Water-in-oil content is an important parameter for the oil and gas production process, transportation and custody transfer. Water co-produced in oil and gas production is a by-product and waste. As an oilfield matures, water production often increases as a result of water injection for reservoir pressure maintenance. The increasing presence of water in production fluids can lead to capacity issues, which affect oil/gas/water multiphase separation and consequently the quality of oil and gas. The presence of water in an export crude oil or gas can therefore not only impact the sales value, but also lead to operational issues such as pipeline corrosion and hydrate formation.
In custody transfer and/or allocation, water-in-oil content must be determined and discounted as it is not a commodity, but a waste that must be further separated from oil and gas and safely disposed of. Thus, accurate measurement of water-in-oil (crude or condensate oil) is essential for the oil and gas industry. Inaccurate measurement could lead to production process problems, transportation issues, pipeline integrity concerns, and loss of revenue from the sales of commodity oil and/or gas. For fiscal or custody transfer, water-in-oil is usually low and is part of “Basic Sediment and Water (BS&W)”, a key quality parameter in crude oil sales.
For the oil and gas industry, water-in-oil content is also referred to as water cut. It is part of multiphase flow measurement for production monitoring, allocation and well testing. Knowing the proportions of oil, gas and water from individual wells helps maximise the overall production rate and ultimately the overall recovery of the oil and gas from a particular field.
“water-in-oil content must be determined and discounted as it is not a commodity, but a waste that must be further separated from oil and gas and safely disposed of”
Measurement of water-in-oil can be done by sampling and laboratory analysis using a number of standard methods. It can also be achieved using online water-in-oil measurement devices for which at least four techniques are known to have been commonly used.
Production, allocation, transportation and custody transfer
In oil and gas production, well fluids containing a mixture of oil, gas, water and solids, are brought to the surface, production separators are used to separate the mixture into gas, oil and water and solids phases. The separated gas may then be compressed, dehydrated and exported or may also be flared as an option. Separated oil may undergo a desalting process to reduce the salt content of the crude before export. Solids accumulated inside the separator are periodically removed, cleaned and discharged if this is permitted in an offshore environment. Water separated then goes through a treatment process where oil and solid contaminants are removed. The cleaned water is then either discharged or re-injected (for disposal or reservoir pressure maintenance) or reused for agriculture, irrigation or hydraulic fracturing operations purposes.
Production fluids can come from wells in the same oil and gas field, but they can also come from different fields owned by separate operating companies. Well testing using a test separator, as shown in the schematic diagram (Figure 1), is therefore periodically carried out to establish the rate of oil, gas and water that is produced by the individual wells. Knowing the rate and proportions of various phases in the individual wells allow for the overall production to be optimised, in the cases where well fluids from different operating companies are processed, it is essential that the total rate of oil, water and gas are calculated and “allocated” back correctly to the individual wells and their owners to ensure each obtains a fair share of the production fluids. Allocation is a process rooted in the need to distribute the costs, revenues and taxes among multiple players collaborating on field development and production of oil and gas.
When a well test is carried out, water-in-oil or water cut is measured for the oil stream exiting the separator oil outlet. Together with the rate of the water stream, one can work out the total water production rate from a specific well. Nowadays, with the advancement of multiphase flow measurement technologies, well testing is increasingly done using a multiphase measurement device which can measure the amount of water, oil and gas simultaneously without the use of a test separator.
When oil and gas is exported, a pipeline is used. Due to the density difference between water and oil, and between water and gas, water-inoil or water-in-gas can drop out and accumulate within certain parts of the pipeline, which can lead to corrosion problems. The presence of water-in-gas during transportation can also potentially lead to the formation of gas hydrate within the pipeline, under certain temperature and pressure conditions. Gas hydrate is essentially ice that contains natural gas which can potentially lead to a pipeline blockage, causing operational and safety issues. Knowing the level of water-in-oil or water moisture in gas can help determine the likelihood of corrosion taking place and / or gas hydrate formation inside the pipeline. It can also help determine the level of anti-hydrate formation chemicals that may be required to prevent gas hydrate formation or the scheduling of the pipeline inspection and maintenance regime.
As terms, custody transfer and fiscal metering are often used interchangeably. They refer to the transactions involving transporting oil and gas commodity from one operator (or owner) to another. These include the transferring of oil and gas between tanks and tankers, tankers and ships and other transactions. Custody transfer in oil and gas measurement is defined as a metering point (location) where oil or gas is being measured for sale from one party to another. For fiscal or custody transfer, water-in-oil must be measured accurately and then discounted.
Measurement methods and technologies
Water-in-oil can be measured using online technologies, as well as laboratory standard methods. Online technologies are increasingly used for fiscal, custody transfer and process operations in particular after the publication of the API MPMS TR 2570 / EI HM56 Technical Report in 2010, which is entitled “Continuous Online Measurements of Water Content in Petroleum (Crude Oil and Condensate)”. These online instruments offer many benefits in terms of cost saving, real time continuous water-in-oil information and increased productivity. Laboratory standard methods are also important and have been traditionally used to measure water-in-oil concentration. They are also used to calibrate and validate the performance of online water-in-oil measurement devices.
Laboratory standard methods
For fiscal, custody transfer and allocation, laboratory-based water-in-oil concentration measurement standard methods have played, and will continue to play, an important role. They are very well established and practiced by the oil and gas industry for decades. There are a number of standard methods, which include centrifuge-based, distillation-based and Karl Fischer titration-based.
All Karl Fischer methods are generally better and more accurate than distillation and centrifuge-based water-in-oil analysis methods. In general, the coulometric Karl Fischer method is better and more accurate than the volumetric Karl Fischer method. However, Karl Fischer
titration-based methods are affected by the presence of Mercaptan and sulphide (S- or H2S). Also, Karl Fischer titration methods require the use of expensive, hazardous chemical reagents and delicate glass pieces, and the reagents must be replenished continuously. In addition, routine cleaning of the laboratory equipment parts is labor intensive and time consuming.
Online water-in-oil measurement
Most of the online water-in-oil measurement instruments that are commercially available are designed and constructed based on four techniques: capacitance, density, infrared absorption, and microwave.
Capacitance-based technology probably has the longest history, commercially. It is a simple and well proven technology, with a low cost. As a method, it works well when the oil is the continuous phase and it is also relatively insensitive to water salinity. Most of the systems on the market at present can measure low percentages of water-in-oil accurately.
Density-based water-in-oil measurement technologies
Density-based water-in-oil measurement technologies may include Coriolis, gamma-ray or x-ray, and are popular for multiphase flow measurement. Whilst they can provide additional information such as flow, viscosity and density in the case of Coriolis meters, these systems are generally affected by the presence of gas bubbles and solid particles. They are also sensitive to variations in process conditions. Overall, density-based systems have large uncertainty for measuring lower level water-in-oil concentration.
Infrared absorption-based technology
Infrared absorption-based technology covers the entire water-in-oil measurement range. Although it is also unaffected by changes in density, salinity or entrained gas, it is not particularly accurate at a lower water-in-oil concentration range.
Microwave-based technology is more accurate for lower water-in-oil concentration range applications, however its high initial cost and sensitivity to salinity must be considered, despite its robustness.
Operational, safety, financial and environmental impact
For fiscal or custody transfer, inaccurate measurement of water-in-oil will directly impact on revenue. For example, oil tankers can typically transport between 500,000 to four million barrels of crude oil. For a tanker with a capacity of one million barrels of oil, a water-in-oil content of 0.5% means that as much as 5,000 barrels of water could be present in the tanker. At $50 per barrel of oil, this means a potential financial exposure of $250,000.
Around the world, some 90 million barrels of crude oil are produced worldwide daily, and in pipeline transportation and allocation, water-in-oil content could, in reality, be much higher than 0.5%. Thus, any inaccurate water-in-oil measurement could have a significant impact financially to all the parties involved, which include production partners, oil and gas commodity sellers and buyers.
“accurately monitoring water-in-oil reduces the risk of water-led corrosion, and in turn corrosion induced pipeline leaking – or worse – pipeline rupturing”
For oil and gas transportation using pipelines, pipeline integrity is paramount for the operators. Corrosion-related pipeline incidents can lead to catastrophic consequences. For example, in 2000 the Carlsbad Pipeline Explosion in New Mexico which killed 12 people, was caused by internal corrosion to a 30-inch natural gas pipeline. Also, in 2006 the Prudhoe Bay Oil Spill in Alaska, in which some 267,000 gallons of crude oil leaked from the pipeline, was linked to corrosion. By measuring water-in-oil (or condensate) and moisture in gas accurately, and making sure that the concentration is within the specification set by the pipeline operators, the risk of water-led corrosion is reduced, and in turn corrosion induced pipeline leaking, or worse, pipeline rupturing.
For oil and gas production, inaccurate water-in-oil measurement could lead to an unoptimised process and a reduced production rate. Wells that produce fluids containing a large amount of produced water may be choked back and even shut in to allow more to be produced from those that contain less water. In production optimisation, it is also important to measure the water content in the separator oil outlet for process control purposes. Accurate measurement here would provide the information required for the correct dosing of production chemicals, such as demulsifier and defoamant, to assist the multiphase separation. It would also enable the correct setting of the oil and water interface level inside the multiphase separator for optimised operation, as well as ensuring the water content level in the oil is within the export quality specification.
Any pipeline leakage of oil and gas resulting from pipeline corrosion is obviously bad for the environment. Inaccurate water-in-oil measurement could also affect the performance of produced water treatment systems or refinery wastewater treatment systems, which then impact on the quality of treated water for discharge. The discharge of produced water or refinery wastewater is strictly regulated.
Trends and needs
Traditionally water-in-oil determination in custody transfer and allocation has been done by sampling and laboratory analysis. This process is laborious and time consuming. Online continuous water-in-oil measurement provides real time determination of water in a flowing hydrocarbon stream. It offers many advantages, and can potentially improve system efficiency, operational safety and streamlining system operations if they can work reliably and accurately. Currently the American Petroleum Institute (API) has an active working group developing a standard for online measurement of water content in petroleum and petroleum productions, which is a clear indication of the importance of the subject to the industry.
Online continuous water-in-oil measurement devices have been available on the market for a long time. However, few studies have been conducted in which these online water-cut measurement devices are tested and evaluated independently and in a collective manner. The only known tests were conducted back in the 1990s, in which commercially available devices then were tested using a specially designed and developed flow loop. Since then, measurement technologies have advanced and been improved, and new instruments have also been developed. Therefore, there is a need to test and evaluate such devices again.
In 2019, Pipeline Research Council International (PRCI) commissioned such a project. In the project, a closed loop performance test was planned to measure the error between known water content and the water content measured by the different water cut meter technologies. The tests would cover water-in-oil content range for both custody transfer and allocation / process applications. Results obtained from the project were to be shared by PRCI members and were also expected to provide input into the API standard development. It is understood that the project has now been executed, however, no results have been published to date.
There also seems to be a technology gap in online measurement of very low water content in gas condensate or crude oil applications in the parts per million (ppm) range. For gas and gas condensate production, separated gas and condensate streams are often recombined and exported. Thus, water content in condensate oil will affect the overall water moisture level in the gas / condensate export line. In the United States, the accepted maximum water presence in gas is 7 lbs/MMSCF, or 147 ppm whilst in Canada, this is 4 lbs/MMSCF, or 84 ppm. Both capacitance and microwave-based technologies have been explored for ppm range of water-in-condensate applications, but there has been limited success.
Measurement of water-in-oil is crucially important for the oil and gas industry in relation to fiscal or custody transfer, production and production allocation, and pipeline transportation. Inaccurate water-in-oil measurement can directly impact operators’ finance, production operations, pipeline integrity and safety and the environment.
For custody transfer and allocation, measurement is often carried out by sampling and laboratory analysis, for which standard measurement methods based on using centrifuge, distillation or Karl Fischer are available. However, there is an increasing demand for online measurement devices for which the oil and gas industry continues to work together to come up with standard practices and guidelines.
For oil and gas production operations, online water-in-oil devices are already widely used as part of multiphase flow measurement. The vast majority of water-in-oil devices use one of four measurement technologies, including: capacitance, density, infrared absorption or microwave. For online water-in-oil measurement, there is a need to independently test and evaluate instruments available on the market. There also seems to be a technology gap in accurately measuring the ppm range of water-in-condensate oil for gas and gas condensate production and pipeline transportation applications.