Here you will find a list of industry white-papers and case studies that we feel may be of interest to you. Not only can you view those papers done by Weatherford Production Optimization, but also those written by outside companies and individuals. If you are interested in submitting a paper or case study to our list, please
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This paper describes the evolution of an oilfield automation and software system up to an innovative level of surveillance and work planning. The historical automation level was at that of individual wells. (It is estimated that about 10% of the world’s wells are automated to this degree.) Next, this data was brought to field offices allowing remote surveillance. (Most automated wells have some similar type of data consolidation.) The next step was to feed this data automatically into engineering models, which is comparatively rarely done (other than with much human intervention).
It was to build upon this relatively high level of historical automation and surveillance that the decision was taken to go a step further and introduce a highly innovative software system which not only further developed the remote surveillance concept, but also managed the well services activities so that full well histories would be electronically managed. What was particularly novel was the concept that the workflow processes themselves would be defined in, and managed by, the software. There are few instances of this level of business process automation being applied in the upstream operations and engineering sectors, and the lessons learned are valuable.
During the past decade the concept of the Smart Field has developed from a twinkle in the eye of the visionaries in our industry to a position where several operators, notably BP, Chevron, Norsk Hydro, Saudi Aramco, Shell and Statoil, have flagship fields where many, but probably not all of the Smart Field Technologies have been deployed. The development and deployment of these technologies has normally been in Partnership between a major operator and one or more key suppliers.
Each of the major operators have their own terminology for “Smart Fields” as listed below. Throughout this paper the term Smart Field has been used based on its use at the SPE Forum and it is intended that any of the following terminology could be substituted by the readership.1,2
BP “Field of the Future”
Chevron “i-field” Shell “Smart Fields”
Also, during the past decade there has been an increasing appreciation within the industry that much of the future lies with the effective management of existing production and the continued development of mature fields. What may not be so clear is how to apply smart technologies to mature fields with a legacy infrastructure and long production history. Participants felt that maturity in itself makes a challenge for deployment and enforces the need for effective Change Management.
Many oil companies have begun to exploit the benefits of highly instrumented fields for optimal operation of their assets. This approach relies on much-increased use of data streaming from field to office.
Improvements in infrastructure for data handling and a common data exchange format as a ‘lingua franca’ between applications are prerequisites to robust and efficient dataflows.
Many of the software tools used to process and monitor the data flowing from the field are provided by a number of independent software companies and service providers. The current commercial landscape is characterized by a relatively large number of companies, each providing a piece of the solution. The majority of these tools do not stand on their own, but require information from other tools. An efficient means of interoperability between these tools is essential.
In this commercial setting it is in the interest of both users and providers of tools that a viable open industry standard for a data exchange format be established. Such a standard levels the playing field by assuring some level of compatibility between vendor products, allowing them to focus on delivering innovative, distinguishing functionality. From an operator’s perspective the standard will accelerate the delivery of integrated solutions to end-users and decrease the costs of connecting and supporting the various parts.The evolution of the Internet has had a
profound impact on the manner in which data is being processed. The technologies, although still developing, have matured over the past years to the extent that they can now be used reliably for routine operations. Internet-based IT architectures are being adopted by most companies and will be incorporated in the PRODML design.
PRODML will help oil companies reap the benefits of highly instrumented fields.
Many excellent articles and technical papers over the years have documented the economic and operating benefits achieved by installing pump off control on rod pumped wells. This paper not only examines the most common problem associated with rod pumping – displacement control, but it defines “pump off”, as well as reviews and summarizes the benefits of rod pump control already documented in past articles and technical papers. In addition, this paper provides numerous examples of case studies with microprocessor-based rod pump controllers (RPCs).
The estimates of benefits cited in this paper are based on field experience, customer dialog, and expert input. These benefits and typical improvements are based on specific case studies and should be used only as a guide to estimate the potential benefits of rod pump control in a particular situation.
XTO Energy is a domestic producer with a history of acquiring properties where technology can be used to increase profitability and consequently extend the life of the reservoir. XTO optimizes assets through drilling, workovers, and cost reductions. This article focuses on reducing operating costs using well optimization technology.
Since operating costs are a contributing factor to the cost per barrel of production, minimizing operating costs reduces the production cost per barrel. Production cost per barrel is defined as field overhead expense coupled with costs associated with the operation of the producing wells, including workovers, utilities, repairs, maintenance, chemical treatments, and labor.
Profitability of the asset can decrease as well production declines (as represented by the decline curve in Figure 1). Eventually, the well becomes unprofitable and is temporarily or permanently abandoned. By reducing production costs, the well is immediately more profitable and the economic life of the reservoir is extended.
By using both hardware and software as a single system, XTO is able to reduce production costs by incorporating the optimization system into their organization. Each morning, the well specialist uses the software to review data scanned from producing wells fitted with intelligent controllers to make informed decisions about which wells need to receive attention for that day. He then prioritizes an action plan to address well conditions that are less than optimal. Finally, the appropriate personnel and resources are dispatched to these high priority wells with knowledge based on data received from rod pump controllers (RPCs) and analyzed with the desktop software system. This process reduces the time to trouble shoot a problem well and significantly reduces average time to failure resolution. This is because finding problems quickly typically makes failures less catastrophic.
For example, when a well consistently pumps off and cycles several times per day, but suddenly runs continuously twenty-four hours per day with out pumping off, the production optimization system immediately identifies the change. This condition usually means that the fluid level is remaining at a high level, which could indicate a change in reservoir behavior or more likely, a tubing leak. Finding and repairing the leak minimizes deferred production and eliminates the excess cost of pumping an inefficient well.
The optimization software and automation principles discussed in this paper have been implemented in fields with as few as 20 wells to fields with well over 3,000 wells. These installations have been made in primary recovery fields to tertiary recovery fields undergoing water, CO2, or steam flooding. These systems have been installed in new fields with no automation in place and in mature fields, which have been automated for over a decade. Over the history of all these installations, we have documented the benefits and rationale for implementation of these types of systems. This paper describes the cash flow enhancement benefits of implementing a comprehensive production automation optimization system in the following different categories:
This paper documents the initial benefits of using the ePAC flux vector drive on an active well in California, USA. Benefits include the following:
Substantial power savings
Reduced tubing and rod wear
Rod and pump jack forces being dramatically reduced.
Accurately balance the pump jack.
The ePAC Rod Pump variable speed drive was set up on a well in Bakersfield, California on September 25, 2001. This well was chosen to test all the software features and demonstrate the advantages of the ePAC drive. It is a horizontal steam injection well with the pump sitting at 85 degrees, with a Mark 2 Jack installed running off the line at 7.6 SPM. There was a Pump Off Controller (POC) on the well, which we left running. Due to sand infiltration, the POC was set to keep the well running during a pumped off condition. According to the dynamometer card generated by the POC, the well was running about 50% of the time in a pumped off condition.
Following the setup, the well did not pump off. As the pump fill decreases below the target pump fill, the drive controls the speed to maintain optimum fill. The pump fill is calculated on each stroke. If the pump fill is greater than the target fill, the target fill is reset and the drive speeds up to accomplish the new target fill. Once the pump fill becomes less than the target fill, the drive slows down until target fill is accomplished. Thus the speed ramps up and down to maintain optimum production without pumping the well off. Minimum target fill was set at 60%. Minimum pump fill was set at 45%. As long as there is fluid in the well bore, the drive will slow down in order to never let the fill go below minimum pump fill.
The cost of electricity is one of the single largest items associated with oil and gas production. This cost however tends to be overlooked relative to other production costs, due to the regulated nature of the utilities combined with its specialized and non-core technical requirements. In spite of this, several studies and strategies over the years have looked at ways of reducing this cost component with meaningful results. Many of these strategies consist of structuring loads and designing equipment to take advantage of the utilities regulated rate structure. As the electricity industry in the US moves towards deregulation, these rate structures will no longer exist and in their place will be contracts negotiated on a free market basis between the user and supplier(s) of electricity.
In the upcoming deregulated electricity market, three key strategies are available to effectively manage oil field power costs; 1) real time monitoring and control of the electrical load 2) infield generation of electricity and 3) negotiation of an integrated power supply agreement. Because electricity is the ultimate just-in-time product, prices vary greatly depending upon when the power is consumed. The strategies listed above allow for the user to proactively structure their power supply systems to address the fundamental volatility of the real price of electricity. The effect is to strip out the historic premium that is paid to the utility to handle the natural volatility of electricity prices by blending load shifting, internal generation and market purchases.
This paper examines different scenarios where the above strategies are proposed and makes estimates for potential cost savings. These solutions utilize existing technology applied to the changing market environment and therefore focus on economic justification as opposed to technology verification. In one such case the pumping intervals for a collection of wells is adjusted using real time power prices combined with remote operations. This has the effect of reducing the total cost of the electricity consumed per barrel of production while only marginally reducing the actual number of barrels produced.
Many oil field service companies as well as oil producers have manually tracked assets over the years for a variety of reasons. The service companies have tracked assets such as pumps, packers, or other products to assist in R&D efforts. Being able to collect the data and compile statistics on run times and component failures enables the service companies to evolve and improve current products as well as design new products. From a producers perspective, compiling the same or similar data allows for the development of "best practices" in operating procedures and processes. Software products developed to address these needs have evolved with time to provide more functionality. However, many systems implemented to handle the total process of data acquisition, warehousing, querying, and reporting to achieve improved operating results have become more difficult and expensive to support than the value added.
The value of the information has not diminished, but increased due to the fluctuations in oil prices and the continuing efforts to reduce lifting costs through design and process enhancements. The recent development of a web based tracking system incorporates workover management, downhole equipment, and chemical usage while enabling the operator and service provider the ability to easily enter and access the data. The system reduces the problems of database synchronization, multiple entries of the same data, and provides a common means through the Internet to interface with the information. The system links the operator in the field, the service company providing equipment or chemicals, and the district office together through a common database that each has access to.
The system allows a technician in a pump shop, workover foreman in the field, or chemical sales person to easily enter data into the system using a laptop computer or touch screen technology. The data is brought back to the service provider's local office and is accessible to the operator through the Internet. Wells, well equipment, and equipment components can be tracked for run life and root cause of failure. The operation becomes an information network that uses the same data to accomplish different tasks but with a common objective of reduced costs and improved profitability.
This paper describes a technique used to verify measured well test data in shallow rod pumped fields. Typically, the availability of measured well test data is constrained by test facility accuracy and the availability of the test facility for acceptable testing frequency. This technique involves the use of RPC (Rod Pumped Controller) calculated total fluid production as one source of production data for each well. A second source of production data comes from a wave equation driven diagnostic software program. This program uses load and position data gathered from each RPC to generate a downhole card from which pump displacement (production) can be calculated for all wells.
The measured well test data for each well can then be compared to the "inferred production" and the "downhole displacement" data for any observed discrepancy. "Inferred production" and "downhole displacement" make it possible for operating personnel to track daily individual well production with a high degree of accuracy without the use of actual well gauging facilities that might not be available on demand or that give questionable results.
This paper will also address methods necessary to setup RPC inferred production for reasonably accurate results, as well as necessary techniques for good displacement calculations from RPC dynagraph cards. These techniques involve the use of central site software for RPC setup and data telemetry.
In most fields today, operators are asked to do more with less. The common theme is "Keep production up and expenses down." This paper describes the results experienced in several fields in the United States that are using Case Services' csLIFT software suite for production field automation. The combination of the right personnel and the right software has provided an environment where production costs were reduced and total production was maintained or increased. Efficiently monitoring well and facility operations, analyzing well performance, and accurately predicting problems with csLIFT has resulted in significantly decreased failure rates and stabilized or increased production per well.
Today's cutting edge diagnostic software for beam pumping surveillance, analysis, and optimization includes improved methodology based on time-tested techniques as well as practical new functionality. Specifically, this paper will reference dynamometer card pattern matching to aid the well analyst, lease operator, or other interested parties in understanding well operating conditions. This is technology available from the 1980's, but refined in the pattern matching algorithms used and the presentation of results to the user. Available new functionality includes diagnostic reporting that produces a collection of outputs or warnings which are the result of a statistical analysis of surface and downhole card information, calibration or predicted dynamometer card information, and trended data for each beam well addressed by the diagnostic software. The required data is gathered and the resulting calculations are performed each day by the diagnostic software. The purpose is to apply logic that an experienced well analyst would use to determine whether each well needs any corrective action. The diagnostic logic can be customized, allowing users to specify statistical limits for creating warnings. Those diagnostic warnings deemed unnecessary can be deactivated by the user.
Major areas of interest for this paper include: 1) recognition of RPC load calibration problems, 2) gearbox torque and pumping unit counterbalance, 3) correct prime mover size, and 4) verification of pattern matching usability. The field test will include beam pumped wells located in conventional primary recovery areas and wells pumping under the influence of injected CO2 for secondary recovery. The data presented in this paper was randomly selected from wells in a 101 well system located in western United States. Average pumping depths ranged from 5400' to 6500'. All wells were equipped with RPCs (Rod Pumped Controllers), calibrated load cells (all with five years or less service), and some combination of magnetic proximity switches and inclinometers for position input. RPC and end device maintenance and software well configuration history should be consider as average.
This paper describes the cash flow enhancement benefits of using automation software for gas production optimization. Efficiently monitoring well and facility operations, analyzing well performance, and accurately predicting problems with software optimization tools has resulted in significantly decreased failure rates and increased production per well.
The automation software allows producers to move from a reactive mode to a proactive mode. Wells become more stable, and analysts can spend more time fine tuning operations for maximum production rather than fixing emergencies. In short, the networked automation software system calls on computers and other devices to handle the manual and repetitive work of monitoring wells and facilities, as well as collecting and crunching numbers.
The optimization process goes beyond basic operations, but extends into production optimization involving well testing, facilities monitoring and alarming, production monitoring, and gas injection. The net effect is increased runtime and arrested decline curves, resulting in more reserves.
While divisions in a corporation are accepted as an efficient way of structuring an organization, modern corporations often have barriers between divisions, limiting their ability to interact. The result is much like the fable of the blind men and the elephant. Different departments focus on one specific area of the business while losing the vision of the big picture (the elephant). These divisions manifest themselves in different operating procedures, different software applications, and different databases.
Unfortunately, when it is time for different areas of the company to pool their resources and work together, it is difficult to manage the dissimilar data sources and applications. Moreover, when someone in the organization needs to see a detailed area of the business, it requires the use of different unfamiliar applications and databases. These "blind men" need a specific application that addresses the area of the business unit that is important to their task.
This paper describes some the issues relating to disparate databases and applications that are used throughout the energy industry and describes a solution to solve those issues. Technology standards, such as Windows NT, ActiveX, and COM, can be used to combine the data and applications from presently unrelated areas of the business into specific, meaningful information that speeds the decision-making process toward more accurate decisions. This can all be done without the effort of creating new and complex databases that require new data models, extensive setup, configuration, and maintenance.
Case Services' software provides production optimization for a variety of different methods of artificial lift. This paper discusses the dominant factors in electrical centrifugal submersible pump design and monitoring. Emphasis is placed on three areas:
Well inflow performance behavior.
Fluid Pressure-Volume-Temperature and phase behavior.
Pump equipment performance specifications.
An examination of fluid dynamics within a centrifugal pump provides appreciation for the need to analyze the pump "one stage at a time." The importance of individual pump testing is also identified.
This paper focuses on the three ESP products in the csLIFT suite, csSubmersible, csSubsAnalysis, and csSubsDesign.
Methods are proposed by which the pump, motor, producing formation, and fluids are considered a complex system, which can be modeled by csLIFT computer software. csSubsAnalysis and csSubsDesign provide a basis for the prediction of the equilibrium point at which a particular set of equipment might operate under specific well conditions. csSubsDesign permits an analyst to compare a number of designs for desirability.
Further discussion illuminates the value of periodic monitoring of electrical centrifugal submersible pump installations with csSubsAnalysis. Methods are proposed by which monitoring can identify changes in operating conditions which could adversely impact pump life.
During the past five years, eProduction Solutions has worked with a vast array of oil and gas companies. The csLIFT suite of products has been implemented in fields with as few as 20 wells to fields with over 3,000 wells. These installations have been made in primary recovery fields to tertiary recovery fields undergoing water, CO2, or steam flooding. csLIFT products have been installed in new fields with no automation in place and in mature fields, which have been automated for over a decade. Over the history of all these installations, we have documented the value-added benefits and rationale for implementation of the csLIFT suite of products. This paper describes the cash flow enhancement benefits in the primary areas of an oil and gas field operation, as a result of implementing csLIFT software.
The paper describes the cash flow enhancement benefits of implementing csLIFT in the following different categories:
Reduced Operating Costs and Well Failures
Individual Well Management
Efficiency in Field Operations
Efficiency in Computer Operations and Automation
Since not all oil fields are the same, some of these benefits may not be applicable to your specific site. Therefore, an Excel 97 worksheet file and example field justification is downloadable from eP to assist you developing possible cost savings and production improvement associated with installing and using csLIFT in your specific field or area.
This paper describes the software system a major oil company's large South Texas gas field now uses to monitor and optimize production. Using a software solution for data acquisition and integrated analysis allows operators of the field to have accurate data on well production, more accurate nomination tracking, and immediate material balancing.
The field has 320 gas wells and nine facilities that are now on the system. It monitors 19 remote terminal units (RTUs), 16 sales points and 18 compressors in a field that produces an average of 240 million cubic feet of natural gas per day. The users of the system are able to add and modify wells and facilities to the software system as needed.
The goal of the project was to use technology to reduce operating costs, increase production through reduced downtime, increase employee productivity, and improve safety across the field.
Implementing the system has resulted in reduced costs and increased production. The benefits of implementing the system include: more accurate nominations, increased efficiency in discovering shrinkage in the field, greater production due to a decrease in the downtime of compressors, more accurate production forecasts using G-10 data, the enabling of call-outs from the software after hours, and optimized work processes for employees.
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