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Wednesday - Thursday, 21-22 February, 2018
Houston, Texas


Technical Program

The Forum's focus shifts each year, as necessary, to address the issues of greatest interest to the industry. The forum will cover:

My update would include items such as:

  1. Overview of GOM Activity
  2. Production and Measurement Statistics
  3. New policies/guidelines related to oil and gas measurement

The starting point for understanding multiphase flow in pipes is clearly the prediction of flow pattern. My Keynote lecture will describe the flow patterns that are encountered, and why accurate prediction is so important. I will trace the history of flow pattern prediction, including the early empirical maps, the transition to mechanistic modeling, and finally to unified modeling. Unified models are the future for more accurate prediction of flow patterns. The unified flow pattern part of my lecture will be taken from part of Chapter 9 of the recent textbook “Applied Multiphase Flow in Pipes and Flow Assurance” published in 2017 by the Society of Petroleum Engineers. This is not a simple topic and I will be challenged to make it understandable and exciting. However, I have been doing this for almost 50 years and am confident that the audience will fully appreciate my presentation.

API MPMS Ch. 20.1 - Production Measurement and Allocation Systems is currently being updated. The goal of the document is to establish a framework to develop, implement and manage upstream production measurement and allocation systems. The updated document will refer to the combined application of fluid measurement (flow metering, tank gauging, fluid quality and applied phase behavior) and allocation methodology for the determination of allocated hydrocarbon and water quantities. The intent of this document is to provide operators with a consistent and transparent approach for determining accurate and equitable production allocations.

The focus of the presentation is to provide an overview of Ch. 20.1, including discussion on each of the standard’s major sections

The 2017 publication of API MPMS Ch. 20.5 provides the industry with a standard that establishes a framework to consistently and transparently conduct and apply production well testing for well rate determination in measurement and allocation. The standard addresses production well test operations, calculations, and the proration of results for use in allocation, along with the application of well flow modeling and virtual flow metering in measurement and allocation. The focus of the presentation is to provide an overview of Ch. 20.5, including discussion on each of the standard’s major sections.

The roles of control and planning in any organization typically end up in a confrontation largely due to the people responsible for the functions. Today we are capable of generating an unfathomable volume of data covering every aspect of our business. This offers the opportunity to achieve new levels of sophistication, efficiency and technology across a wide spectrum of our industry. Whether this happens depends less on the data and more on the individuals charged with utilizing it. In this talk, I will offer my thoughts and observations on this relationship based on 45 years in the oil and gas industry.

The revolution in oil production from shale has placed much more strenuous as well as new demands upon several sectors of the petroleum industry especially in the Permian basin. Multiphase Meters are now tasked with metering wellhead production that may change by orders of magnitude in rate and over the full 100% range of fluid fractions, possibly including a need to monitor solids and fluid salinity. Unconventional single well life-cycle may see production from high liquids flow back, to free flowing wet gas, through artificial gas lift, including annular flow, and various “unstable” flow regimes such as churn, and slug flow, to finally low rate pulsing liquid dominated flow, lifted by sucker rod pumps.

Further, a new business sector has emerged, referred to as “midstream”, which requires sourcing, Re-Use, handling, storing, treating, blending and quality control for Fracking Operations, the millions of barrels/day of produced water required for continued development of new wells. The burdens upon the production facilities to separate the wellhead production streams have led to speculation that the produced water could potentially be very variable in salinity and may be multiphase in nature, and thus not readily managed by the current Mag meter methods

Traditional methods of Multiphase metering have relied upon correlations derived from testing which prove to be valid over relatively narrow production flow ranges.

We have designed and are testing a very different approach to Multiphase metering which would allow application of a single properly sized meter to operate acceptably over the full life cycles of unconventional shale production. Two decades of industry sponsored research & testing has clearly pointed out the importance of the embedded dispersed flow components for the overall properties of a multiphase stream. Our prototype multiphase meter uses several levels of mechanistic models of electromagnetic response as seen by arrays of microwave sensors (i.e. , Texaco Starcut™) to particle scattering, and mechanistic models of the effects of flow perturbation on dispersed flow dynamics (i.e. , TUSTP: U. Tulsa / Chevron) . High speed signal processing allows estimations of particle velocities within the meter to achieve automatic calibration for both composition and flow rates. Those actions are combined within a recursive processing scheme which is adaptive to constantly changing production using Kalman Filtering and Bayesian methods. The above would be the first example of an Artificial Intelligence operated Multiphase Meter intended to support unconventional production

Early stage results will be provided.

My update would include items such as:

  1. Overview of GOM Activity
  2. Production and Measurement Statistics
  3. New policies/guidelines related to oil and gas measurement

Pressure and rate transient data provide a means to characterize both the well geometry and the well drainage volume. Well parameters of interest include skin components (altered near wellbore permeability, limited entry, natural or hydraulic fracture stimulation), and completion geometry (productive horizontal well length, natural or hydraulic fracture half-length and conductivity). Reservoir parameters of interest include permeability (vertical and lateral principle permeability values), heterogeneity (contrast and geometry of mobility-thickness-compressibility regions or flow units, natural fractures), drainage limits (structural or stratigraphic limits or compartmentalization, gas cap or aquifer presence, interwell interference), and pore pressure.

Coupled with well rates (gas, oil, and water injection or production), ongoing downhole pressure measurement not only enables potential quantification of the above-mentioned parameters, but also evidence of changes in well and reservoir parameters over time. Changing well parameters include near-wellbore permeability loss, hydraulic fracture conductivity loss and/or geometry changes, and change in horizontal well productivity length. Changing reservoir parameters may include fluid leakage across faults or bed boundaries, evidence of compaction as loss of permeability-thickness, pressure dependent permeability, multiphase flow, and pore pressure.

This paper compiles cases showing the value for continuous pressure and rate monitoring in understanding well and reservoir behaviors that change with time. Examples include offshore oil, tight gas, and shale gas reservoirs. Insights gained from these examples provide valuable input for integrated static and dynamic reservoir characterization and simulation, and enable identification of the need for well remediation and improvements in well completion designs for future wells. Key for future value will be interpretation automation that translates data into parameters useful for data analytics.

All multiphase meters require accurate fluid properties as part of their PVT configuration This is generally done using pressure and temperature dependent look-up tables or Black Oil Models. When using look-up tables, an eternal Equation of State (EoS) software package has been integrated into the MPM meter flow computer the software package in question is known as Multiflash and is produced by KBC Advanced Technologies.

During the software selection process, the performance of a number of EoS software packages has been reviewed by TechnipFMC. It has been shown that there may be a large variation in the prediction of the fluid properties by different software for the same fluid. The impact of such uncertainties will be assessed through a sensitivity analysis using real field data. A rigorous analysis will be performed to isolate the various contributions to the total multiphase meter uncertainty that derive from modelling the fluid and its physical properties. For each one, a quantitative estimate and a practical recipe to minimize and control its impact on the uncertainty of the measurement shall be provided.

Using the embedded PVT model and Multiflash software as a basis, the multiphase meter is also able to perform a number of other useful calculations. Firstly, the PVT configuration can be corrected for the presence of water vapor. This information can be used as a method of in-situ verification towards the measured water fraction at operating conditions. The meter can then output dry gas and water vapor flow rates whilst accurately predicting the water condensation behavior at standards conditions. Secondly, the meter can make composition-based calculations of other important configuration parameters such as permittivity. This permits real-time corrections to the PVT configuration for the presence of components such as H2S, CO2 and indeed water vapor at operating conditions. Thirdly, the meter can be configured with a full multi-stage process flash to standard conditions taking into account up to five separation stages. This enables a more accurate conversion to standard conditions and allows the output of calculated flow rates at individual separator stages. A sensitivity analysis will be provide using real field data for each of these three cases to demonstrate the significant impact of configuring the multiphase meter in this way.

The embedded Multiflash software allows the meter to be configured with the GERG-2008 equation of state model which provides superior predictions of gas properties. The impact of using this model shall be examined for the specific case of ultra0high-GVF applications.

The multiphase meter is further able to accept live inputs from reservoir gauges, downstream separators and chemical injection flow meters such that these parameters can be taken into account in calculating the fluid properties needed by the meter. The impact of this is that the ‘reach’ of the multiphase meter is expanded beyond its traditional operating range.

The added value of basing the MPM meter calculations on Multiflash shall be detailed with a focus on the PVT uncertainties which have driven this approach, why multiphase meter verification becomes more efficient, and how such functionality can be used to improve the overall performance of hydrocarbon allocation systems.

Over the last decade North American gas supplies have changed substantially becoming richer, this has brought the Hydro Carbon Dew Point level much closer to normal operational conditions. These changes can be reflected in changes made to equations of state such as AGA 8, which has been recently updated to allow for the expansion of the compositional ranges.

We will discuss the effects of Hydro Carbon Dew Point (HCDP) on measurement accuracy. We will look at multiple factors that affect uncertainty such as proper meter operation, maintaining fluid in a gaseous state, gas sampling and handling of samples after they are obtained. Several case studies will be carried out on several wells in two gas fields. All of these factors and more contribute to increased uncertainty when measuring gas close or in the critical area.

Production metering is one of the essential measurements that is performed in the field. Kashagan is a giant oil field, which has a set of challenges to tackle in order to implement production flow rate measurement. These challenges are: high pressure and high temperature environment, high H2S content, harsh weather conditions and most importantly unmanned production islands. To overcome all these challenges non-intrusive technology is required, which is able accomplishing multitude of tasks with minimum intervention.

Multiphase flow in well conduits, e.g. production tubing, tubing head and flow line, is most likely inevitable phenomenon during whole production life of any oil field. Kashagan is not an exception.

The technology that addresses the challenges in Kashagan field is MPFM. After performing flow loop tests in Norway and getting approval from the State Authorities for production reporting using MPFM, unmanned satellite production islands had been equipped with MPFMs. There is one MPFM serving a group of wells installed on one of the islands, and some of the other islands have a MPFM installed on each well.

This paper will discuss NCOC N.V. and Schlumberger experience with this technology at Kashagan conditions. It will also discuss challenges of having MPFM upstream of production choke manifold versus downstream choke manifold and defining PVT model around bubble point pressure. The paper will also describe the methods of MPFM data validation, both by the Operator and the manufacturer. Finally, the paper will touch on the impact of MPFM technology on production allocation.

Deep water and heavy oil assets can produce difficult to handle oil/water/gas dispersions, e.g., emulsions, foams, and mousses. Such dispersions seem to characterize new fields as they become available in US (Gulf of Mexico) and other countries such as Venezuela, Brazil, Angola, Nigeria and China. Also, better characterization of oil-water mixture and separation properties are needed to determine in advance and optimize the proper chemicals and equipment needed for an oil spill cleanup. It is becoming increasingly important to investigate the emulsion and foam forming tendencies of oil field fluids and evaluate the effect of chemical additives in order to design appropriate facilities, because such dispersions can cause tremendous problems in production, transportation and processing. The Dispersion Characterization Rig (DCR) is a laboratory tool to help in characterizing the flow and separation behavior of fluids and the complex dispersions that are produced in the field.

A state-of-te-art, Portable Dispersion Characterization Rig (P_DCR) is used to investigate the effect of nanoparticles on oil-water emulsion formation and stabilization. The objective of this study is to investigate the separation kinetics of oil-water emulsions stabilized by spherical silica nanoparticles and its dependence on solid particle concentration, wettability, initial dispersion phase, water-cut, and shearing time. Mineral oil and distilled water are used as the test fluids and separation profiles are obtained from the experiments using a sophisticated software. Spherical silica nanoparticles of average primary particle size of 20 nm were selected as the emulsifying agent, since silica is commonly found in the produced fluids.

In one series of experiments the emulsions were prepared with intermediate-wet nanoparticles. Both simple water-in-oil(W/O), as well as multiple oil-in-water-in-oil(O/W/O) emulsions were observed. Faster separation occurred when the particles were initially dispersed in oil. Increased nanoparticle concentration, as well as shearing time typically resulted in slower emulsion separation rates.

Another series of experiments was performed with hydrophobic and hydrophilic nanoparticles. Very fast separation rates were observed when using hydrophilic silica nanoparticles and 25% water-cut regardless of solid concentration. However, when the water-cut was increased to 50% and 75% very stable emulsions were produced. Emulsions prepared using hydrophobic particles were the most stable across all water –cuts. For the case of 25% water-cut, no water coalescence was observed for a wide range of oil0wet nanoparticle concentrations. Oil creaming was promoted as the concentration of solids decreased, and the emulsions remained oil continuous and highly resistant to water coalescence even for very low solid concentration (100 ppm), resulting in a dispersed phase volume fraction as high as 93%. The experimental results of the study verify that the presence of nanoparticles, even at low concentrations, can significantly decrease separation rates of oil and water emulsions.

Due to diminishing conventional oil reserves and the need to secure future energy supplies to a rising world population, the exploitation of elevated temperature and pressure oils is on the increase. The industry is now going to extreme depths in various regions of the world in pursuit of new oil & gas reserves. These demanding environments present numerous technical challenges to the industry. As the development of these challenging reserves grows, so too will the requirement for accurate flow measurement of elevated temperature and pressure fluids.

One such challenge is that the temperature and pressure of produced oil from a reservoir can differ considerably from standard calibration laboratory conditions. The standard practice for calibrating flow meters for the oil & gas industry has been to match the fluid viscosity and, if possible, the fluid temperature and pressure. However, matching all parameters is seldom possible due to the limitations set by the calibration facilities. As such, the parameter that is most often matched is the fluid viscosity.

A limitation of the above approach is that temperature and pressure variations are known to influence properties, other than fluid viscosity, that may also be critical to the overall measurement uncertainty.

In Issue 9.2 of its Guidance Notes for Petroleum Measurement under the Petroleum (Production) Regulations 2014, The UK Oil & Gas Authority (OGA) have stipulated that temperature and pressure compensation applied to any flow meter between its calibration conditions and its operating conditions must be “agreed in advance with DECC” and must be “traceable and auditable”.

Although there has been some research into the performance of flow meters at elevated viscosities, temperature and pressure, only a small amount of independent and traceable data exist on certain meter types and diameters. It is not possible to extrapolate the flow meter performance with little or no measurement data and subsequently claim a performance for the device at a different condition.

To address this, NEL have built and commissioned a fully accredited elevated pressure and temperature (EPAT) liquid flow facility. This facility will be used to investigate the performance of flow meters at elevated pressures and temperatures. It also allows for standard commercial calibrations to be completed close to service conditions. This work will provide traceable data on the performance of Coriolis flow meters when operated at elevated pressures and temperatures.

This paper will present details on the importance of calibrating at service conditions. Data for a Coriolis meter calibrated at elevated pressures and temperatures wills be presented. As included will be the calibration of Coriolis meters at a range of viscosities (up to 1000 cP) and associated Reynolds Numbers.

The paper will present examples of temperature, pressure, viscosity and Reynolds number effects on Coriolis flow meters. It will highlight the current practice of calibrating close to service conditions. In the North Sea, current practice is to send flowmeters to a calibration laboratory for re-calibration. Historically the laboratory would calibrate at close to ambient temperature and approximately 2 bar. Viscosity would be matched if possible using a substitute fluid. NEL’s work has highlighted the issues with this procedure and will demonstrate example data from their latest facility, the Elevated Pressure & Temperature (EPAT) oil flow facility.

Determination of water breakthrough, or a change in water gas ratio (WGR), of a gas well is a key challenge in deep water environments. Commingled flow from different wells into a common flowline can make back allocation of individual well rates challenging. In addition, identifying the “bad actor” helps in avoidance of issues such as hydrate formation and liquid surges. The correlation between temperature and water breakthrough has been known for many years but not fully understood. Under the right conditions in gas wells, a correlation has been established and extended to determine water breakthrough from temperature drop, pressure drop and gas molecular weight. This correlation to detect water breakthrough has been implemented in a virtual flow meter (VFM) in a transient real-time system and is presented in this paper.

Accurate flow measurement in heavy oils (below a Reynolds number of 2 x 10exp4) is extremely difficult using traditional flow measurement technology. The fluids tend to be highly viscous (>100 cSt), and cause an increase in frictional losses as Reynolds number decreases. The flow can also exhibit a variety of forms depending on the Reynolds number. For Reynolds numbers above 4 x 10exp3, the flow is generally considered turbulent; below 2 x 10exp3, the flow becomes laminar and in between these limits lies the transitional region characterized by dynamic and unpredictable mixtures of both laminar and turbulent flow.

Flow measurement of heavy oils using traditional differential pressure meters has been shown to have significant problems particularly in determining an accurate discharge coefficient and representative density to use in the calculation of mass flowrate. Due to the increase in frictional forces through the meter, typically caused by an increased fluid viscosity, the discharge coefficient is non-linear and reduces dramatically over a small Reynolds number region. Therefore, if the Reynolds number is not accurately known then potentially significant errors in flow measurement can be introduced (up to 40%).

A new method has been created based on differential pressure technology that can remove these errors by providing the Reynolds number in real-time and hence a corrected discharge coefficient. Furthermore, the inclusion of additional technology can also provide a calculation of the density and the viscosity of the fluid making it a 3-in-1 measurement solution. This is one for the first measurement techniques independent of operating Reynolds number making it ideal for heavy oil flow measurement.

Baseline and blind tests have been completed on a range of Venturis, quadrant edge orifice plates and cone meters using the method. The results show a significantly improved flow rate error typically better than +/- 1.5% in laminar, turbulent and through transition. Density can be calculated to +/- 2% of actual values and Reynolds number and viscosity to within +/- 5% of actual values.

This presentation will detail the theory behind the method and show a case study of the method in operation using test work completed on the NEL High Viscosity flow loop.

Determination of water breakthrough, or a change in water gas ratio (WGR), of a gas well is a key challenge in deep water environments. Commingled flow from different wells into a common flowline can make back allocation of individual well rates challenging. In addition, identifying a “bad actor” well helps to avoid issues such as hydrate formation and liquid surges. The correlation between an increase in fluid temperature and water breakthrough has been known for many years [1] [2] but not fully understood. Under the right conditions in gas wells, we established a correlation to determine water breakthrough based on a temperature drop, pressure drop and gas molecular weight. This correlation to detect water breakthrough has been implemented in a virtual flow meter (VFM) in a transient real-time system.

This short technical discourse explores the relative merits of the use of thermodynamics based models with commonly used correlations to estimate flow rates of multiphase fluids through surface chokes. Seven different data sets gathered from laboratory and field settings, involving about 1,000 independent data points, constituted the essence of this study. The study found the importance of PVT data in any flow through choke calculations. Specifically, we found that changes in density and heat capacity of fluids with pressure and temperature should be part of any rigorous effort for computation of flow rates.

The preparation of reservoir fluid models and the generation of appropriate tables for these models has been discussed previously. However recent experience with such an effort has indicated this topic at least needs clarification and identification of heuristics for model and table preparation. This talk will describe important aspects of the required PVT experimental data necessary for fluid model preparation. Then how to use typical experimental results to fashion appropriate property values for the tables based on the required input and desired outcome for the meter.

Most PVT studies are designed for reservoir simulation and engineering. These studies ignore many aspects important to facility engineers such as liquid volumes below bubble point pressure, and data at temperatures below the reservoir temperature. Temperature is a variable in pipelines more so than in a reservoir. Further data need to be taken to pressures as low as 750 psia.

The typical match focus on bubble point pressure is not so important since in reservoir studies this represents the onset of multiphase flow. This is not so important in pipeline flow where the volumes of liquid and gas at T and P as well as phase densities and viscosities are most important for flow. A case study will be used to demonstrate the complications of applying software to prepare tables of values appropriate for multiphase meters.

Although hydrocarbons are traded in volume and often measured in volume terms, for many regions mass measurement is required for certain purposes such as allocation measurement, financial reporting, and taxation purposes.

Thus precise measurement of density becomes a critical parameter in the conversion from volume to mass. In recent years the errors associated with in field density measurement have received special attention from the oil and gas industry. The main concern revolves around the performance of density meters operating at process conditions that differ from laboratory calibration conditions. In addition to accurate measurement over a wide range of densities, users also require precise measurement at elevated process pressure and temperature as well as across varying fluid viscosities and ambient temperatures.

Test data acquired under these challenging process conditions using this new vibrating tube sensor technology and is presented and reviewed in detail.

The performance data is derived from several sources - including the revised NEL Densitometer Calibration Facility in Glasgow. NEL, the flow measurement specialist, has completed a major upgrade of its Densitometer Calibration Facility. Overall, this means that, in line with recent recommendations from the OGA (Oil & Gas Authority UK), the facility allows densitometers to be calibrated at their anticipated operating conditions.

Fiber Optic Distributed Acoustic Sensing (DAS) technology has been used in an increasing number of applications in the oil and gas industry. In this work we focus on distributed multiphase flow rate measurements using DAS, which is of great interest for the upstream production measurement community.

DAS systems provide an indirect measurement of flow and so it is important to understand multiple stages of physical relationships that link multiphase flow in the wellbore to the measured DAS data. In the first part of our talk, we present a comprehensive multi-physics simulation model that incorporates the impact of the formation, wellbore and fluid flow patterns in the wellbore, along with the behavior of the optical fiber itself. The model helps us identify and extract the contribution of several flow related parameters in the DAS data as well as factors resulting in noise. Using this simulation platform we investigate the impact of several different flow regimes on DAS data, including laminar, bubbly, slug, and annular flow in the wellbore.

In the second part of our talk, we discuss inverse-problem solving strategies to analyze DAS data efficiently to obtain flow rates. We present a signal processing technique based on the wavelet transform, which processes DAS data efficiently and identifies components of the DAS data that are most relevant to the flow parameters. Subsequently an artificial neural network model is used to estimate flow rates and flow patterns. The neural network model can be trained using flow-loop and field data to improve the accuracy of the analysis. The DAS signal processing technique coupled with the neural network approach allows for efficient and real-time analysis of DAS data. It should be noted that managing and processing DAS data can be a daunting task considering a single well can produce terabytes of data in a couple of hours during production.

Using our algorithm production engineers can characterize the evolution of flow patterns in time; such as predominantly single-phase oil flow turning into oil-gas two phase flow. We expect our technology to allow oil and gas companies to improve their efficiency, come up with more informed operational decisions, and save millions of dollars by optimizing resources and reducing costs.

The ability to measure water content in hydrocarbon flows is of the upmost importance for effective production management, as well as process control, and stock loss control.

This class will describe the results of technology development that has been worked on in the area of water cut measurement, using a non-intrusive measurement method, based on a composite construction material platform.

The paper will demonstrate the benefits of continuous data streams in trending and profiling water-cut flow regimes from specific applications. It will support this with data from several field trials demonstrating its success and the value of the information. In addition, it will discuss the advancements of this technology along with potential applications where water cut measurement has been difficult or not possible, to date.

The product development, from lab testing to field deployment has been shortened by the use of pre-qualified materials and mature measurement techniques, which have reduced overall risk, often associated to new technologies.

This has led to a number of deployments in a variety of production profiles around the World. The class will discuss specific results, including data from NEL testing for a variety of multiphase and wet gas flow regimes.

The class will discuss advancement in technology where the meter can accurately measure the instantaneous Gas Void Fraction of a 3-phase flow regime. The presentation will discuss the flow loop test parameters, independent testing results, and discuss its potential value to the user in wellhead monitoring, production optimization and big data gathering.

The presentation will further focus on the product development currently underway for a full range 3-phase water-cut analyser, which would be ideally suited for the wellhead, enabling multi-well analysis to occur in variable production regimes.

UPM 2018

The UPM Forum is a unique gathering of all production measurement stakeholders, where they share and learn about measurement data experiences amongst data users, measurement device manufacturers and developers, government regulators, and subject experts.

It is where practical applications and new developments are actively discussed amongst technologists from every production-related discipline.

Regardless of your level of experience and knowledge, it is your best opportunity to learn from and network with the people who can best help you in your work.

Location for UPM 2018

Magnolia Hotel
1100 Texas Avenue
Houston, Texas 77002

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A Forum for Production Data Users

The Upstream Production Measurement Forum (UPM Forum) is a not-for-profit, industry-organized conference and exhibition that addresses the needs for flow measurement in land, offshore topsides and subsea oil and gas production. The purpose of the forum is to enhance the industry’s use and application of measurement and build a more effective collaboration across the industry. The forum brings together operators, suppliers, researchers and regulators in an open environment to share information and developments.

Each year, the forum committee selects the topics addressed at the forum according to their impact and priority. The committee selects the speakers from a pool of applicants and invited distinguished guest speakers based on the relevance to the conference goals and industry trends.

The cost of the forum is intentionally kept low to encourage attendance from a wide variety of technical professionals in upstream production. This enhances the discussions and the overall quality of the forum.