Software That Enables Flow Metering of Well Rates With Long Tiebacks and With Limited or Inaccurate Instrumentation

Melbø, Hallgeir; Morud, Svein Arne; Geest, Robert van der; Bringeda, Bjørn; Stenersen, Kjetil

doi:10.4043/15363-ms

Cited by 10 publications

(5 citation statements)

References 6 publications

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“…Papers have been published previously describing virtual flow meter systems [for example Melbø 2003, van den Berg 2010and Loseto 2010]. Most of these use proprietary modelling tools which are not always available for other engineering work outside of the VFM application.…”

Section: Approachmentioning

confidence: 99%

ISIS Rate & Phase: Delivering Virtual Flow Metering for 300 Wells in 20 Fields

Heddle¹,

Foot²,

Rees³

2012

All Days

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At the SPE conference in 2006 BP announced the Field of the Future Integrated Surveillance Information System (ISIS) project. Since then the ISIS system has been developed, delivered, tested and verified. Deployment to BP assets has been at the scale and pace proposed in the conference papers published at that time. This paper describes a core module, the Rate&Phase virtual flow meter, and also gives reasons why deployment has been achieved so successfully.BP's Rate&Phase system automatically estimates production rates from individual wells and other well performance and reservoir information at least once per hour. The approach has been to automate a proven Petroleum Engineering methodology using models of well hydraulics and flow though chokes. The system takes advantage of the instrumentation typically installed on new wells and the transmission of those data for analysis at technical centres often remote from the production sites. Rate&Phase is integrated in ISIS along with routines to automatically reconcile production across entire fields, monitor issues of erosion and sand production and estimate reservoir pressure at shut-ins.The Rate&Phase system has been deployed widely across BP-operated assets including many major oil and gas fields. Benefits have been realised from the ability to efficiently monitor well stock, manage fields better and allocate production more accurately. The effort to determine monthly production allocation is significantly reduced. Production gains have been realised through assets operating closer to constraints because of the assurance of flow rates in critical pipework. Developments are being introduced to reduce maintenance effort through tools to assist model re-calibration and to complement the hydraulic models with models derived entirely from measured data.Rate&Phase exploits commonly-used modelling tools and is designed to be easy to deploy/configure. Acceptance of the system has been hastened because it is not regarded as a black box and all results can be reproduced manually offline. Current production and performance information is readily available and changes over time can be trended though existing data interfaces.

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Section: Approachmentioning

confidence: 99%

ISIS Rate & Phase: Delivering Virtual Flow Metering for 300 Wells in 20 Fields

Heddle¹,

Foot²,

Rees³

2012

All Days

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“…A random sample of the resource oil ratio will be found by where is a sample drawn from a uniform distribution on the interval . Thus, it is expected that the change in the resource oil ratio from to is the same as from to for sample , because follows from (11)- (12). and is defined by said interpolation.…”

Section: Error Distribution Of Oil Resource Ratiomentioning

confidence: 99%

“…Unfortunately, the accuracy has not been shown to be good enough to replace well testing. Soft sensors such as Well Monitoring System [12] or FlowManager 1 may also provide this information. However, most oil production systems still relay on well tests to provide data.…”

Section: Introductionmentioning

confidence: 99%

Optimal Well-Testing Strategy for Production Optimization: A Monte Carlo Simulation Approach

Bieker¹,

Slupphaug²,

Johansen³

2006

SPE Eastern Regional Meeting

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TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractWell testing may be performed to support many decisions including ones related to production optimization of an oil production system. In production optimization information such as gas oil ratio and water cut/water oil ratio is used to decide on, for example, which wells to prioritize for choking back/opening to avoid over-/underutilization of the production capacity. Since the reservoir properties change with time, the uncertainties of their estimated values increase with time, and eventually a new well test will be required. As the uncertainty in the estimates grows, so does the risk for prioritizing the wrong well(s) giving lower oil production rate than possible. A computer program is developed to decide which well to test based on historical test data. The program uses a Monte Carlo approach for identifying which well test is likely to lead to highest increase in the total oil production rate after the well test information is utilized to optimize the oil production. The computer program is applied to field data quantifying the benefits when applied to this specific field.

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“…This limited acceptance is likely due to the fact that there is still a scarce number of studies in the literature about VFM models description, validation and field verification [4]. From few studies available in the literature that validate VFM models with field data [6,7] it is possible to see that these technique has shown promising results in the field for flow rate determination, with accuracy levels similar to actual flow meters. Nevertheless, more studies are still needed to evaluate VFM models in a wider range of conditions to establish the weakness and capabilities in more details.…”

Section: Introductionmentioning

confidence: 99%

Performance evaluation of multiphase flow models applied to virtual flow metering

Mokhtari¹,

Waltrich²

2016

WIT Transactions on Engineering Sciences

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This paper presents a performance evaluation of multiphase flow models when using these models on Virtual Flow Meters (VFM). Recently, VFM simulators have been identified as a technology capable of provide metering backup, monitoring for abnormalities of physical multiphase flow meters and also for production well allocation. Nevertheless, there are just a few studies found in the literature analysing the accuracy of different VFM models applied to multiphase flow metering. In the oil and gas industry it is essential to accurately measure the amount of oil, gas and water being produced by individual wells. Prior to the 1980s, single-phase measurements alone were sufficient to meet the industry standards. However, with the advent of deepwater exploration and production, multiple wells comingling to a single production separator is a common practice in petroleum production for offshore systems. Therefore, the use of multiphase flow meters to account for the production of oil, gas and water from individual wells became evident. This investigation uses field data for more than one well to evaluate the performance VFM simulators. The results obtained from this study shows that VFM models can provide accurate predictions for multiphase flow metering. The simulators evaluated in this study could predict flow rates of oil, gas and water within acceptable levels of uncertainty, with an average absolute error of 20%.

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Software That Enables Flow Metering of Well Rates With Long Tiebacks and With Limited or Inaccurate Instrumentation

Cited by 10 publications

References 6 publications

ISIS Rate & Phase: Delivering Virtual Flow Metering for 300 Wells in 20 Fields

ISIS Rate & Phase: Delivering Virtual Flow Metering for 300 Wells in 20 Fields

Optimal Well-Testing Strategy for Production Optimization: A Monte Carlo Simulation Approach

Performance evaluation of multiphase flow models applied to virtual flow metering

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