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Production and Operations Management Case Study

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									                                                                                        Digital Energy Workshop -June 8, 2010

                                                                                               The Value of Real-Time Data

                                                                                         Subject: Wells - Increased Productivity

     SPE Paper    Title                                 Summary of Paper                                                                                                       Identified Benefits
      Number

Good Sources
         28467    Gas Optimization at the Kuparuk       Oil, water and gas are separated at three central processing facilities. Gas is compressed at each facility for use    10,000 BOPD or 3% of the total oil
                  River Field                           in gas lift operations and for miscible and immiscible water alternating gas pressure support projects.                production
                                                        Currently the central processing facilities are gas handling limited. Therefore, a gas optimization strategy is
                                                        vital to the efficient operation of the field.

                                                        Implemtation of a lift gas allocation and production well selection strategy based on the incremental gas oil
                                                        ratio and formation gas oil ratio concepts results in a significant increase in oil production from a field which is
                                                        compression capacity limited. The benefit at the Kuparuk River field is approximately 10,000 BOPD or 3% of
                                                        the total oil production.

         84166    Gas Lift Automation: Real Time Data   This paper discusses the problems engineers experienced understanding daily production variance before                  The actual result was 600 BOEPD
                  to Desktop for Optimizing an          automation was installed, the system functionality of the automation system, and the results achieved. Project         annualizzed over the year, which
                  Offshore GOM Platform                 execution is also discussed because of its importance in ensuring the offshore personnel were engaged with             represents a 7% increase.
                                                        the project.

                                                        Financial justification for the Amberjack gas lift automation system was made from an estimated 450 BOEPD
                                                        increase in production. The actual result was 600 BOEPD annualizzed over the year, which represents a 7%
                                                        increase.

                                                        It is important to note that the overall benefit of this system comes from engineers consistently using the
                                                        system to access well data and make changes that increase producton. The system by itself will provide from
                                                        one to two percent production increase by simply maintaining a constant gas lift injection rate in each well.
                                                        But the real benfit comes from engineers noticing well opportunities and implementing gas lift redisigns, other
                                                        forms of well work, communication with the field, and educating operators to recongnize opportunites.


       103248,    Preparing a Business Case for                                                                                                                                Correcting a problem early saved
        Case A    Technology Investment in Production   Murphy E&P’s deepwater platforms, Medusa and Frontrunner, together produce over 91 MBOEPD (at $60 per                  approximately 48 hours of production
                  Operations                            barrel this amounts to $5.5MM per day or $228K per hour). From the beginning of production, Murphy was                 worth about $684,000
                                                        experiencing a common problem back in their corporate office. The engineering and management personnel
                                                        responsible for meeting production targets could not reliably “see”, from onshore the real time data collected
                                                        offshore from the reservoirs, the wells, or the production process.

                                                        Real time data available both onshore and offshore allowed engineering and operations to quickly identify a
                                                        problem with a downhole valve. Identifying and correcting the problem early saved approximately 48 hours of
                                                        production worth about $684,000.




58c2ed40-0334-40e7-8cff-727ed6dab27e.xls                                                                                                                                                                       7/11/2011 6:52 PM
       103248,    Preparing a Business Case for          The proposal was to monitor and control the field with SCADA. The project provided monitoring and control        Production accelerated 12%
         Case B   Technology Investment in Production    capabilities on 108 producing wells, 37 injection wells, 3 remote gathering stations and 5 test stations.
                  Operations

                                                         Operations wanted to understand the benefits of automation for their field so recommended historical data be
                                                         used for the bsiness cass. The team collected produciton and operating time data for the wells one year before
                                                         and one year after SCADA was installed. The data showed that the wells accelerated their production after
                                                         SCADA by approximately 12%.

                                                         The team concluded that SCADA would be a good investment for the field. The project would provide a NPV of
                                                         $170,000, an ROR of 69% and a DPI of 3.5.

       103248,    Preparing a Business Case for          A producer installed a SCADA system with pump-off controllers (POC) with the goal of improving production as     Well work reduced $35,000 per year for
         Case C   Technology Investment in Production    well as pump failures. The project's business case was build around a 2% increase in production and a 20%        a pay-out of 0.1 years.
                  Operations                             reduction in well maintenance.

                                                         After the POC's were installed a project audit was performed.

                                                         The study showed that repairs for events that a POC could impact, primarily non-corrosion problems,
                                                         decreased from a failure frequency of 1.2 failures per year before POC's to 0.4 afterwards. This accounted for
                                                         approximately 60% to 70% of the failures in the field.

                                                         At an average well work cost of $50,000, the reduction in failure rate produced a $35,000 benefit per well per
                                                         year. Since the cost of a POC amounted to only $3500 per well per year, the project produced a pay-out of only
                                                         0.1 years.

       110525,    Optimizing the Production System       This paper discusses the workflows utilized in identifying production optimization and enhancement               Restored production to previous levels,
        Case A    Using Real-Time Measurements: A        opportunities from large amounts of streaming data flowing from a number of wells.                               adding 20%
                  Piece of the Digital Oilfield Puzzle


                                                         Observations on a large number of wells during a 2 year period show that over 50% can benefit from some
                                                         form of optimization, resulting in a substantial increase in production.


                                                         On a high volume producer with a very high PI, an alarm was received on high pump intake pressure and low
                                                         average motor current. Well test showed a decrease in flow rates by 20%. Further analysis indentified pump
                                                         degradation as the problem. The pump would have failed had it continued working. The unit was proactively
                                                         pulled and replaced to restore production. Such proactive intervention to avoid a catastrophic event was only
                                                         piossible due to real time surveillance and process to continually optimize the equipment

       110525,    Optimizing the Production System       One of the prime drives in ESP operations is run life. Initially run live averaged 60 days.                       In one year, incremental production
         Case B   Using Real-Time Measurements: A                                                                                                                         equivalent to $100,000 was added and at
                  Piece of the Digital Oilfield Puzzle                                                                                                                    least $60,000 in equipment and rig casts
                                                                                                                                                                          were saved.




58c2ed40-0334-40e7-8cff-727ed6dab27e.xls                                                                                                                                                                  7/11/2011 6:52 PM
                                                         The operator added new performations and lowered the equipment to increase run life from 60 to 122 days.
                                                         Production data revealed that most of the liquid was coming from the top set of perforations. As the unit was
                                                         sitting below the top of performations and a shroud cold not be installed due to clearance limitatios, there was
                                                         not enough liquid flow past the motor to carry away the heat.


                                                         Based on data obtained through serveillance, it was recommended to raise the unit about 600 ft to be above
                                                         the top set of performations.

                                                         Through continued surveillance and analysis and timely recommendations, run life was increased four fold,
                                                         from 122 days to 465 days, and well up-time was increased by over 15%. In one year, incremental production
                                                         equivalent to $100,000 was added and at least $60,000 in equipment and rig casts were saved.


                                                         Degradation of ESP can cost significant amounts of money through increased electrical consumption and
                                                         deferred production.

       110525,    Optimizing the Production System       Looking back for a year, the surveillance data for a West Texas well demonstrated that the pump in-take               Replacing degraded pump increased
         Case C   Using Real-Time Measurements: A        pressure had been steadily rising. In order to maintain production, the pump frequency was increased using            production 64% while reducing power
                  Piece of the Digital Oilfield Puzzle   the VSD from 58 Hz to 63.5 Hz, resulting in increased electrical costs of 22%. Further analysis indicated that if     costs by 10%.
                                                         the degraded pump were replaced, there would b a 64% increase in total fluid production with the pump
                                                         running at a lower frequency. This would reduce power costs by 10% even with the increased production.


       110525,    Optimizing the Production System       An analysis of the in-take pressure and productivity index of an ESP revealed that production could be                Increasing speed of ESP increased
         Case E   Using Real-Time Measurements: A        improved by increasing the speed of the pump from 60 Hz to 62 Hz using the VSD. The resulting production              production 400 B/D or 6%
                  Piece of the Digital Oilfield Puzzle   improvement was 400 B/D or 6% without any additional capital expense.




       112147,    BP Norway's Field Of The Future        BP Norway's Field of the Future Implementation - A Case Study. This paper will take a look back over the              5% (minimum) increase in production.
        Case B    Implementation - A Case Study          substantial achievements and benefits htat have accrued through the implementation of these technologies
                                                         and reviews the experience gained. It will also take a look forward to the plans BP Norway have for taking their
                                                         achievements to an even higher level of performance by fully embracing innovative intelligent energy solution
                                                         concepts in two major projects that come on line in 2010/11.


                                                         In order to achieve adequate production rates from the low permeability chalk reservoir at Valhall field the
                                                         wells are stimulated using a prop frac technique which is both very time consuming and very expensive. In
                                                         1999 one of the first applications of the fiber optic cables was to bring all the necessary data for making fracing
                                                         decisions to shore, so the engineers from both BP and suppliers could work onshore suported by their full
                                                         teams.

                                                         Improvements delivered were a 5% (minimum) increase in production.




58c2ed40-0334-40e7-8cff-727ed6dab27e.xls                                                                                                                                                                      7/11/2011 6:52 PM
                                                       Between the lines throughout all of the provided documentation of production improvements generated
                                                       through improved communication technology is an undercurrent of best management practices of successfully
                                                       integrating diverse teams of people through skilled communications management provided by the BP Norway
                                                       team. This is an outstanding historical account of a well-documented technical transition and a testament to
                                                       the staff that implemented the changes.


        116519    Intelligent Fields Management at     The Intelligent Field Management (IFM) project was about aggregating data, manipulating it with models and         10 to 1 benefits over cost
                  Woodside: A Low-cost Step            visualizing the results. The business problems addressed include well testing, efficiency and trouble shooting,
                  Improvement in Field Management      integrated data and anlysis, improved model characterization, prioritizing
                  using off the Shelf Technology


                                                       Implementing IFM had a significant and positive impact, including increased production, improved work
                                                       efficiency and increased integration and decision making.

                                                       Well testing - fewer needed; also allowed for fewer production dispruptions efficiency and trouble shooting-
                                                       data for models is always known and better visibility of data is helpful.

                                                        Integrated data and anlysis - perhaps the greatest immediate benefit of IFM has been a step change
                                                       improvement in integrating both data analysis and work practices.

                                                       Improved model characterization- network model runs every 1/2 hr because the data can be quality checked
                                                       automatically

                                                       Prioritizing - again this was about visibility into data making better operating choices

    128682,       A Dynamic Business Needs Dynamic     Recently the state-of-the-art in intelligent operations has evolved from a reactive capability to a predictive     Increased production was 3500 B/D, or
    Case A        Solutions; How Field of the Future   capability. Data streaming, which was initially installed to allow onshore support teams to view and respond to    10% of flow from two tiebacks.
                  Turned BP into a Smooth Operator     actual process data, has now been coupled successfully with mechanixtic and data-driven models to provide a
                                                       look-ahead capability. real time performance monitoring has morphed into predictive performance analysis.


                                                       A hybrid data analytical and dynamic modelling study was executed in 2008 in teh Valhall Field to optimise the
                                                       start-up procedure for the flank wells. Through the study, a set of start-up criteria were developed to support
                                                       the asset in deciding when to bring a well online. The start-up criteria significantly reduced the number of
                                                       failed start-up attempts, improving well availability and up-time. The overall increase in production was 3500
                                                       B/D, approximately 10% of the total production from the two flank tie-backs.


    128682,       A Dynamic Business Needs Dynamic     In 2008 an attempt to bean up one of the Tambar wells failed when the header pressure was not cut                  3000 B/D
    Case B        Solutions; How Field of the Future   significantly prior to start-up. With no gaslift the well was bull-headed with nitrogen to displace the stripped
                  Turned BP into a Smooth Operator     oil back into the reservoir. Working in the virtual environment, an optimum bean-up strategy was determined.
                                                       The model-based advice was a success and the well was broought back online at a rate of over 3000 B/D. For
                                                       the latter part of 2008, the well was kept online by dropping the manifold pressure at Tambar prior to start-up,
                                                       as per the recommendations generated from the dynamic modelling work.




58c2ed40-0334-40e7-8cff-727ed6dab27e.xls                                                                                                                                                                 7/11/2011 6:52 PM
    128682,        A Dynamic Business Needs Dynamic       In 2007, BP's modelling toolkit led to a 2000 B/D production increase in the Schiehallon Field in the North Sea.   2000 B/D
    Case C         Solutions; How Field of the Future     Initially, flow stability mapping was used to characterise the stable operating envelope for each riser. A data-
                   Turned BP into a Smooth Operator       enabled model was then used to explore different well-to-riser combinations that would improve the level of
                                                          stability across the field. Once the level of stability had been improved, production was ramped up as the gas
                                                          flowrate was pushed closer to the compression capacity. Through a data-enabled model, the allocation of
                                                          gaslift was optimised to further improve production rates.


    128682,        A Dynamic Business Needs Dynamic       Well A02, a heavily deviated well on the Clair platform, is prone to slugging. Numerous attempts by the asset      1000 B/D
    Case E         Solutions; How Field of the Future     to flow the well in an optimum but stable fashion have yielded little success. With flow stability being a major
                   Turned BP into a Smooth Operator       concern for the asset, the well is heavily choked back.


                                                          Use of the data analytics toolset helped to identify a sweet spot that preserved a minimum rate needed to
                                                          prevent the occurrence of severe slugging, while maintaining a minimum hydrostatic head needed to mitigate
                                                          the impace of hydrodynamic slugging. Operating A02 at the sweet spot has helped to increase production by
                                                          1000 B/D

Possible Sources
         52177     Production Optimization at the         The objective of this work was to develop an optimization model which would be an improvement over the             7% increase in production
                   Kuparuk River Field Utilizing Neural   current model and aslo be superior to commercially available optimization software. This required the
                   Network Genetic algorithms             development of a field production model which included well performance, surface line, and facility models.
                                                          In order to successsfully solve for an optimal solution to this large highly nonlinear allocation problem a
                                                          technique based on genetic natural selection prcess is used. In order to address the roblem of excessive
                                                          computation time, neural networks were developed to replace the surface line hydraulics simulaion.




                                                          The model was run to generate recommendations for allocation of wells to production and allocation of lift
                                                          gas. Average forecasted optimized rate for the 27 days was 292,000 B/D, which is a 7% increase in produciton
                                                          over the current optimization forecast method.

                                                          Production increases are calculated based on a model. No actual field results are shown.

         71556     Production Optimization using          Good example of new technology that leverages realtime data to reduce well testing effort, improve data            352 STB/d and 2.76MMSCFD/d
                   Multiphase Well Testing: A Case        accuracy and more proactively manage gas lift and overall production. More in-depth with specific results
                   Study from East Kalimantan,            desired. Developed Multi-phase flow meter.
                   Indonesia

        120509     Waterflood Recovery Optimization       This paper focuses on a model based study vs. actual field example, however there is a logical workflow that       130% NPV
                   Using Intelligent Wells and Decision   could be applied toward intelligent well business case. Applied workflow analysis to support decision analysis
                   Analysis                               related to well number and placement, use of intelligent wells and operating schedules, as well as evaluating
                                                          surface capacity parameters, such as export pipeline diameter and pump inlet pressure.




58c2ed40-0334-40e7-8cff-727ed6dab27e.xls                                                                                                                                                                  7/11/2011 6:52 PM
        123205    A Workflow-Based Approach to Real-   A closed-loop optimzation process was implemented for a large offshore oilfield to monitor the gas lift             Gathering data in real time through DCS
                  Time Production Optimization         operation in real time. It is based on an Engineering Workflow Platform which integrated multiple source of         system then integrating data with wells
                                                       data associated with analytical applications. This provided user-friendly visualization and desktop for engineers   and network simulators then periodically
                                                       to optimize the production.                                                                                         optimizing the gas lift gas injection rate
                                                                                                                                                                           and setting remotely the the rate of gas
                                                                                                                                                                           injection through DCS system. The
                                                                                                                                                                           workflow improved the monitoring of
                                                                                                                                                                           the production facilities because of large
                                                                                                                                                                           production fluctuation observed before
                                                                                                                                                                           the implementation.




58c2ed40-0334-40e7-8cff-727ed6dab27e.xls                                                                                                                                                                    7/11/2011 6:52 PM

								
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