bluuebunny/crossref_metadata_2025 huggingface dataset:
Property Evaluation of EOR Technology by Means of Expansive Granular Crosslinked Polymer
Authors: Wang Wei , Lu XiangGuo
Published: April 2009

This paper discusses the adjustment of water injection in oil formation by adding the expansive granular crosslinked polymer (EGCP) into the injection carrier.

Some pilot tests have been conducted in some reservoirs of Jiangsu, Daqing, Dagang, Shengli and Zhongyuan Oilfield, where water flooding recovery is low due to the channeling in heterogeous oil formation. All pilot tests succeeded in plugging higher permeability water zone to favor the injected water squeezing into lower permeability zones and driving more oil into wells, and the ultimate oil recovery have been obviously increased.

In this paper, laboratory experiments have been done to not only provide experiment data basis for the field application, but also provide the mechanism basis of the EGCP profile modification through porous media. The EGCP system is composed of EGCP and carrier. The carrying fluid should be chosen according to input rate, expansion ratio, transport capacity, EGCP anti-shear ability, and flow resistance. Besides, an optimization analysis based on laboratory data has been made on the types and concentrations of EGCP and carrier, EGCP slug size and EGCP injection time, and profile modification evaluation. Furthermore, micromodel test has been done to study the mechanism of EGCP profile modification. The input rate and expansion ratio of EGCP become smaller, however, the anti-shearing ability becomes strengthener with increasing the salinity of carrie. The water input rate and expansive ratio of EGCP became bigger in polymer carrier, compared with those in formation water carrier, while the anti-shear ability of EGCP became stronger in polymer carrier, the anti-shearing ability further increase with the increasing of concentration of polymer solution. The experiments show that the pressures at the core entrance and middle point can increase synchronously when using polymer solution as carrier. This phenomenon testifies that the ability of EGCP suspension transportation is better in polymer solution, micromodel test further testifies that EGCP has the flow characteristics of "transportation, trapping, re-transportation and re-trapping" when it is flowing through porous media, which is beneficial for diverting the direction of injection liquid to enter the unswept area. The alternation of transportation and trap still can be indicated by pressure changes. The EGCP technique has been further optimized by enlarging EGCP slug size and moving up EGCP injection time to enhance oil recovery. All of these will be beneficial to choose the proper EGCP and carrier, plug large channels, get a good profile modification effect and enhance oil recovery.
Acid Tunneling Stimulation in Oklahoma Limestone Using Coiled Tubing
Authors: Strasburg J. , Clark J.
Published: April 2009

With the recent increases in price of a barrel of oil and the growing scarcity of easily exploited oil, efforts to improve productivity of older wells have intensified. Some options for accomplishing this include re-stimulating the well and/or adding laterals that extend past the original wellbore. In open-hole limestone formations, one innovative technique can achieve both of these goals simultaneously, creating pre-stimulated "tunnels" that bypass existing near-wellbore damage to make contact with new reservoir rock.

The new technology relies on limestone's acid solubility and a coiled tubing-conveyed bottomhole assembly comprised of components that tilt the tool toward the formation. A high-pressure nozzle then jets acid to extend new tunnels from the wellbore. The technique is applicable in all open-hole wells drilled in carbonate formations and can be used to remediate old wells or complete multiple drainage tunnels in new wells.

This acid tunneling technique and tool have been utilized around the world. They were first used in the United States to create three additional tunnels in an Oklahoma well that has been producing since 1924. This paper will describe the acid tunneling tool and design along with: an operational timeline, summary of lessons learned during the United States operation, comparison of pre and post-job production information for the treatment.
Effective Wellbore Parameters and the Productivity of a Multi-Fractured Horizontal Well
Authors: Cvetkovic Branimir
Published: April 2009

Continuous improvements during well completion in addition to stimulation technology renew the need for multi-fractured horizontal well modeling. The present work investigates the productivity of a well with fractures by means of semi-analytical late-time approximations. These expressions are related to a vertical and a horizontal well with a single-fracture production. The flow in a fracture that is coupled to a horizontal well is of uniform flux (or of infinite conductivity flow) and the fractures can be positioned transversally or longitudinally. To successfully measure the production efficiency of a fractured-horizontal well, the effective wellbore radius and the equivalent single-fracture half-length were introduced. The effective wellbore radius was defined for a vertical well and could be extended for its horizontal counterpart. The equivalent fracture half-length was defined for a horizontal well with a single-transversal and a single-longitudinal fracture. The late-time approximations were developed for a fractured horizontal well positioned in the middle of an infinite oil reservoir. The developed expressions were employed for a multi-fractured horizontal well in order to define an effective wellbore radius and an equivalent fracture half-length (for both the transversal and the longitudinal fractures). A series of solutions corresponding to various conditions were given in a multiple-fractured-horizontal well model. It was possible to verify derived effective parameters of a fractured horizontal well by using a fast, robust and facile software program, a screening-tool product, that has been of considerable benefit to companies in the petroleum industry.
Changing the Operation of Oil and Gas Fields From "Harvest" to "Process" Mode
Authors: Cramer Ron , Rodger George Joel
Published: April 2009

In the O&G industry the nature of well and reservoir operations are slowly, but relentlessly changing. The traditional operations sequence of events is to drill, complete, and then flow wells to production at a "reasonable rate," and the process will yield what Mother Nature delivers.

This is what we refer to "harvest mode." The problem with this approach is that the production is invariably sub-optimal, resulting in lost revenue for the field operator and potentially damaging the reservoir.

Tools exist to look at the operation as an integrated process whereby the reservoir, well, and the entire surface facilities are modeled/monitored to optimize production from each well and the field/reservoir as a whole. This is what we refer to "process mode."

Traditionally operators endeavor to minimize reservoir damage and maximize production by performing infrequent, manual production tests, and occasional in-well pressure tests, to determine optimal well conditions. Ironically when instrumentation/automation is added to an oil or gas well it is almost always for safety or operational reasons. For example the use of rod pump controllers so that pumps are not damaged when they run dry, or to control the pump to minimize energy consumption when the pump is not filling completely. Automation, in the form of instrumentation and control systems, is rarely installed on a well to optimize the production of the well.

This paper will discuss underlying problems, experiences and plans that operators and service companies have in this area of production operations. The key to moving to aforementioned "process" mode is to properly monitor and or measure the production from the wells. Some operators developed simple pressure and pressure drop monitoring system to help detect when well tests must be re-run, as opposed to routine testing. Many other operators have used Individual Well Monitoring or Individual Well Testing. Finally, in one case an operator is looking at using well monitoring and updating the surface and reservoir models to continuously optimize the overall operation.
The Digital Asset: Connecting People, Technology, and Processes in a Collaborative Environment
Authors: Grable Jeff , Wylie Glenda
Published: April 2009

World energy demand is increasing. The next trillion barrels will be harder to access, harder to find and will be in ever smaller accumulations. New discoveries will undoubtedly be more difficult to produce and will have to be done with fewer and dwindling experienced resources.

The industry has begun to accept change due to their desired demand for improved efficiencies. These efficiencies include integrating the workforce (both service and operating groups), improving quality and efficiency of workflows, and improving the technologies that are feeding into the "Digital Asset™" service. Such technologies are better formation evaluation measurements, better geological models, and faster reservoir simulators, better able to integrate production data for comparison to the geological models. Connecting people and improving technology and workflows allow the right decisions to be made at the right time while spending the least amount of effort.

Today, necessity drives new and more dynamic integrated operations; and more efficient working relationships are evolving. This paper will discuss the challenge of doing more with less, exploiting more difficult reserves while lowering costs, increasing profits while reducing risk, and speeding up work processes while cutting non productive time.

The answers lie with in a series of steps towards cultural change: utilizing real-time collaborative environments allowing simple workflow methodologies to be applied and feeding improved measurements into improved models while continuous optimization occurs while simultaneously actual operations occur.
Data Driven Surveillance and Optimization
Authors: Cramer Ron , Goh K.-C. , Dolan Mike , Moncur Charlie
Published: April 2009

Traditionally individual well oil, gas and water production is measured periodically e.g. monthly, using shared well test facilities. Consequently, oil and gas production from a cluster of wells is difficult to manage, leading to late diagnosis of production problems and slow and conservative handling of production constraints. FieldWare Production Universe (FW PU) is a software application developed by Shell that provides continuous real time estimates of well-by-well oil, water and gas production. FieldWare PU estimates are based on data driven models constructed and updated from production well tests and real time production data.

This paper will discuss use of FieldWare PU for continuous optimization by predicting changes to overall and individual well production as a result of changes to individual well production chokes, lift-gas rates or other similar set-points to maximize an objective function subject to various well and overall production constraints.
Viability Study of Implementing Smart/Intelligent Completion in Commingled Wells in an Australian Offshore Oil Field
Authors: Pari M. Nadri , Kabir A. H.
Published: April 2009

Simulating automated action of smart well components represents a challenge in forecasting performance of such wells, which is fundamental in their design decisions. For example, wells equipped with Inflow Control Valves (ICV) where zones have to be switched on, off or partially closed based on their performance relative to the rest of the wells/completions in the field which share the same surface network and facilities constraints.

In this paper we present a study that has been carried out to justify installation of a surface controlled ICV in a group of wells in an off-shore Australian field with commingled production. The merit of surface controlled ICV versus uncontrolled commingled production has been compared. A numerical reservoir simulator has been used to model reservoir performance and production from individual zones. Also, well and production network has been simulated using a well and Production Network Flow Simulators. An interface "simulation manager" is used to facilitate information exchange between the two simulation programs and optimization of the process. Proper control of ICVs is simulated based on reservoir and well-bore simulation data which will result in maximum oil production of field network system resulting in higher recovery. Also, we have done typical economic analysis for smart well completion implementation. The results show that smart completion is viable for this field.
Realizing Value from Real Time Well Monitoring In Greenfield Assets
Authors: Feineman David R.
Published: April 2009

BP's proprietary Integrated Surveillance Information System (ISIS) was deployed globally starting in 2006. The system delivers well performance data to petroleum engineers in field and office sites in near real time. The paper presents two case studies on implementing remote well performance monitoring on two Greenfield assets in Africa and Asia where distance, national culture, and language differences must be addressed as part of a technology rollout. Based on the case studies, there is evidence that Greenfield assets can adopt new ways of working and technology that allows them to surpass the performance on similar Brownfield projects.
4D: From Mainstream to Main Street
Authors: Levin Stewart A.
Published: April 2009

As highlighted at recent SPE conferences and workshops, the use of 4D seismic technology has become mainstream. Currently, 4D monitoring programs are used in more than 140 fields (Lumley, 2008). Indeed, many major companies now require 4D feasibility studies for all new reservoir development plans. However, the high cost of 4D monitoring has generally limited its use to large fields that require heavy expenditures to produce. There has been relatively little "trickle down" in the use of 4D seismic among smaller producers, service companies, and/or consultants. Is this poised to change?

Challenges to 4D market expansion include technical feasibility as well as various economic drivers. Expected seismic response changes may be too small to reliably detect and interpret. And, relatively few entities have the luxury of maintaining a dedicated, integrated geoscience and engineering team with 4D expertise. However, most experts agree that economics serve as the greatest barrier to 4D expansion. In addition, the recent decline in oil and natural gas prices has provided further disincentive for 4D application by operators. On the bright side, I will show that studying the world's distribution of oil and gas fields leads one to the conclusion that if 4D costs were to drop by a factor of three, the number of fields for which 4D becomes economically feasible would rise by a factor of at least ten.

I predict that 4D costs could drop to these levels in three to five years because of the confluence of factors that include: technology continuing to reduce acquisition and permanent instrumentation costs, continuing growth of computing capacity, and integrated software packages for effective 4D interpretation. Also, regulations and tax incentives are adding greenhouse gas geological storage to the 4D monitoring market, and new inventions and processes are expected to play a role as well.

The possibility of increased expansion of 4D seismic technology from mainstream to Main Street is highly significant in the oilfield services industry because it would open annual revenue opportunities for smaller players that could be collectively measured in billions of dollars.
The E&P Balanced Scorecard: Becoming a Strategy Focused OPCO Driven by Performance
Authors: Kadam Sandeep , Fonseca Christopher
Published: April 2009

This Middle East Oil & Gas company explores, develops and produces hydrocarbons. It strongly believes that a strategy focused performance management approach would enhance its capabilities of producing hydrocarbon in the most economical way and maximizing ultimate recovery from reservoirs.

The company launched an e-Performance initiative to communicate and execute strategy and to create a "Line of Sight" both top down and bottom up and enhance horizontal alignment and integration.

We designed and developed the Performance Management System through Balanced Scorecards -A series of workshops were conducted for the functions / divisions by a group of consultants consisting of experts in Oil & Gas and Performance Management-Strategic objectives, measures and targets were captured and the score cards were programmed in Excel with traffic signals

Initially the key performance indicators were captured in an Excel workbook. The next step was to automate the process of data collection and aggregation before presenting it for Performance Management. Several applications were reviewed for the purpose. The choice takes into account that the proposed IT architecture and application exploits to the maximum extent functionalities of the existing ERP system and other applications.

Key Performance Measures were defined for the Production Operations, Gas Division, HSE function, New Development, the support services of HR, Finance, IT, Medical and the corporate functions of Supply Chain, Planning, Legal among other departments.

The New Development comprised Engineering and major projects, exploration, development, planning and support and automation/smart field. New development was the most significant concern to the company since it would increase their daily crude oil production by 0.4 million bbls by 2012.

All employees were made aware of the balanced scorecard, its objectives and the process to be followed through extensive training and awareness sessions.

The Balanced Scorecard system needs to be integrated to the operational IT systems, databases and/or datawarehouses. It is necessary to refine the KPIs due to changes in influencing factors.
The Promise and Challenges of Digital Oilfield Solutions—Lessons Learned From Global Implementations and Future Directions
Authors: Sankaran Sathish , Lugo Jose , Awasthi Ankur , Mijares Gerardo
Published: April 2009

Digital Oil Field (DOF) in the oil and gas industry has gained momentum in the last few years and has transformed from being a vision to projects that have measurable value. The promise of DOF has motivated many oil and gas operators and service companies to now establish corporate initiatives and associated business programs to develop and deploy DOF solutions. Many major capital projects are already evaluating the feasibility of DOF in early stages of the project decision process as part of the operational philosophy.

However, the implementation of these projects over the last few years has unraveled a multitude of practical challenges and hurdles to achieve the DOF goals, including selecting the candidate of highest value opportunities in the business unit's portfolio, justifying a business case, establishing new management processes to address operational transformation, defining people roles and responsibilities in DOF work processes, forming a team of skilled personnel for development and support of installed solutions, recognizing fit-for-purpose models, identifying appropriate technologies for the rapid deployment of integrated workflows, lack of open architecture and standards, project management approach, and change management, among others.

This paper describes the challenges faced in DOF implementations by Halliburton and the current industry status. The case studies presented highlight these issues and practical lessons learned about addressing these issues using novel solutions and delivering value through adopting best practices. The paper also provides an insight into future trends and areas of development, addressing areas of challenges that still must be resolved.
Using Integrated Operations Centers
Authors: Landgren Kennth , Lhote Jean-Pierre , Vernus Jean-Claude
Published: April 2009

Oil and gas companies increasingly require environments that support real-time E&P business processes, where field information, applications, and experts can be linked with operational managers and decision makers so daily operational parameters can be viewed and decisions executed. Most companies believe that making decisions in real time while leveraging global resources and infrastructure will help to improve their field productivity while reducing costs.

Project team members are often collocated to ensure open communication and planning. However, since E&P activities often take place in remote and hostile parts of the world, global operations with dispersed personnel frequently require such operations support centers to be "virtualized." Reliable and secure information flow is central to ensuring success in the contemporary oil field.

A previous paper outlined the significant challenges of process, networking, security, hardware, and software infrastructure encountered in creating and supporting these integrated operations centers. Another paper reported on some of the progress in meeting these challenges, with particular focus on the actual applications that support oilfield operations.

This paper focuses on challenges and solutions encountered in actually using such integrated operations centers, with particular emphasis on people issues, including change management, training, and collaboration. Real examples from working centers are used to illustrate the issues and solutions.
Real-Time Evaluation of Pressure Transients: Advances in Reservoir Monitoring
Authors: Contreras C. , Bodwadkar S. , Kosmala A.
Published: April 2009

Reservoir engineers operating in mature fields across the world struggle to get necessary reservoir data to make their exploitation plans more realistic. Pressure transients are the most effective way to understand the dynamic behavior of the reservoir. Loss of production and cost of acquiring data versus the benefits has always been a classical management dilemma. With the advent of digital oilfield technology, the pressure and hence the deterioration in well deliverability can be continuously and cost effectively monitored. This paper illustrates how real-time data can be used to make decisions on when to invest in pressure transient tests, and when a test is run, how to minimize the downtime. The case studies presented here are for wells on electrical submersible pumps in various types of reservoirs across Latin America.

The paper briefly discusses the three pillars of digital oilfield; technology, processes and people and how they work together to achieve continuous reservoir and production optimization. Reservoir analysis for wells on electrical submersible pumps (ESP) is challenging due to the restrictions imposed by the downhole equipment. Our work presented here focuses on developing workflows and interpretation techniques for this unique environment.

Having sensors downhole provides operators with an opportunity to get pressure drawdown and buildup data when the ESP starts and stops. For the wells we monitor, 10% of these unscheduled events provided much coveted reservoir information without having to stop the production intentionally. For the scheduled pressure transient events, the data acquisition rates were actively changed to ensure sufficient high quality data. Also, the length of the test was decided in real time to make sure that the test was long enough to meet the objectives but not too long to increase the cost without additional benefits. Thus with real-time technology we were able to overcome the shortcomings of traditional well testing and address the concerns of both engineers and the management. Case studies are presented where production enhancement opportunities were uncovered as a result of scheduled and unscheduled events on wells producing with ESPs. The results show that more than 70% of wells can benefit from stimulation, potentially increasing production up to 300%. To make proactive decisions and act on the recommendations generated from these production enhancement opportunities is still a challenge that needs to be addressed.

For fields with large numbers of ESP wells, a time snap of reservoir properties could be periodically obtained to track changes in pressure, skin and permeability for real time optimization.
Creating a New Workflow for Integration of Business Processes between Well Engineering and Subsurface Data Management
Authors: Eade J.
Published: April 2009

The lack of a global, consistent and reliable system for well/wellbore identification has been a long-standing issue. Industry professionals believe the heart of the problem is the lack of consistent definitions and best practices.

A major oil company has devised a solution, based on creating unique well identifiers (UWIs), that helps establish internal consistencies and best practices across the company's operating units. The generation of UWIs leverages the company's standardized computing environment for its subsurface data, and extends the computing environment to encompass engineering workflows and, by facilitating ties to back-office systems, enables integration with business processes. The effort to define and devise a comprehensive solution was managed as an upstream business improvement initiative to address the following key issues, and as such, was widely accepted and supported within the company.

Business process integration Revision of individual operating unit UWI practices to avoid diluting the benefits of a standardized computing environment Re-evaluation of data vendors to improve inadequate well-data coverage and responsiveness. Avoidance of costly and inefficient data trades by developing a better understanding of the data already owned, before purchasing new data.

This presentation will describe the resulting workflow whereby data from the well engineering database flows to the subsurface corporate well database and from there onwards to project databases once drilling begins. A workflow example explains how geoscientists can receive updates of trajectory data on-demand, thereby eliminating data re-entry and ensuring data correlation between the well engineering database and the project database.
Effective Use of LEO Satellites for Well Data Collection
Authors: McCoy Robert
Published: April 2009

LEO (Low Earth Orbit) satellites are an effective method of collecting and controlling well data from electrical submersible pumping (ESP) systems and other instrumentation from a global perspective. Utilizing intelligent remote systems, the data is gathered from the well and then compressed for transmission over LEO provided IP data paths. The data paths are very bandwidth efficient for small data payloads. After transmission, this data is then decompressed in a server application (HCG) and made available to a SCADA server. Using the "push" data scenario for a "Report by Exception" is very successful with hundreds of installs. This creates a "plug and play" true LEO global system without modifications to the SCADA system, historians, or visualization applications.
Automated, "By Exception" Well Surveillance: A Key to Maximizing Oil Production
Authors: Schipperijn Peter , Thavarajah Raymond , Simonato Ana , Mehdizadeh Mohsen
Published: April 2009

The increased need to maximize production from mature assets has resulted in the transformation of the oilfield surveillance workflow. Hitherto, wells were reviewed sequentially throughout the field on a calendar basis. This was a time-consuming process with the potential of considerable time lag between problem occurrence and diagnosis. The new data-driven workflow requires a tool to support a "review by exception" process through the automated identification and prioritization of exception wells.

The primary benefit of incorporating the surveillance tool in an integrated workflow is to shorten decision time and improve the quality of the decision through an automated process. Other benefits include timelier proactive problem identification, better use of the practitioner's time (focus on analysis rather than identification), elimination of repetitive data gathering and reformatting tasks, consistency and repeatability of evaluation, and better knowledge management.

Developed in San Joaquin Valley under the i-field initiative which espouses business transformation to the digital oilfield of the future, the tool's main role is to classify and diagnose well performance. It accomplishes this by encoding customer-derived business rules in a multi-channel framework. Using a sequential, frame-based expert system as the classification engine provided a superior diagnostic capability while limiting the number of unique diagnoses to maintain to an acceptable level. It also provided complete transparency in the analysis unlike other AI methods such as an artificial neural network (ANN). A web-based UI provided the user extensive filtering, sorting, and drill down capability by which to quickly identify and diagnose problem wells.

Deployment of the tool with the new integrated workflow has led to a 30% increase in the number of wells and patterns reviewed. In addition several specific well work opportunities were identified and led to increased production, effectively bridging the gap from data bytes to barrels.
Anomaly-Driven Engineering Empowered by a Central Surveillance Center
Authors: Brutz J. M.
Published: April 2009

A central surveillance center, designed to conduct routine surveillance on reservoirs, wells, facilities, and subsea systems, has been developed. Surveillance engineers, control-room operators, and information technology analysts staff the center. Centralizing routine surveillance enables cross-asset sharing of top surveillance techniques, develops staff's surveillance competence, and allows asset-focused engineers to ensure project delivery.

The center's software toolkit enables event identification, surveillance execution, and systematic history documentation. An advanced alarm tool and a web-based workflow tool enable the routine surveillance conducted by the center's staff. The alarm tool allows staff to focus on events by exception, and the workflow tool ensures a consistent set of surveillance measures are conducted for each event. All events and analysis are stored in a searchable online database to facilitate analysis of future events.
Getting Data to Drilling and Completions Teams and Vice Versa
Authors: Sawaryn S. J. , Deady A. , Whiteley N. , Critchley C. , Brown L. , Gibson N.
Published: April 2009

The paper describes some simple, but effective steps in providing drilling and completions data and visualisation in support of enhanced collaboration whilst allowing for future growth. The solution is based on WITSML and is implemented in the Operator's Advanced Collaborative Environment (ACE) in Aberdeen.

The transmission of large amounts of data onshore, from the rig is a relatively easy task but ensuring that these data are accurate and usable in both industry and proprietary tools is more of a challenge. The services provided by the major service companies are still geared towards providing data through their proprietary data packages and tools and the support they provide has been honed to match this business model. This situation is changing because of operators’ needs for technical and commercial flexibility.

Since January 2008, seven rig teams have adopted a new data viewer provided by an independent supplier. The shift has been user driven, prompted by a desire for consistency and the availability of dedicated on-site support. The use of proprietary tools and the greater sharing of data between the drilling and completions and subsurface disciplines is also driving the change, challenging set methods of data capture, communication and visualisation. The data displays in open areas have proved to be particularly popular and effective.

Further work is needed to improve internal service levels out of normal working hours and achieve greater alignment with the service providers to leverage existing infrastructure, practices and expertise and avoid unwanted complexity and cost. Robustness will become increasingly important as more critical services are delivered from onshore. Greater standardisation will help. Contract interfaces, both with main service providers and sub-providers still represent a major challenge.

The paper describes the data viewer and its deployment, the progress and successes to date and the further improvements required. Overall, team's attitude towards their data is changing and the real issue is getting teams to their data.
E&P Operational Innovation With Real-Time Collaboration and Exception Management
Authors: Al-Hamad Mohammed A. , Vettical Celestine S.
Published: April 2009

The use of real-time collaboration and exception management solutions can help you optimally leverage the investments made on real-time operation centers (RTOCs) and data management systems, and maximize utilization of scattered experts and resources to handle more critical situations from anywhere and anytime. These solutions leveraging modern Web 2.0 technologies will help you optimize the overall exploration and drilling operations by reducing rig downtime, mitigating risk, improving asset utilization, maximizing reservoir contact and increasing economic production. This paper discusses the prerequisites, implementation considerations, lessons learned and benefits of real-time collaboration and alert management systems, and the opportunities such systems offer to bring operational innovation in the E&P community and to find effective ways to address the new age energy industry challenges.
A Workflow-Based Approach to Real-Time Production Optimization
Authors: Barbarino Sebastiano , Alvarez José , Lozada Miguel Angel , Diaz Felipe
Published: April 2009

This paper explores the results of one operator's successful implementation of a workflow-based solution to real-time production surveillance and optimization of a large offshore field. In particular, we will provide an overview of one of the more complex workflows addressed, real-time model-based gas lift optimization for the asset. Details of the workflow and total value proposition are examined, demonstrating the possibilities and ROI potential of new data integration and workflow technologies.

With a system characterized by large pressure fluctuations in the surface network, previous attempts to achieve model-based optimization using manual processes had struggled with the high frequency of updates needed to maintain the models in an "evergreen" state. Utilizing a combination of techniques such as surveillance-by-exception, automated model validation, and assisted model updates, the new approach allows the operator to re-optimize gas allocations to the field's more than 200 producing wells and 70 platforms, at a 12 hour frequency. This frequency of re-optimization is sufficient to maintain the system at a maximum stabilized production rate.

The solution is currently in operation, and has provided a sustained production improvement to the field. Operational data is made readily available to users to support decisions, while workflows derived from operator best practices guide users to ensure that analysis is structured, streamlined, and repeatable.

The work is significant as a successful implementation of a large-scale production optimization solution configured to established operator best practices. In an age when operators are faced with declining production rates, smaller discoveries, and a "graying" workforce, such solutions allow operators to do more with less and deliver maximum asset value.
WITSML Real-Time Inter-operability Testing
Authors: Pickering J. G. , Whiteley N. , Rochford J. , Sheil K. , Lowe J.
Published: April 2009

BP has developed an internal Recommended Practice for the deployment of a standard data architecture for real-time drilling and completions information. This architecture uses WITSML communications as much as possible although data aggregation on the drilling rig can still employ WITS, OPC or even a proprietary language. Most deployments in BP are built on the latest Version 1.3.1 of WITSML. Early deployments in Indonesia revealed some inter-operability problems which had to be resolved quickly to eliminate operational delays. This experience highlighted the value of pre-deployment testing and subsequent deployments have all been staged in an independent test facility hosted for BP by SAIC in Aberdeen.

The BP WITSML test laboratory has already staged drilling and completions data systems for BP businesses in Gulf of Mexico, UK North Sea and Oman prior to field deployments. In addition, the Business Units have also been keen for the laboratory to provide an operational support function post deployment. Testing has also been conducted in conjunction with main BP equipment suppliers to demonstrate compliance for future installations.

Various problems have been identified during testing which will be described in the paper. The value of identifying these problems in a laboratory environment, rather than potentially exposing drilling operations to delays during equipment commissioning, is very considerable. The testing has been conducted with a very positive commitment from our suppliers which has resulted in significant learnings for all parties.

BP, along with other major energy companies, sees WITSML as an important enabler for remote operations, collaboration environments and the deployment of new technologies to support its future drilling and completions operations. The WITSML laboratory testing has been a critical step in building confidence in the robustness of WITSML and demonstrating its performance capabilities.
Subsurface Support Centre: A Hub for Communication of Knowledge
Authors: Løwén S. , Nygård B. E. , Østensen S. , Lund T.
Published: April 2009

Based in Stavanger, Norway, StatoilHydro Subsurface Support Centre (SSC), provides support to the drilling and well operations in the company.

The SSC is a hub for communication of knowledge between professional networks and the operational assets. The team work closely on drilling and well operational issues together with the operational assets within the company and contributes to experience transfer across the organisation. This gives the SSC team a unique opportunity to evaluate experiences and share the knowledge obtained. Every day 40–50 drilling and well operations are ongoing and the SSC is involved both in the planning and operational phases of these operations.

The main goal is to work proactively, by being involved early in the planning phase of each operation, hence contributing to reducing incidents and non productive time by doing things right the first time.

Real-time and memory data from all ongoing drilling and well operations in the company are available for the SSC team and are used both for monitoring of critical operations as well as for statistical and operational analyses to improve long term quality of the operations.

The technical collaboration systems in the SSC are suitable to manage collaboration, independent of different office and installation locations in the company.

The SSC has become an integrated part of the new organisation. The SSC is well known within the company and is involved in several operational and pre-operational cases every day. Many of the established key factors regarding Integrated Operations (IO) such as working in collaboration rooms, multidisciplinary teams, independence of physical location and decisions based on real-time data are incorporated in the work processes being performed in the SSC.

The SSC has introduced new work processes in the organisation contributing to increased efficiency and availability of expertise within the company. The work processes ensure high quality multidisciplinary discussions which enhances the quality of the recommendations to the operational assets.

Both discipline expertise and operational assets within the company are spread over several locations in Norway and internationally. It is crucial to ensure involvement of the correct expertise at the right time to achieve safe and efficient operations.

The SSC is an important part of the total development of IO for drilling and well operations and has been recognized for its innovative work processes and for providing efficient service.

The SSC has been recognized as a valuable asset and has become an important supplier of knowledge within the company.
Integrated Business Processes in Production Operations
Authors: Lauzon Stéphane , Broadway Gene
Published: April 2009

The paper will present an approach to integrating business processes across different functional silos in a production operations environment on a real-time basis: planning, well performance, allocation and accounting, maintenance and reliability, safety and compliance, etc.

Different systems and applications that have been deployed around the production unit in the field largely remain isolated in their silos and from business processes. Existing integration is often brittle point-to-point integration that is difficult to maintain when systems or applications at either end change. While this type of integration has allowed for a certain increase in efficiencies through automation, the future is too look beyond data integration to business process integration, bringing tighter integration between production processes and business processes, not just systems and applications, closer to real-time. Application and key metric information can be presented to reflect the different roles in an organization, and can be rolled-up to an enterprise level, or drilled down to a production unit level. Common views and data aggregated from real-time systems and business systems, accessible to different functions, provides a collaborative environment to enable quicker and more profitable decision making.

In this paper we will present the underlying technical foundations that make the integration possible and explore the integrated work processes that are now enabled.
Integration Is About People
Authors: Lameda Rufina , van den Berg Frans
Published: April 2009

Shell E&P operates a Smart Fields implementation program that integrates roles, activities and technology around key oil production business processes. One of the biggest challenges has been to follow up implementation of technology and processes with sustained change of people behaviour. The program has found a practical change management approach that achieves sustained integration that "sticks" beyond the lifetime of a specific implementation project.

Successful integrated teams are typically built on good leadership, clear goals, clear accountability, a sense of shared responsibility, and a no-blame culture. Most oil companies have such teams for individual projects. However, they struggle to achieve sustained team integration in routine operations. The project successes indicate that processes and technology are not the primary cause for this struggle.

Experience with integration programs around people, process, and technology suggest that two critical success factors are often overlooked. Firstly, oil companies need to develop measurable integration-oriented objectives. A typical example is integrated production system optimisation vs. optimising individual wells. Team members must be rewarded for realizing system opportunities even if those diminish the opportunities for their own areas of responsibility. Secondly, change programs must be followed up by regular intervention of leaders to ensure that the desired behaviour is sustained. Often this simply comes down to leaders asking questions that reinforce expected behaviour.

This paper discuss experience from projects in Africa, Asia, Europe, and the Middle East, sharing examples of measurable integration-oriented objectives as implemented in these projects: ➧Definition of objectives➧Implementation approach➧Mechanism for sustainability➧Learnings

We also present intervention cases that leaders should follow to show that they care about how results are being obtained, in the Smart Fields integrated way of working.
Strategies for Training Digital Petroleum Engineers
Authors: Ershaghi Iraj , Paul Donald , Mahdavi Mehrzad
Published: April 2009

Meeting current and future worldwide demand for oil and gas requires continuous improvement in the productivity of reservoirs and oil and gas operations. Upstream oil and gas operations are now focusing on the increased use of real-time information technology to the norm seen in many industries, including downstream manufacturing operations. Crossbreeding of oilfield science and culture and information technology is helping to implement advanced system engineering and optimization processes to total asset awareness for maximizing the performance of people and processes. This has opened up opportunities and requirements for the preparation of a new generation of petroleum engineers. There is a growing level of interest and curiosity from practicing petroleum engineers to understand and to potentially join the evolving professional track of digital petroleum engineers.

This paper brings points of view from the academia, industry and service companies to describe the opportunities, the Industry strategies, and approaches concerning the human element of applying digital technology. Strategies are discussed for training engineering graduates on the concepts and practices that are making this professional track perhaps the most evolutionary change in manpower training since the inception of the petroleum industry.
Control of scum accumulation in a double stage biogas collection (DSBC) UASB reactor treating domestic wastewater
Authors: Pereira J. O. , Celani J. S. S. , Chernicharo C. A. L.
Published: April 2009

This paper presents an innovative reactor concept which is based on a double-stage biogas collection (DSBC) device aimed at controlling scum formation and accumulation in UASB reactors treating municipal wastewater. Scum production inside a control reactor and a DSBC-UASB reactor was compared and much lower scum yield coefficients were observed for the DSBC-UASB reactor. However, the mass balance indicated that the dominant control mechanism was scum disaggregation and exit to settler zone rather than scum degradation.
The Suny Oneonta Second Life Music Project
Authors: Greenberg James , Nepkie Janet , Pence Harry E.
Published: April 2009

Do online virtual worlds represent a viable learning environment for higher education? Many Second Life classes resemble their real life equivalents, but some faculty are exploring the potential of virtual worlds for less-traditional teaching. This article describes one such effort, the SUNY Oneonta Music Project, in which faculty and students from several different disciplines combined their talents to create a special learning experience.
Building Social Capital through Online Class Discussions: A Little Freedom Goes a Long Way
Authors: Schoenacher Sheryl R.
Published: April 2009

Online class discussions have been studied from many perspectives; however, the literature is lacking that shows instructors how to help online students build social capital. Social capital is an information asset that stems from the interaction between agents. This study examines how social capital can be fostered through online class discussions. When students have a little freedom to lead their own discussions, the results are that they gain much more than a passing grade. Students learn that interactions with their classmates can be a source of valuable information. They use these online discussion experiences to broaden their own knowledge base and use this opportunity to find solutions to problems in their personal work environment. Using conceptual analysis, online discussion postings covering three semesters of an online Management Information Systems course were analyzed and the results categorized using a 6-dimensional model of social capital in order to ascertain whether social capital was being formed.