by stuck anchor pump. The risks were identified during planning stage and risk reduction measures were jointly agreed with Field Development. Various options were explored to minimize risks to ALARP level and subsequently addressed in Work Over Program. The surface equipment constraints were eliminated through rigless works and X-tree configuration were modified to suit deployment of a workover rig. Well process safety principles were applied to accomplish initial well killing in both production zones so as to safely pull out existing dual string completion without any well control issues. An initiative to use sucker rod back off tool, first time and safe back off operation was performed successfully from very close to stuck point.
The existing completion strings were pulled out and further well cleanout and workover program was well cleanout Finally, well was completed with new ESP completion string and successfully production tested. The most important factor in success was proactive planning keeping in view of Process Safety for well control issues and effective communication among the concerned parties.
The initiatives adopted in execution of such a challenging well intervention resulted enhancement in safety to rig crew and Rig operational safety standards in addition to contribution towards cost reduction. Lessons learnt has potential of rig time saving specially during workover of large number of heavy oil wells where stuck sucker rod conditions are very common due to sand invasion in tubing during production.
Bassam, Abdul-Aziz (Kuwait Oil Company) | Al-Besairi, Ghazi (Kuwait Oil Company) | Al-Dahash, Sulaiman (Kuwait Oil Company) | Sierra, Tomas (Weatherford) | Mohamed, Assem (Weatherford) | Heshmat, Kareem (Weatherford)
The demand for digital oil field solutions in artificially lifted wells is higher than ever, especially for wells producing heavy oil with high sand content and gas. A real-time supervisory control and data acquisition solution has been applied in a large-scale thermal pilot for 28 instrumented sucker rod pumping wells in North Kuwait. This paper focuses on the advantages of real-time data acquisition for identifying productionoptimization candidates, improving pump performance, and minimizing down time when using intelligent alarms and an analysis engine. Real-time surveillance provided a huge amount of information to be analyzed and discussed by well surveillance and field development teams to determine required actions based on individual well performance. Controller alarms and intelligent configurable alarms in one screen enabled early detection of unexpected/unwanted well behavior, re-investigating well potential, and taking necessary actions. The challenge was to handle heavy oil, sand, and gas production, maintain all wells at optimum running conditions before and after steam injections, and take into consideration the effect that injections would have on nearby wells. Recording in the database a "tracking item" for each well event enabled review and evaluation of the wells and creation of optimization reports. The daily, 24-hour surveillance of the wells resulted in observing common problems/issues on almost all wells and other individual issues for specific wells.
Zhao, Ruidong (RIPED, CNPC) | Li, Jinya (China University of Petroleum) | Tao, Zhen (RIPED, CNPC) | Liu, Meng (RIPED, CNPC) | Shi, Junfeng (RIPED, CNPC) | Xiong, Chunming (RIPED, CNPC) | Huang, Hongxing (NCCBM) | Sun, Chengyan (Daqing Oilfield Company, CNPC) | Zhang, Yufeng (RIPED, CNPC) | Zhang, Xiaowen (RIPED, CNPC)
With the development of many kinds of oilfields, deep well, high deviated well and cluster well are increasing rapidly. Sucker rod pumping still remains a major artificial lift method. There are such problems as severe rod/tubing wearing and shortened rod/tubing life in high deviated rod-pumped wells, and the mechanism and prevention of rod/tubing wearing have not been understood properly.
In order to understand the mechanism of rod/tubing wearing, a lateral load calculation model of rod/tubing is solved in this paper. The calculation results show that both the magnitude and direction of lateral force change dynamically with time and space in one stroke cycle. To better describe the rod/tubing wearing phenomenon, the lateral load is divided into two parts: the primary normal vector related to wellbore trajectory and axial force, and the secondary normal vector only related to wellbore trajectory and invariant with time.
The three-dimensional and dynamic nature of lateral force can account for the rod/tubing wearing partially. The results of mathematical model show that the magnitude of lateral force at the same depth may differ greatly at different times, and its direction may also change periodically. It is likely to be bidirectional rod/tubing wearing when the primary normal force direction changes periodically. Simulation results show that the direction of lateral force is very likely to change periodically below the neutral point of rod string. This finding has accounted for the common double-faced and multi-faced rod/tubing wearing on the lower rod string. The periodic change of lateral force direction will cause rod/tubing collision, which is also an important cause for the rod/tubing wear below the neutral point. It is assumed qualitatively that the production parameters such as pump depth, stroke, stroke frequency and pump diameter are the major factors of the rod/tubing wearing according to field experience. In this paper, mathematic model is used to analyze the impact of these parameters on lateral force and the quantitative analysis is also conducted which provide theoretical foundation for the design of anti-wear production parameters.
The mathematic model and method proposed in this paper are favorable to better accounting for the important phenomenon of rod/tubing wearing in rod-pumped deviated wells. They are capable of the quantitative calculation of lateral forces under different parameter conditions and the anti-wear design. This model has been applied to hundreds of highly deviated wells at Jidong Oilfield, prolonging rod/tubing life 58 days in average.
PCP population in PDO fields is around 18% of the total Artificial Lift systems with an average runlife of around 360 days. The main cause of failure are tubing leak and sand resulting in parted rods & pump stuck. Continuous PCP surveillance/ monitoring are key to understand pump performance and hence increase their runlife. With this objective, PDO has installed a PCP Controller application / surveillance tool called Well Manager in number of wells on trial basis. In the current set up, PCPs are operated using speed mode and the fluid level checked occasionally using simple fluid shot apparatus whereas with Well Manager they can be operated using different function like production optimization mode, dynamic fluid level or speed control mode all of these modes can be associated with de-sanding function or torque limiting function. These modes to be functional require running downhole gauge, casing pressure, flow line pressure and surface flow rate meters. Surveillance data collected from these meters while these modes are activated has allowed PCPs to automatically optimize their operating conditions to prevent trip due to sand accumulation and pump stuck and therefore increase runlife time. New PCP setup was installed in well No.1 aiming to reduce solids whilst keeping production rate as it was expected. Well Manager with automated flushing feature every 8 hours, and down hole gauge installed with ant-vibration sub has led for doubling the run life and eliminating FBU interventions. This has resulted in increasing run life from 113 to 239 days and still running. Moreover, compared to the old design in this well, the new set up managed to produce same flow rate using a smaller pump size with lower solids production rate. Another four units installed and showing positive results as well as stability with less well trips and increase in run life. The novelty and combination of the Well Manager set up can be replicated and implemented in all PCP wells in the oil industry helping to increase pumps runlife, reduce well intervention cost and oil deferment and therefore, reducing the life cycle cost.
PCP population in PDO fields is around 18% of the total Artificial Lift systems with an average runlife of around 360 days. The main cause of failure are tubing leak and sand resulting in parted rods & pump stuck. Continuous PCP surveillance/ monitoring are key to understand pump performance and hence increase their runlife. With this objective, PDO has installed a PCP Controller application / surveillance tool called Well Manager in number of wells on trial basis.
In the current set up, PCPs are operated using speed mode and the fluid level checked occasionally using simple fluid shot apparatus whereas with Well Manager they can be operated using different function like production optimization mode, dynamic fluid level or speed control mode all of these modes can be associated with de-sanding function or torque limiting function. These modes to be functional require running downhole gauge, casing pressure, flow line pressure and surface flow rate meters. Surveillance data collected from these meters while these modes are activated has allowed PCPs to automatically optimize their operating conditions to prevent trip due to sand accumulation and pump stuck and therefore increase runlife time.
New PCP setup was installed in well No.1 aiming to reduce solids whilst keeping production rate as it was expected. Well Manager with automated flushing feature every 8 hours, and down hole gauge installed with ant-vibration sub has led for doubling the run life and eliminating FBU interventions. This has resulted in increasing run life from 113 to 239 days and still running. Moreover, compared to the old design in this well, the new set up managed to produce same flow rate using a smaller pump size with lower solids production rate. Another four units installed and showing positive results as well as stability with less well trips and increase in run life.
The novelty and combination of the Well Manager set up can be replicated and implemented in all PCP wells in the oil industry helping to increase pumps runlife, reduce well intervention cost and oil deferment and therefore, reducing the life cycle cost.
This one day course will prepare both user/purchaser and supplier/manufacturer to use ISO and API standards for electric submersible pumps (ESP), progressing cavity pumps (PCPs), gas lift and sucker rod pumping systems. Instructors will demonstrate the various ways how to apply these standards, including (but not limited to) equipment purchase, testing, bid specifications and response to tenders. Intermediate – Basic knowledge of ESPs, PCPs, gas lift and sucker rod pumps will be required. This course is for artificial lift engineers and managers who have (or will have) a role in the procurement process for their company (from request for equipment by user/purchaser through to the response by supplier/manufacturer and delivery of equipment). All cancellations must be received no later than 14 days prior to the course start date.
The main objective for the implementation of this methodology was to achieve uninterrupted production and avoid failures. Heavy oil wells undergoing CSS in the field in Kuwait, pose challenges of high temperature and sand incursion. As soon as the well was brought on production at the end of soaking period, Metal PCP, which was earlier believed to be the best choice proved wrong when it underwent failures due to dry run because of steam (gas) and the lost interference fit between the stator and rotor owing to reduced viscosity and poor efficiency due to fluid slippage. The strategy was revisited and Sucker rod pumps were initially installed as soon as the well came on production. Being shallow wells on VSD control, they were safely ran at 3 SPM and that kept the sand from entering the well since the velocity of the fluid kept way above the critical velocity. The pump produced around 100 bbl./day. As the reservoir cooled, and the viscosity increased, the calculated rod stresses were seen to increase beyond 80%. Anticipating the rod failures and the subsequent production loss, strategic decision to install all metal PCP was made for the next period of production. The increased viscosity of the fluid provided excellent efficiency to the PCP operation and also eliminated the rod fall. The well produced around 245bbls/day consistently. Thus the methodology states alternating the Sucker rod pump (SRP)and All Metal PCP (AMPCP) through the production cycle using viscosity as the indicator.
The cost and benefits of this approach was evaluated. The work over cost to replace the AL type against the costs due to failures and production loss was studied. It was concluded that this system provided the tangible cost benefit of around 30%, along with the uninterrupted production and conserving the heat energy in the reservoir. This method utilized the best combination of the performance features of SRP and PCP in their optimum operational brackets.
Considering the energy loses to the reservoir for a short period, which will be caused due to the work over rigs that utilize the cold mud fluids to replace the AL system or to clean the deposited sand which would cover the perforation, some design changes were made such as drilling the hole 1000 ft more than originally designed to maximize the production.
The manuscript focuses on benefits realized in sucker rod pump system performance, number of workovers, downtime periods, and overall production efficiency as a result of continuous steam injection (steam flooding) on a heavy oil pilot field. It also presents benefits on production performance as a result of realtime well optimization of sucker rod pump systems. Implementation of real-time production optimization techniques to record behavioral changes provide for up-close field operational surveillance (allowing for faster response time). The steam injection effect varies from between locations, based on the distance between injector and producer wells, along with the degree of down-hole interference. The objective was to study steam injection effects on a group of wells and adjust the operational parameters of sucker rod pump systems based on individual well performance conditions. Real-time wellsite monitoring (including creating notifications, warnings and alarms to identify troublesome or non-optimized wells) and data-trend analysis allowed us to make necessary corrective actions continuously, which led to an improvement in well performance since steam injection started (thus optimizing productivity). The continuous steam injection, supported by real-time optimization and constant sucker rod pump system performance adjustments, led to the following operational efficiency improvements: 1. Reduced downtime related to troubleshooting activities 2. Reduced pump replacements (obtaining longer run life of downhole equipment) 3. Improved pump efficiency (measured by improvements in production rates) 4. Created a workflow for sucker rod pump system performance review and optimization opportunities 5. Improved field-wide overall production 6.