Updated: Sep 26, 2018
by Maurice Rios, Director of Operations
Expanding infrastructure to support additional wells, pads or wellsite gathering facilities is usually a multi-million dollar endeavor that requires careful planning and coordination between the E&P operator and its selected vendors. These critical investments are carefully evaluated on a number of criteria, particularly ROI and HSE. Operators need to offset their CapEx investment with uplift in production volume, and the ability to sell the product at a favorable price over a long period of time before they are able to break even, better yet profit.
With oil prices north of ~$70/bbl and climbing, many oil companies are finally in a position to increase field production by drilling and completing new wells. More drilling activity means equipping wellsites and fields with facilities capable of pumping, separating, processing (in the case of natural gas) and storing the raw hydrocarbons before transferring them into pipelines, tank trucks or rail cars that will carry them to compressor stations and refineries before selling them on the open market. An average wellsite will likely include several wells and gathering lines, storage tanks, a separator, a few compressors, a disposal well for produced water, and possibly an injector well for artificial lift. This infrastructure is carefully outfitted with valves, gauges, pumps, sensors and more that regulate the flow of hydrocarbons from the well.
The design team for the wellpad infrastructure usually consists of a multi-disciplinary group of engineers including, but not limited to, reservoir, drilling & completions, mechanical, and electrical engineers, along with the Asset Manager, Operations Supervisor, SCADA Manager and possibly a third-party Engineering, Procurement and Construction (EPC) firm. Together this team will define the specifications and create the Statement of Work (SOW); carefully weighing their options and ensuring the wellsite facilities will be scalable for current and future needs.
During the last downturn, many operators were faced with decisions around shutting-in wells. This means they had previously drilled the wells, but opted not to complete them on account of poor ROI, and a stronger need to maintain positive cash flow. As the price per barrel climbs, the drilling and completions rate increases accordingly, and Operators begin developing and producing fields rapidly, particularly in the North American shale plays. The uptick in activity requires a very streamlined and almost ‘templatized’ process for supporting the producing wells. This includes the wellsite infrastructure.
However, despite all of the careful planning and optimization, there is one critical part of bringing a well online, that if overlooked, can wreak havoc on production schedules and forecasts. Although automation and controls, and SCADA integration represents the last 5% of the total infrastructure build plan, it is perhaps one of the most important parts of the process because it is the final step between idle equipment and producing wells.
How do automation and controls, and SCADA implementation impact well performance?
Most wellsites are in rather remote locations that makes manually monitoring well performance cost prohibitive for any Operator with more than say 100 wells. Imagine sending out field crews daily to visit every well to take readings from the gauges and sensors, and then waiting for the information to be transmitted to a central location before analyzing and making any decisions about production or maintenance. This would be a huge bottleneck when you scale up to hundreds or thousands of wells, and it would expose the E&P operator to significant HSE risk. What would happen if the pressure or temperature of a few wells began to fall or rise outside of the optimal performance range? The Operators would be faced with lower production volumes (impact on cash flow) or potentially worse, a blowout which destroys equipment and endangers lives and the environment.
Automation and controls at the wellsite allow for processes to be programmatic and managed remotely in an effort to optimize efficiency, reduce HSE risk and minimize delays in decision-making. For example, if a temperature sensor reading is above a certain threshold, a Programmable Logic Controller (PLC) could be installed to automatically shutdown the process which would circumvent damage to the equipment and prevent a potentially hazardous situation. Same can be said of gauges installed on tanks that can monitor oil, gas or wastewater levels and can be programmed to trigger an overflow alarm, or can even trigger a release valve to properly dispose of accumulated gas, for example. All of this automation at the wellsite makes it possible for the facility to safely bring hydrocarbons to the surface, and helps reduce manual labor and HSE-related incidents such as leaks. By introducing a SCADA system, you can remotely monitor several sites simultaneously where automation, controls and communications are established which gives much greater control over well interventions and scheduled maintenance. In turn, this allows an Operator to forecast scheduled shutdowns more effectively to help production accountants understand fluctuations in marketable volume.
Developing these automated processes requires foresight and early planning during the design and engineering phase of the expansion project so the automation and controls, and the SCADA system are properly configured and implemented. A qualified SCADA Integrator can help with process design, technology evaluation, feasibility studies, systems integration and can optimize the onboarding of new wells if they are given the opportunity to participate sooner, rather than later.
Said another way, wellsite automation and SCADA integration represents approximately 5% of the overall infrastructure project in terms of both time and budget, but it is the most critical part of the entire process because it is the difference between a producing well and an idle site. Until this last 5% of the project is fully commissioned, an Operator cannot efficiently bring the well online and would have limited ability to protect their multi-million dollar equipment investment from any number of operational hazards. Not to mention they would have no ability to remotely control the asset, or monitor the production which would make forecasting financial performance challenging.
Consult with a SCADA Integrator during the Drilling Phase
There are a number of advantages for the E&P Operator and for the EPC firm by working together with an experienced SCADA Integrator early in the scoping phase of a wellpad project. Outfitting the site with the appropriate controls that take into consideration:
Post-installation staff proficiency in a variety of controllers and platforms;
Technological advances and growth opportunities in process automation;
Project scheduling and delivery processes;
Integration(s) with existing systems such as SCADA, historians/data management solutions, production accounting packages, etc.;
Time and budget; and
Expected wellsite equipment performance and production volumes,
Is a process that takes very little upfront time investment to ensure the wells are commissioned and brought online according to plan.
A SCADA Integrator can also help the project team determine the system, and maybe the equipment, that best fits the asset, and should have qualified engineers available to assist with process design, FEED, estimating the delivery schedule, and a number of other pre-SOW criteria. They can help you estimate cost for not only the project itself, but also for the maintenance and support post-installation.
In project management certification courses, this last 5% of the project in which the overall success or failure hinges on the effective installation, testing and commissioning of the controls and SCADA system, is a critical milestone. It is considered the ‘Moment of Truth’ event; a make or break part of the entire workflow. It’s often recommended by project management professionals to use this moment as the starting point and work backward to outline the critical steps required for success.
Imagine what happens if any of your timelines before this final 5% slip and take longer than expected. The Integrator is likely to charge a premium if the Operator and EPC firm haven’t modified their delivery schedule to reflect these delays. However, if the Integrator is included in this process earlier, they can proactively help the team investigate alternatives that might reduce these delays through simultaneous development or modifications to the scope or equipment.
Lastly, a SCADA Integrator could also help you understand the tradeoffs and costs between maintaining a legacy system and replacing or upgrading the system at the time of the project. Just like with other hardware and software, parts and upgrades for controls and SCADA systems may become obsolete or pose significant operational losses in comparison with a replacement. The ability to have this discussion and an assessment of the business case for the two options gives the Oil Company time to initiate the change vs. being handcuffed by time constraints to an investment that will cost more money to maintain in the long run.