Casabe Field is a mature oil field located in the Mid-Magdalena Valley basin in Colombia, with over 60 than years of production. For the last 25 years it has been waterflooded using a five-spot injection pattern. In 2004 Ecopetrol and Schlumberger initiated a technological alliance aiming to increase the recovery factor and to incorporate new reserves. From an integrated work the project defined an aggressive drilling, completion, workover operations to convert old water injectors into multi-zone selective completion injectors and the abandonment of damaged wells campaign to optimize the waterflooding patterns. The workover program reached its highest activity peak of from 2008 to 2009. This increment brought the need to perform several well abandonments to avoid interference with the new injector wells. The abandonments also proved to be a main challenge of the campaign because of the well status complexity as severe casing restrictions, fishing, abnormal pressures, and reduced surface location area. A new methodology to optimize workover resources was developed based on alternating the use of a Coiled Tubing combining a Pulling Unit. This methodology enabled the workover in wells where workover rigs had serious downhole and surface limitations. From 2009, 96 wells were abandoned, 52% of them applying the method that combines both units. The methodology has generated so far 181 days of Workover rig time in savings, therefore allowing the rigs to complete more than 235 wells by the end of 2009, complying with the overall project program contributing with an incremental production of 5000 BOPD. In addition, this methodology to abandon well has generated alone savings of 1.5$MMUSD from the initial CAPEX. This paper will describe the agile well abandonment methodology combining Coiled Tubing and Pulling Units in a highly efficient, economical way, and complying with HSE standards and regulations allowing its application in any other oilfield.

Inorganic scales are new identified phenomena in Casabe field while corrosion has started to increase to alert the field operations. The field has been under waterflooding since 1985 with no much success due to lack of vertical selectivity. It was resumed in 2004 and boosted from 25000 BWIPD to 110000 BWIPD, and in consequence, some injection related problems which had never been recognized in the field turned out to be an issue from wellbores to surface facilities. Failures in tubings, casing and flowline integrity and storage facilities with evidences of corrosion, lighted on the alarms regarding the corrosion processes in the field. Diagnostic process started in 2010, revising the fluids being injected and the produced fluids from the wells, knowing that injected water is fresh and formation water has salinities up to 50000 ppm. Water samples were collected and analyzed to establish a current field wide corrosion baseline and evaluating the impact of the water injection process from the water source, injection lines and down into the injection wells and the reservoir, likewise the back to the producing wells x-mas trees. Chemical treatment is being applied upfront in the injection system, and corrective treatments have been implemented in some wells to reduce corrosion downhole. Simultaneously, a surface flowline integrity survey, maintenance and replacement by new materials were initiated to avoid spills or unexpected failures in the gathering system. Nevertheless, the current scenario is regularly under control, continuing monitoring is required in throughout the field. A new integrity management plan for the asset is under preparation since produced water is planned to be re-injected in the reservoir as primary source for the waterflooding. Whilst re-injection starts up, potential problems for corrosion could come up including scaling as it is indicated by Langelier Saturation index in the produced water.

Customers in Ecuador inject the byproduct formation water from production wells into injector wells. A limited injection rate bottlenecks production, which is economically undesirable. Two major contributors limit injection capacity: reservoir injectivity and flowline pressure losses. In the latter case, paraffins, asphaltenes, and scale, collectively referred to as "schmoo," progressively build in the flowline and reduce the internal diameter, limiting flow rate capacity. One cost-effective method to remediate flowlines with significant deposits is coiled tubing (CT) cleanouts. This unconventional method, which calls for optimized planning, execution, and performance evaluation, has been implemented in five flowlines. An economic analysis shows that remediating flowlines using CT cleanout yields significant savings as compared with replacement. After a candidate is identified, job planning takes into consideration flowline length and deviation (to identify maximum reach of CT), schmoo analysis (to design an optimal bottomhole assembly and fluid treatment), and execution logistics (to ensure a viable, reliable, and safe operation). After the cleanout, the flowline is put back into service, and the effectiveness of the treatment is estimated based on system flow rates and pressure losses. The equivalent internal diameter (ID) for the flowlines was improved by over 49% in each of the remediated flowlines, achieving an effectiveness of over 89% of nominal ID and increasing flow rates without a detrimental effect on system pressure. The cleanouts re-established nominal capacity in over 50k ft of flowline that no longer needed replacement. Lessons learned include the ability to complete the cleanout with water alone. The chemical analysis in planning stages showed the absence of carbonates, which enabled a mechanical cleanout with a high-pressure nozzle. Nonetheless, a chemical treatment was designed as a contingency. Another learning was that whereas tubing force models helped predict the reach of the CT, other factors created limitations. For example, the weld bead on the flowline limited the reach of the CT and required re-evaluating where to create cuts along the flowline. Finally, deploying the CT in a flowline required configuring the injector head horizontally, which required a customized base for safe rig up and operation of the injector head and pressure-control equipment. CT successfully cleaned out five flowlines with IDs ranging from 6-in. to 8-in. and re-established 89% to 98% of their nominal ID. As a result, the operator saved upwards of USD 14 million in flowline replacement costs, increased asset utilization, and decreased deferred injection. Historically, there is limited documented experience with flowline cleanouts using CT. The paper documents a repeatable methodology for candidate selection, planning, execution, and performance evaluation. It also provides basic building blocks to meet treatment design, rig-up, and execution requirements that are unique to this application.

Electrical submersible pump (ESP) is the main artificial lift system in Shushufindi field. These systems besides facing high gas production, high scale and corrosion tendencies, also have to deal with surface fluid handling and electrical power limitations which combined impose challenges to optimize the ESP system. In perspective, the digitalization initiative has been key to integrate data in order to have a big picture of the actual field condition and ultimately to enhance oil production. Various dashboards have been created using the business intelligence tool to provide real time information. ESP dashboard shows opportunities to optimize the ESP unit by integrating real time and manual entry data to optimize frequency, surface equipment, opportunities for pump upsizing, and re-designing the ESP downhole equipment. The result of this analysis is derived from ESP simulation, nodal analysis, chemical treatment monitoring and real time surveillance of the ESP parameters. Dashboards of water handling, electrical power, and chemical treatment are utilized to support process analysis providing current field status, with also the feedback from operational and engineering recommendations. Comprehensive real time monitoring resulted in average of 500 bopd less production deferment in the last 12 months as the result of early detection and a proper operational optimization (chemical treatment, gas flaring, and choke optimization) of the unstable wells. Strategic decisions have been executed to ensure the availability of water handling capacity and electrical power for each production station such as stimulating disposal wells, cleaning injection flowlines, and repairing power generations. Up to 3,000 bopd total incremental has been generated in the last 12 months as the result of 17 upsizing operations, optimizing frequency in 68 wells, and optimizing surface equipment in 35 wells. The associated mean time between failures (MTBF) of ESP system has increased over the time from 224 days in 2013 to 674 days in 2020. Digitalization is a game changer for optimizing the oilfield production and to reduce associated operation risks from features as of real time surveillance, EDGE computing, remote actuation, and big data intelligence. This paper will elaborate in detail on how digitalization can be valuable in optimizing ESP system with a successful case study in Shushufindi field.

PurposeTo investigate the change in routine outpatient ophthalmology UK practice during the COVID‐19 pandemic focusing on the use of telephone and video consultation. To determine the views of the UK consultant ophthalmologists on the role of teleophthalmology and its future use.MethodsA survey was designed to determine teleophthalmology practices pre‐COVID and during the first COVID‐19 lockdown. It also assessed participants’ views concerning the adoption of teleophthalmology and its future application within ophthalmology. The survey recipients were consultants within the UK. The data were collected and analysed using quantitative (SPSS, Chicago, IL, USA) and qualitative (thematic collation) methods.Results1. Statistically significant reduction in face‐to‐face workload during the first lockdown.2. Telephone and video consultation usage increased during lockdown; (93.8 %) of respondents performed telephone consultations and (23.8%) carried out video consultations.3. (46.25%) of consultants were concerned about the potential negative effect tele‐ophthalmology on training.4. (52.50%) of consultants did not agree that remote consultation should become the default modality of care (Strongly disagree‐disagree). Although, subspecialties like neuroophthalmology (50%) and oculoplastics (43.48%) supported the adoption of this model.5. (38.13%) of the consultant body thought that video consultation added value over a telephone consultation.6. Thematic analysis: Benefits: efficient in management low risk patients, useful as an adjunct to other services, increase capacity without the space issue and help deal with backlog of patients. Limitations: Investment into telemedicine hubs is required for it to become more applicable in more fields; not appropriate for some sub‐specialities and risks of missed signs and missed care. ConclusionsThe use of teleophthalmology increased during the first COVID‐19 lockdown. UK ophthalmologists expressed their concern about the negative impact of remote consulting particularly on training. More than 50% disagreed with making tele‐ophthalmology the default modality of care; however, sub‐specialities such neuroophthalmology and oculoplastics perceived that it could be valuable.