Oilfield production is the sector of exploration and production (E&P) businesses that operates after a well is drilled, completed, and the flow of oil, gas, and water has commenced. Within this part of operations, the general scope is to produce oil and gas at a profitable level while maintaining well production and integrity, and then separate and initially treat the individual components of the produced fluids for transport to markets around the globe. At every stage of this production process, accurate control and measurement play a key role in business operations. Often, measurement is considered the main focus at the transfer of ownership from an E&P company to a midstream company; however, before fluids ever reach this point, key measurements can play pivotal roles in upstream oil and gas production.
Reservoir and production engineers need to understand how a well is producing; accounts payable teams need to understand quantities produced for royalty payments; production and facility engineers need to rely on measurements to ensure equipment is operating properly and accurately; and accounting departments need to ensure royalties are accurately allocated to mineral rights and landowners. Making the right design and equipment selections can have a large impact on each of these focus areas for an operating company.
Initial measurements typically start with an allocation separator. This vessel is often used on a rotating basis at a facility to check production from multiple wells. It is usually a three-phase horizontal separator that separates fluid from one well into three different streams: oil, water, and gas. Fluids are sometimes combined downstream of this vessel and sent to a central facility for further processing. The main purpose is not proper fluid separation, but to measure and monitor the performance of a well and allocate how much fluid is produced from that well. These measurements are then used by reservoir engineers, accounting teams, and facility engineers for a number of purposes. Technology selection for the measurement can vary based on what is important to the operating company: accuracy, uptime, diagnostics, or price. Turbine meters have historically been a common flowmeter for liquid measurements and orifice plate differential flowmeters for gas measurement. However, advances in manufacturing, diagnostics, data availability, and the need for accuracy have driven many operators to use Coriolis flowmeters, electromagnetic flowmeters, and ultrasonic flowmeters in these applications. These electronic flowmeter technologies provide highly accurate measurement data, higher turndown ratios, onboard diagnostics to identify upsets and process challenges, and additional measured variables such as temperature, density, pressure, conductivity, and more.
For example, a Coriolis meter applied on the oil leg of a separator can accurately measure mass flow, volumetric flow, oil density, and oil temperature; identify solids buildup and gas breakout; determine oil and water ratios; and more. All of these variables can help engineers and operators better understand and troubleshoot their equipment and processes.
After allocation separation or bulk separation, most liquid products, such as oil and water, flow into large storage tanks at a central processing facility or tank battery. Level measurement is applied here to monitor the fluid in the tanks. The primary purpose is control; however, accurate and dynamic tank measurements help determine inventories and provide a check against upstream allocation vessels and downstream LACT skids. Instead of providing only overfill protection, magnetostrictive tank probes and guided-wave radar provide continuous level measurement of fluids in oil and water tanks. Because tank dimensions—and therefore tank volume—are relatively well defined and easy to calculate, these dynamic measurements allow for accurate inventory monitoring as a check against dynamic flow measurements. If tank volumes do not align with other dynamic flow measurements at the facility, operators can troubleshoot and identify issues before fluid is sold, gaining better control over lost and unaccounted-for product.
Improving measurement in allocation and tank measurement also enables better facility control. Most of these instruments were historically used only for process control: controlling levels, avoiding spills, and managing flow rates. Now, most instrumentation in a central processing facility is dual purpose—control and measurement—which gives operators much more control to remotely manage production, reduce truck rolls to the site, improve safety for operators and pumpers, and more accurately account for production volumes.
The final key measurement at a production facility occurs when fluids are sold and transported from the site. This part of measurement in oil and gas is well known and heavily influenced by American Petroleum Institute and American Gas Association standards. Standard technology selection, measurement skid design, and equipment selection are often determined by contract between the E&P company and the midstream company. Often, everything is required to be fully compliant with API or AGA measurement standards. As they have further upstream in the process, companies are moving to more electronic flowmeters with multivariable measurements, high-accuracy instruments, and diagnostic suites that identify measurement errors immediately instead of at the end of the month when closing out tickets.
Water transfer and sale from a processing facility have much less standardization in measurement equipment and practices; however, accurate measurement is still critical. Due to the volume of water being sold from newer, large, centralized production facilities, inaccurate measurement can have very high costs over the course of a month or year—up to millions or tens of millions of dollars. Operators are driving standardization efforts to improve contracts and measurement accuracy across the oilfield as the value and cost of water as a resource continue to increase.
Overall, measurement’s role in the oil and gas industry continues to expand as contracts become more aggressive, price volatility has major impacts on profitability, and operators look for better ways to optimize production. The biggest recent driver is the use of machine learning and artificial intelligence tools to gain competitive advantages. The common denominator is that all of these systems require data and measurements to derive actionable insights into the business. Fluid streams that were once measured only at final sale are now critical areas for process improvement, and additional data is required for optimization. Sensors measuring flow, pressure, temperature, level, quality, strain, vibration, and more are being applied throughout the field to feed these systems.