Measuring difficult flow streams and more accurate flow control can improve oil and gas well profitability

Instrumentation largely consists of flow, level, pressure, temperature and other field devices and associated controls to maintain process safety and enhance productivity. In some applications, utilizing more accurate instrumentation and control strategies that incorporate difficult measurements have the potential to measurably improve profitability, sustainability and process safety. 

One such application is the utilization of more accurate flowmeters to control chemical injection flows in oil and gas wells. In addition, modifying the control strategy to incorporate a mass flowmeter that measures well production can result in significant savings as compared to controlling chemical injection flows at fixed flow rates. Further, drilling rig safety and productivity can be enhanced by adding a mass flowmeter to measure drilling mud and related flow streams. Similar benefits can be achieved by applying the methodology presented herein to other processes. 

Drilling operation

When drilling wells, mud is pumped down to the wellbore and loose material is brought up to the surface where some of its components, such as gas and solids, are removed. The remaining material is accumulated in a mud tank where chemicals and other materials are added to modify its characteristics, such as density and viscosity, before pumping the modified mud down into the well. 

If the well pressure becomes higher than the wellbore pressure, oil, gas and water can rush into the wellbore, and create a well kick. This potentially dangerous situation can result in a sudden change in drilling rate, pressure fluctuations and drilling mud flow changes. If not mitigated, a well kick can develop into a blowout, which is an uncontrolled release of oil or gas. Well safety can be enhanced by installing a drilling mud mass flowmeter on the drilling rig to measure the flow of material coming out of the well. This measurement can provide a warning of a potential well kick and enable the operator to take timely action to prevent the impending kick and potential blowout, thus tending to decrease drilling rig downtime. For safety purposes, the required pressure rating of instrumentation in piping potentially subject to well kicks is typically 5,000 psig (345 bar) but can be higher or lower, depending on the well. 

Well operation mass flow measurement

After the drilling rig is removed and production starts, the well produces oil, gas and water that are separated and processed further, or disposed of. Small amounts of chemicals are injected into wells at strategic locations to increase production, reduce corrosion, reduce foaming, enhance viscosity, separate gas/oil/water and promote other processes to improve profitability, improve productivity and protect equipment. The actual flow rates of the injected chemicals are determined using control strategies that can have a significant impact on profitability, production, chemical consumption and sustainability. Innovative and highly accurate flowmeters can be integrated into chemical injection control system designs to provide significant chemical savings and enhanced production. 

The process control objective is to maintain the desired mass concentration of each injection chemical at each strategic location in the well. Proprietary information can be used to determine the concentration for each chemical and location, from which individual chemical injection flow rates can be calculated and maintained during operation, subject to operator adjustment. The unmeasured production flow can vary significantly during operation. The control strategy of maintaining fixed chemical injection flow rates in conjunction with significant uncertainty surrounding the actual production mass flow rate can result in overfeeding or underfeeding chemicals, both having potentially significant effects on well operation. 

For example, if the actual production mass flow is 10 percent higher than its assumed flow, the injection chemical concentrations at strategic locations will be approximately 10 percent lower than their desired amounts, adversely affecting the productivity of the well by a potentially large amount, while not adequately protecting the well and its equipment. 

Conversely, if the actual production mass flow is 10% lower than the assumed mass flow, approximately 10% more chemicals are injected, which can adversely affect the productivity of the well and waste 105,120 liters of chemicals annually (10% x 2 lpm x 60 min/hour x 8,760 hours/year) when the total flow of chemicals is 2 liters per minute (lpm). If the average weighted chemical cost is USD $1.00 per liter, operating in this manner wastes over USD $100,000 of chemicals annually, aside from making the process less productive and less sustainable. Spending (say) USD $50,000 for a flowmeter to measure the production mass flow and ratio controls to adjust the chemical injection controller setpoints in proportion to the actual measured production mass flow, would result in a simple payback of approximately 6 months. Productivity increases realized by injecting the desired amount of chemicals would further reduce payback time. Projects such as this, with potential payback measured in months, should be aggressively investigated for viability in both new and existing wells. 

It should be noted that a given percentage error in the production mass flow causes a corresponding equal and opposite percentage error in the mass concentration of the chemicals in the production flow. In this example, a 10% lower (higher) production mass flow resulted in 10% higher (lower) mass concentrations. 

Neither scenario is good, but their stark contrast illustrates the potential economic, protection and sustainability improvements that can be realized using ratio controls that inject chemicals as a percentage of the measured production mass flow, instead injecting a fixed flow. In these scenarios, a ratio control strategy would either save approximately USD $100,000 or provide necessary equipment protection that was lacking, respectively. Between these scenarios, such as when the well is (unknowingly) operated closer to the desired mass concentration of each injection chemical in each location, less chemicals are saved or additional equipment protection is provided, respectively. 

Drilling mud mass flow measurement

Measuring drilling mud flow on drilling rigs is problematic because drilling mud is abrasive and contains large and varying amounts of solids, dirt, rocks, gas and liquids with varying composition, density, conductivity, viscosity, and other physical properties. During operation, the drilling mud can be:

• A combination of liquid, gas and solids.
• Subject to large density changes, but this can be mitigated by installing an independent density meter. 
• Thixotropic, where its viscosity changes significantly under different operating conditions. 
• Electrically conductive or non-conductive.
• Operating in the laminar, transitional and turbulent flow regimes. 

Measuring the mass flow of drilling mud presents various flowmeter technology constraints including:

• Coriolis mass flowmeters are subject to erosion, coating and trapping large cuttings aside from being limited in size. 
• Differential pressure flowmeter primaries exhibit poor accuracy because their operation can be linear, unknown or quadratic in the different flow regimes, respectively. 

o Measurement equations depend on density, viscosity and Reynolds number, which is itself dependent on flow, density and viscosity.

• Magnetic flowmeters cannot measure non-conductive liquids, and liners are subject to wear. 
• Positive displacement flowmeters are not appropriate to measure liquids with rocks, sand and other debris. 
• Ultrasonic flowmeters are affected by varying density, not accurate in all flow regimes, affected by varying speed of sound, and often not reliable due to poor acoustic conductivity. 
• Variable area flowmeters have moving parts, are subject to plugging, and are not accurate in all flow regimes. 
• Vortex shedding flowmeters cease to operate in the laminar and transitional flow regimes. 

As a practical matter, drilling mud flow is often measured using Coriolis mass flowmeters, despite their shortcomings. However, a proprietary differential pressure drilling mud mass flowmeter is available that claims to measure with an accuracy of approximately 1% of rate using a patented energy correlation technique that is independent of viscosity. However, each 1% fluid density increase (decrease) will cause the flowmeter to read approximately 0.50% lower (higher) than actual, so continuous density measurement is required to achieve the stated mass flow accuracy. 

Variations of mud flowmeter technology can likewise measure drilling rig streams such as mud blending, mud shipment and pumping operations to improve mud formulation, ensure accurate custody transfer and assess equipment health, respectively. These measurements can provide significant value by enabling drilling rigs to operate with fewer upsets and less downtime, while increasing safety and reducing the number and severity of expensive and time-consuming repairs. 

For example, mud with incorrect density pumped into the well can be detected quickly to avoid potentially spending multiple non-productive days flushing the well. Reducing downtime by only 1% would increase drilling rig availability by almost four days per year. Drilling rig rentals are approximately USD $250,000 per day onshore and USD $750,000 per day offshore, so the economic value of these four additional drilling days is approximately USD $1,000,000 and USD $3,000,000, respectively. Therefore, investing (say) USD $500,000 for these flowmeters would result in simple paybacks of 6 and 2 months, respectively, suggesting that their purchase and installation should be aggressively pursued. 

Production mass flow measurement

After the drilling rig is removed, measuring the production mass flow is similarly challenging because it can be:

• Partially gaseous and may contain some solids.
• Subject to large density changes, but this can be mitigated by installing an independent density meter.
• Subject to significant viscosity changes under different operating conditions. 
• Electrically conductive or non-conductive.
• Operating in the laminar, transitional or turbulent flow regimes.

Given the similarity of these challenges, it is not surprising that a variation of the drilling mud flowmeter can be permanently installed to measure the production mass flow stream to enable faster diagnosis of operating issues and increase production. 

Injection chemical flow measurement

Practical process control strategies not requiring production flow measurements were developed to manipulate the chemical injection flows in operating wells. These include:

• Manual adjustment of valves, pump strokes and pump motor variable speed drives.
• Self-contained chemical injection control valves (CICV).
• Measuring and controlling injection flows.   

o Closed loop feedback flow control with a flowmeter, flow controller and control valve (or variable speed drive) that maintains the desired flow rate of each chemical.

o On/off control that opens and closes control valves for varying periods of time to achieve the desired total flow of each chemical.

There is significant uncertainty surrounding the actual production mass flow rate, so control strategies such as these that manually set the chemical injection flows at fixed values can have profound effects on well profitability and sustainability. 

The typical flow accuracies of these flow control strategies are approximately ±20% (anecdotal), ±5%, and ±1% of rate, respectively. Note that these are the accuracies with which the flow is controlled, and not the accuracy of the process control objective, which is maintaining the desired mass concentration of each injection chemical at each strategic location in the well. 

Improving flow measurement accuracy can reduce the unnecessary addition of chemicals and increase profitability. For example, the flow settings for systems with accuracies of ±20%, ±5% and ±1% of rate would be 125, 105.3 and 101 cc/min, respectively, to ensure that the chemical flow does not fall below the desired (say) 100 cc/min. More accurate flow measurement enables the flow to be controlled closer to the set flow rate and potentially reduce chemical consumption, reduce chemical costs and increase sustainability. These chemical savings are largely in addition to the above cited savings associated with controlling the chemical injection flows as ratios to the production mass flow. 

For example, two flow control loops using actual flowmeters with 2.5% and 0.3% rate accuracy would require setpoints of 102.5 and 100.3 cc/min respectively, to ensure a flow of at least 100 cc/min. The potential for chemical savings due to increased flowmeter accuracy is approximately the difference between the setpoints, or 2.20 cc/min. The following table shows the potential chemical and cost savings associated with using the more accurate flowmeter. These savings can be used to justify the additional cost (if any) to purchase the more accurate flowmeter with the potential to reduce chemical consumption and increase sustainability.

The following table shows that similar chemical injection flowmeters that typically operate at higher flow rates exhibit similar potential savings when comparing flowmeters with 0.5% and 0.3% of rate accuracy.

Purchasing a more accurate flowmeter in a new installation or when a flowmeter needs to be replaced, can potentially save chemicals, reduce costs and make the process more sustainable. For example, more accurate flowmeters measuring 60 cc/min and 600 cc/min of chemicals costing USD $1.00 per liter can potentially save USD $694 and $631 per year, respectively (from tables). Paying a (say) USD $500 premium for a more accurate flowmeter is attractive because its simple payback is under 1.5 years. Shorter potential paybacks can occur when operating at higher flow rates or when flowing more expensive chemicals. 

Importantly, potential chemical savings can be multiples of the values presented in the previous two tables, such as when flow control loops are installed in unmeasured chemical injection systems or in lieu of self-contained chemical injection control valves (CICV). 

Interestingly, despite significant potential savings, injection flowmeter specifications sometimes do not specify flowmeter accuracy. When this is the case, a misapplied and highly inaccurate flowmeter would be acceptable, despite significant economic penalties that would likely occur if it was purchased, installed, and operated. 

Positive displacement gear flowmeters and Coriolis mass flowmeters are typically used in this service. However, positive displacement gear flowmeters with 0.3% of rate accuracy are typically more accurate than Coriolis mass flowmeters after Coriolis mass flowmeter pressure drop, zero stability and actual flow rates are considered. 

Conclusion

Drilling rig safety and productivity can be significantly enhanced by installing flowmeters to measure drilling mud and related flow streams. 

Chemical injection feed rates are traditionally maintained at fixed values until operating conditions warrant change. Therefore, the process control objective of maintaining the desired mass concentration of each injection chemical at each strategic location is compromised because the production flow can vary during operation. Installing a production mass flow measurement and associated controls can enable the control system to automatically ratio the injection chemical flows to the production mass flow to better address the control objective. The chemical and economic savings associated with full implantation can be substantial. 

Superior control strategies and more accurate control of chemicals injected into wells can significantly improve their profitability, their sustainability and better protect equipment. While savings are typically lower than those associated with installing a production mass flowmeter, they are nonetheless significant and usually worthy of implementation, especially in new chemical injection systems, and sometimes in existing systems, depending on the size and anticipated life of the well.