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: Equipment logisticsGravel foundation preparationsConcrete foundation installationsUnit Pre-assemblyPre-assembled units dispatchesFinal unit installations Daily output targets were set for each process prior to the commencement of operations. Heavy machinery, manpower and tooling requirements were defined for each process to meet the daily output targets. Progress was monitored daily and subsequently resources were scheduled and utilized to achieve the daily output targets. Setting up of a temporary operations base at the remote field along with daily coordination of resources resulted in reducing equipment’s offloading, transportation and installation cycle times, which led to increased operational efficiency and reduced logistics and operations costs. Division of operations into parallel processes helped in tracking the progress of each operation individually, thereby providing over all control in management of operations. By pre-assembling the beam pumping units at the operations base before dispatching the individual unit, installation time was reduced by 50% when compared to a typical beam pumping unit installation. Daily output target setting helped in defining the resources required to meet these targets. As the operations progressed, daily monitoring of all processes resulted in identifying opportunities to improvise operations and subsequently the daily targets were revised to increase output for each process without exceeding the resources which resulted in time and cost savings. Adopting this execution strategy concluded in successful and efficient completion of the project deliverables as follows:Gravel foundation preparations were completed in 133 work daysConcrete foundation installations were completed in 121 work daysBeam pumping unit installations were completed in 103 work days This field operations strategy for installing conventional beam pumping units at 660 production wells within six months can be considered as a reference for successfully and efficiently completing future large-scale beam pumping unit installation projects at remote locations in a limited time frame.

Exploitation of heavy oil fields is a challenging task in Kuwait Oil Company (KOC). Most of these fields require artificial lift to produce optimally. Reliability, operational ease, run-life and steady oil gain, are the key issues, for application of artificial lift, to produce heavy oil. It is our constant endeavor to seek value addition, with regard to these parameters. In view of this, pilot of ‘Hydraulically Regulated PCP’ (HR-PCP) technology, is implemented for heavy oil cold production. Preliminary studies revealed that HR-PCP technology is designed to handle multi-phase flow conditions more efficiently, due to its unique design. Pilot trial is carried out for a representative heavy oil reservoir, having crude oil gravity of 14°API, with top of the perforation at 7819 feet. Objective of the pilot is to evaluate performance of HR-PCP technology, with regard to the heavy oil cold production. Study is based on actual field implementation and does not include any lab studies. The paper, essentially, encompasses various aspects of the pilot such as pilot methodology, technology evaluation, candidate well selection and HR-PCP design as well as details regarding pilot implementation and pilot study results. During the pilot period, relevant pump and well parameters are constantly monitored, with an aim to optimize pump performance. It is concluded from the pilot results that implementation of HR-PCP technology, for this heavy oil reservoir, is proven to be successful in terms of achieving steady oil gain and sustained run-life. Maximum oil rate of 567 b/d and peak MTBR of over 400 days, are achieved during the pilot period. Pilot studies have also prompted us to install HR-PCP technology for other similar wells. Thus, HR-PCP technology emerges, as a viable artificial lift mode for our heavy oil production strategic plan. Results amply demonstrate that the technology can also be applied for other heavy oil reservoirs of similar nature.

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 real-time 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: Reduced downtime related to troubleshooting activitiesReduced pump replacements (obtaining longer run life of downhole equipment)Improved pump efficiency (measured by improvements in production rates)Created a workflow for sucker rod pump system performance review and optimization opportunitiesImproved field-wide overall productionImprovement in sucker rod pump system efficiency (pump efficiency dyna card analysis was significantly improved in wells with low pump submergence after steam injection) Maintaining the same downhole pump configuration, we found that pump efficiency (calculated by measured production rates) changed significantly: from low efficiency before steam injection (on colder periods) to higher efficiency (after steam injection). We also studied pump performance during the production phase and adapted the sucker rod pump system operational parameters to the wellbore's changing operation conditions, driven mainly by wellbore's temperature changes. Applying continuous steam injection in a heavy oil area supported in improving pump performance, reducing downtime, and improving overall production from a specific number of wells, compared to lower production and higher downtimes (with larger number of wells), but without continuous steam injection.