Traditionally, geoscientists, drilling, reservoir, and facility engineers work separately on projects. The workflows between these disciplines are typically onerous, iterative, and time consuming because there is no common environment between roles. For offshore fields, the limited number of towers from which wells can be drilled make well planning a critical process for a successful development. Usually, planning is done on a well-by-well basis, which could introduce the potential for increased risks. ADMA-OPCO has begun developing an offshore green field through drilling about 90 wells (duals and singles) from eight wellhead towers. The development scheme for this field is optimized per reservoir, five-spot water injection, natural depletion, and gas injection. For each tower, slots (injector vs. producers) and allocations have to be defined with high confidence and be communicated to surface project teams to start the design and engineering process. This exercise requires working all well trajectories (drillable wells that meet the statements of requirements). Early in the field-development process, the common practice is to do the well-profile work on a well-by-well basis, which takes a minimum of three to five days per well depending on well type and complexity. This paper addresses a different approach that is used by ADMA-OPCO, which allowed for accelerating the planning process by integrating all stakeholders for the objective of reducing the working hours while optimizing the trajectories and taking into account all criteria and safety guidelines executed within a 3-D static-model environment. As an outcome, more than 100 horizontal drains were successfully optimized, and slot allocations were defined for all towers within 20 working days (minimum of 380 days would be required if done on a well-by-well basis). A drilling footage of more than 20, 000 ft was saved after optimization. Additionally, the real collaborative value was seen in the integrated working sessions, resulting in an improved deliverable.
Driving efficiency to ensure cost and risk reduction in well operations is paramount for any operating company; to achieve this, the main objective was to implement a continuous improvement process that measures performance to then improve it, acquiring lessons learned and finally implement new technologies to reduce non-productive time, invisible loss time and push the technical limit to the limit. The first step was to measure the current performance to determine average and best references to compare against. The drilling operations and engineering teams defined KPIs for each well type and respective sections and activities involving all levels of the organization including every individual, ensuring effective communication inclusive of Rig Crew and Service Providers. The initial KPIs were defined, discussed, validated and agreed by both operations and engineering management, all engineers were informed and challenged to measure their performance against KPIs. Once new records were achieved, a workflow to document best practices initiated, once identified, validated and documented, becoming the new standards. Similarly, once average performance was not achieved, a ‘Lessons Learned’ workflow was initiated. Aiming to get the team engaged a communication protocol of the Highlights and Lowlights was put in place, including recognition during operations meeting and emails. The primary results of the deployment of this initiative include the delivery of a 10% additional well count compared to the initial year's plan. An overall improvement of the overall Drilling and Completion Performance was also noted. An important improvement of the overall Rate of Penetration (ROP) was observed, as one of the key performance indicators. It was also notice a considerable reduction of the Flat time. New practices for losses mitigation in hazardous areas were stablished. The lower completion design was enhanced. The upper completion design and utilize Dual Hydraulic Packer in Oil producer well was optimized. Finally, the 1st Maximum Reservoir Contact Well was completed for two of the three Fields in the Team. The added value achieved by the implementation of these innovative practices includes the implementation of the KPI Gauges as a visual instrument to be used on daily operations meeting by the engineers and management, to quickly and effectively understand performance and improvement in multiple dimensions. Additionally, the implementation of a continuous improvement mind-set, focus in introducing changes gradually instead of radically to ensure a soft and solid adoption embraced by all team members. Finally, the improvement of the office-field communications, including a sense of ownership and achievement for each goal to achieve and record to break, to the point that every colleague involved in a specific operation, independently of their organization (Operator, Contractor or Service Company) is equally committed and engaged.
Collaborative field development well-planning concepts have been subject of several studies in upstream industry, with limited supporting workflows that are often based on case by case studies, which are not necessarily scalable in limited turnaround time due to complexities of larger field development projects. The traditional workflows are highly linear and inefficient, due to lag times while various functions perform their due diligence, reconsider assumptions that eventually increases risk of not achieving the optimal solutions and thus reducing the efficiency. This Paper discusses how all relevant field development workflows were brought under a single collaborative solution environment with efficient workflows, data integration and its successful deployment for optimum pad-based field development implementation for a large brown field. In traditional field development well planning, the workflows such as reservoir targets creation, field development well planning scenarios, wellbore positioning & drillability, surface location optimization and costing are performed manually in siloes. It is indeed challenging to govern and manage data efficiently across these workflows in an integrated way to serve various domains and departments. With larger brown fields, further disintegration of functions across multiple reservoirs, well construction parameters and reservoir developmental strategies occurs. The proposed approach is driven by multidisciplinary collaborative solution environment built on automation and optimization technologies enabled by automated cross-domain data integration across several data sources. The above stated workflows have been automated in a single solution workspace that can quickly respond to risk or changes. This smart collaborative environment has been adapted to optimize the pad-based onshore mature field development for a large field across the planned drilling schedule of wells in order to mitigate the impact of increasing surface congestion in the field due to planned facilities, wellheads whilst considering geological uncertainties. This analysis has been performed while maintaining constraints such as identification of optimized size, number and orientation of pads, slot allocation for pad & off-pad well locations, long term development scenarios including EOR pilots, anti-collision and proximity to production network nodes as well as minimizing CAPEX while remaining in-line with HSE standards. This collaborative solution environment has successfully demonstrated value of data integration with appropriate workflows thus improving communication, accountability and transparency in planning stages of field development. Accelerated field development well planning has reduced uncertainty and multiple iterations of scenarios were generated due to cross-collaboration between teams to evaluate cost and business impacts on a significantly reduced timeline for optimizing field development. This paper illustrates implementation of collaborative solution and respective automated workflows, data integration framework and its synergy with current working environment. The case study explains the successful adoption, workflow collaboration between asset development, drilling & engineering by visualizing various constraints and outlined benefits & value.
The understanding of salt beds has been significantly improved over the years; however, certain operational challenges still persist. Conditions encountered during drilling salt formations may lead to stuck Logging While Drilling (LWD) and or wireline tools, which, at times, can contain radioactive sources. As data gathering remains a primary requirement in exploration wells, cost optimization, beside risk mitigation, is a further challenge in today’s economic landscape. A holistic approach is proposed to address these main objectives. The conventional procedure required drilling and formation evaluation (LWD and or wireline) in the section above the interbedded salt formation, followed by rotary steerable (RSS) only in the interbedded salt formation sections of the well. Considering the shallow depths of the well and the proximity to the aquifers, the threat posed by losing radioactive sources in the well is significant, therefore, formation density and neutron porosity logging operation is often compromised due the inherent risk. Logging While Tripping, a method in which tools record open hole data from inside the pipe, resolves this compromise, as the risk of lost in hole (LIH) is virtually eliminated. The empty LWT collars are run in the last bit trip or reamer run, as they do not affect the drilling operation. Once the well’s total depth is reached, the LWT logging tools are pumped from surface, safely inside of the pipe, and data is acquired while tripping the drill pipe out of the well. If the situation is evaluated as risky, drilling operation may continue without data acquisition. In case the logging tools already were deployed, they can be retrieved at any time by wireline or slickline. Prior to the introduction of the LWT in the drilling/data acquisition procedure, only gamma ray - sonic data was acquired over the challenging formation sections. Compressional and shear data may be important to improve modelling accuracy; however, they may be negatively affected by various factors such as drilling noise, mud properties, washouts and gas in the formation, particularly reservoir rocks interbedded with thick salt beds. When compared to the Neutron-Density porosity, sonic porosity is noticeably inferior, showing limited formation signature. Neutron-Density porosity correlates well with core data.
Aiming to make the well planning process leaner and agile focusing on duration reduction without compromising quality of deliverables, automation opportunities have been identified within the multi-discipline iterations. The two key criteria considered for the selection of the automation project were: Minimum deployment effort and Maximum value added in efficiency. The initial project objective was to calculate formation tops for a well engineer without requiring the intervention of a geoscientist using commercial software. The methodology utilized is the following: 1. Inputs: Well trajectory and Surfaces. 2. Process: The algorithm finds intersections between surfaces and well trajectory. Surfaces and trajectory are represented as a set of XYZ points. To find the intersection, the software iterates through each point of the trajectory from the top, comparing the depth of the projection to the target surface. The projected depth to the surface is found by 2D interpolation of the surface. Once the trajectory point becomes deeper than the surface projection, the intersection is estimated using geometrical considerations of similar triangles. 3. Deliverables: Estimated formation tops for the given trajectory. 4. Results: Simple in-house developed software enhanced well planning workflow in an Offshore Green Field. The software converted to single executable file and can be run on any device without the open-source software installed. Very accurate results achieved with proposed algorithm with a negligible difference of 0.5 feet with the geoscience traditional software. Well planning duration reduced from average 1 week to 1 or 2 days. The workload for well engineers and the asset team has been dramatically reduced. Reduction of the number of commercial geoscience software licenses required. Way forward: A test with a slightly modified code was used to generate formation tops for more than 400 well in a Long-Term Field Development Plan project for a Brown Field during feasibility study. Upscale to all the Fields within the organization. Improve User Interface for better adoption. Include more formats for both, trajectories, and surfaces. Reduce computing time. This project represents the first initiative in the organization aiming to automate the well planning process. Overall, it represents the beginning of a journey where multiple opportunities for automation can be achieved using an open-source coding software that allows any engineer with little to no experience coding to being able to generate solutions to address daily challenges.
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