bluuebunny/crossref_metadata_2025 huggingface dataset:
Improving the Quality and Efficiency of Subsurface Workflows
Authors: Peterson R. D. , Yawanarajah S. , Neisch D. , James S.
Published: December 2007

The authors will show how a unique combination of real-time R&D coupled with strong asset team project alignment has the potential to result in significant improvements in the execution of Shell's Hydrocarbon Development (HD) and Integrated Reservoir Management (IRM) global processes in Shell's Deepwater Gulf of Mexico fields. The solution embodies technology enablers (Scenario and Options Evaluation, Decision Support Systems, Collaborative Environments), and organizational change (Intelligent Workflows, Research and Development, and new Business Models)

The solution consists of a Smart WorkFlow System (SWS), an Uncertainty Management Tool (UMT) and a Smart Collaborative Environment (SCE), all applied in the context of new collaborative work practices. The authors will elaborate how this integrated solution enables the asset teams to optimize their expenditure of scarce resources on the right reservoir scenarios and most relevant sources of risk, such as reservoir continuity or channel sand/shale geometries, all driven by group consensus. The collaborative environment improves execution of the HD and IRM processes through establishment of a common real-time team view. This view increases transparency of technical work, allows for real-time updates on progression of the risk mitigation plan, and allows for playback and critique of decisions in the context of an evolving shared earth framework. Rework is minimized, the efficiency and effectiveness of technical and business reviews are improved, and best practices are captured for global re-use.

The business model establishes a foundation for both Shell and Schlumberger to share the project risk and reward as the solution progresses from sandbox to prototype to commercialization. The authors will also elaborate on critical success factors in such a new collaborative R&D setting.
Towards a Framework for Better Decision Making Under Subsurface Uncertainty
Authors: Peterson R. D. , Yawanarajah S. , Neisch D. , Tabanou E. , James S.
Published: December 2007

The Smart Fields collaboration between Shell and Schlumberger is developing an Uncertainty Management Framework aimed at reducing both Hydrocarbon Development Planning cycle time and improving the quality of decisions made under uncertainty. The objective is to better manage the impact of the full range of project uncertainties on key development decisions.

Schlumberger, working closely with Shell, have developed an Uncertainty Management Tool (UMT) for the purpose of capturing uncertainties, their ranges, additional qualitative and contextual information, and associated risks and action plans. Uncertainty assessments are typically made during the course of discipline and application specific technical work. Whilst not performing uncertainty analysis itself, the UMT aims to maintain an internally consitent view of uncertainties throughout the multi-disciplinary reservoir modeling workflow, which is input to the field development decision making process. Teams would continue to use existing techniques and applications for uncertainty analyis (monte carlo simulation, experimental design etc) but use the UMT for tracking the reduction of uncertainty and risk over time. The UMT tool provides a central repository where this information can be collected, monitored and managed throughout the life of the asset, and archived for future analysis.

Another challenge faced by the asset team is in managing the large numbers of realizations that may be required in order to address the full range of uncertainty. This can be a laborious and time-consuming process, if it is attempted at all. The prototype has the ability to interactively create and edit a realization tree using captured uncertainty information.

The realization tree serves as a guide to the team as they construct their reservoir models. It also allows the team to conveniently track their progress, capture decisions made along the way, and work toward a final concept selection.

In addition to the prototype tool, a model-building workflow using Petrel was developed to assist in ranking and screening static model realizations prior to full dynamic simulation.
Challenges in Integrated Operations Centers
Authors: Landgren K. , Sood S.
Published: December 2007

Oil and Gas companies increasingly need environments that support real time E&P business processes, by linking well site information, applications, and experts with operational managers (decision makers) in one place, where daily operational parameters are viewed, decisions are made, and decisions are acted upon. Most companies believe that making decisions in real time while leveraging global resources and infrastructure will help improve their productivity from mature fields, while reducing costs.

Project team members are often collocated to ensure open communication and planning. However, E&P activities often take place in remote and hostile parts of the world, where it may not be possible or economical to deliver all the required resources and personnel. Global operations frequently require that operations centers be "virtualized" so the team members can be globally dispersed. Reliable and secure information flow is the key to ensuring success in the oilfield of the future.

Creating and supporting such integrated operations centers presents significant challenges in process, networking, security, hardware, and software infrastructure. For example, end-to-end real-time solutions require remote connectivity and "first mile" technology.

Successful creation of integrated operations centers requires clear definitions of the business processes to be supported and the infrastructure technologies needed to support them.

This paper discusses some of the special challenges faced in the upstream oil and gas domain, with examples of how some of the challenges have been met.
Beyond Temperature Sensors: Increased Efficiency in Mapping Flood Paths
Authors: Montgomery J. , Kofoed V. , Rollins P.
Published: December 2007

This paper will introduce a new procedure for mapping the flow paths of the steam, water and polymer floods frequently used in residual oil extraction. The procedure entails the strategic placement of electrodes within the designated oil reservoir. When the field is flooded, the electrodes charge the liquid with a low voltage, low amperage, audio-frequency electrical current. The current creates a distinctive magnetic field that represents the location and character of the flow occurring between the electrodes. This unique magnetic field is identified and surveyed from the surface using a highly sensitive receiver. This procedure can pinpoint the location of blockages and other problems more quickly and inexpensively than traditional methods, which typically rely on the intrusive placement of temperature sensors.

This procedure has been tested in a number of mature oil fields, including one near Bakersfield, California. In this case, the electrodes were placed in test wells that were specially designed to facilitate a charging of water vapor at various horizons. After the reservoir was flooded with high pressure steam, the mapping apparatus was able to take stratified readings of the magnetic fields created by the charged electrodes.

The procedure quickly identified a previously unknown subsurface structure that was effectively blocking the steam flow from reaching the intended solidified crude. The test thus established the new procedure's ability to map steam flows with greater speed and cost efficiency than traditional methods. The resultant maps were determined to be of equal or superior accuracy to those generated by the placement of temperature sensors.

One of the oil industry's most pressing tasks is to increase the yield from fields already under development. Such improved recovery methods hold significant advantages for both investors and the environment. Flooding is a proven method of extending reservoir productionlife. By providing a quick, efficient and accurate map of those flow paths, this new geophysical procedure represents an important forward step in the quest to teach "old reservoirs new tricks."
A Novel Approach for Analyzing the Dispersion Transport in Radial Coordinates
Authors: Garrouch A. A. , Guedouar L. , Al-Dousari M. M.
Published: December 2007

The finite-control volume technique is used to solve the radial convection-dispersion differential equation. In the dispersion model presented, the dispersion coefficient is dependent on both velocity and diffusion coefficient. The solution allows analyzing the dispersion transport of a slug in a steady radial flow from an injection well fully penetrating a homogeneous reservoir of uniform thickness and finite arial extent. Results show that the dispersive mixing zone does not necessarily grow in proportion with the square root of time for all times, unlike for the linear displacement. Results reveal a typical minimum of the dispersive mixing zone with time for radial displacement. It appears that at some radial distance close to the wellbore, the dimensionless mixing zone decreases with the square root of time since there is an accumulation of the miscible slug in this particular space domain. However, when the dissolution of the slug starts taking effect particularly at large distances away from the injection point, the mixing zone begins to increase with increasing square root of time.

Our solution of the convection-dispersion equation in radial coordinates allows to estimate the optimum slug size for miscible displacement projects in hydrocarbon reservoirs. This in return allows to estimate the total amount of solvent needed to maintain miscibility conditions at the displacement front in the bulk of the reservoir, leading to better reservoir management and to a more adequate economic forecast of EOR processes.
Drilling with Casing: Prospects and Limitations
Authors: Gupta A. K.
Published: December 2007

Drilling with Casing is a new technology used for simultaneously drilling and casing a well where the casing is used to transmit mechanical and hydraulic energy to the bit, instead of using a conventional drill-string.

The fundamental value of Drilling with Casing lies in improving drilling efficiency by eliminating flat spots in the drilling curve. It will eliminate the use of drill pipe, significantly reduce tripping times and reduce time lost due to unscheduled events such as reaming, fishing and taking kicks while tripping.

This technology utilizes a top drive to rotate the casing and uses a combination of traditional components such as standard oil field casing, bits, mud motors, MWD/LWD tools, as well as some newly developed components that allow drilling of most hole sizes from any drilling unit, with the ability to recover the drilling assembly using wireline. Since these tools are run and retrieved inside casing, they are protected from the harsh downhole environment while in transit. Casing drilling drill collars can also be used to add stability and to provide better fatigue resistance to the drill string.

This paper will describe the physical components and operational aspects of the drilling with casing system and its benefits over conventional drilling system. The anticipated results of drilling with casing are discussed and specific conclusions include in 20-30% reduction in the time required to drill wells from spud to rig release and up to 30% savings in well cost with improved reservoir productivity.
A New Scaleup Approach for Nonpattern Field Development Under Water or WAG Injection
Authors: Jhaveri B. S.
Published: December 2007

Full-field simulations have been successfully used to model reservoir development scenarios under water or WAG injection. When a reservoir is developed with regular patterns, reservoir engineers often build a type pattern model (TPM) and perform detailed, mechanistic, fully compositional simulation studies to understand displacement mechanisms. Simulation results from these mechanistic TPM studies are then scaled to full field to help design, develop, and manage the field waterflood or WAG injection projects. For a field developed with regular patterns, the scaleup of TPM results to the full field is quite straight forward; requiring identification and simulation of several different pattern types, followed by volumetric scaleup with tank models. However, when a field is developed with no regular patterns because of reservoir geology or other reasons, it is not clear how to apply the scaleup approach described above.

This paper presents a novel approach that uses simulation results from 2D (two dimensional) mechanistic models in conjunction with a full-field 3D waterflood study to describe the nonpattern field in a number of injector-producer segments. The approach also specifies the segment's initial pore volume (hydrocarbons and water), the injector, producer allocation factors, and recovery curves appropriate for the field development. For waterflood, the recovery curve is waterflood efficiency vs. cumulative water injected. For WAG floods, the additional recovery curve is EOR (oil incremental to waterflood) efficiency vs. cumulative solvent injected. Once the segment description with appropriate parameters is complete, it is straight forward to apply the tank model based scaleup approach to predict the full-field waterflood or WAG behavior. The paper presents the development and application of the new approach using example of a satellite field located on the North Slope of Alaska for a miscible WAG project.
Application and Development of Chemical-Based Conformance Control Treatments in China Oil Fields
Authors: Liu Y. , Bai B. , Shuler P. J.
Published: December 2007

China represents the largest user of chemical-based conformance control treatments and a series of technologies have been successfully developed and deployed in recent years. This paper will provide a review of current status of the application and development of chemical-based conformance control treatments in China.

This paper first summarizes types and development history of conformance control treatments. Then a series of technology information for conformance control is introduced, including reservoir evaluation and testing, conformance control agents, decision-making technology of well selection, operation design and evaluation methods of application results. This paper also addresses the theories and applications of some promising combination technologies of chemical based conformance treatment and another EOR/IOR process, including the combination technology of surfactant and water shutoff, profile control and mini-type surfactant flooding, acid treatment and profile control treatment.

Finally, this paper summarizes the problems and challenges that mature Chinese water flooded oilfields are facing. Based on recent well tests, tracer testing and interpretation, and previous water control treatment experience it appears that channels or high permeability streaks have been widely common in mature water flooded oilfields. Some research directions and promising technologies are suggested.
Investigation and Field Evaluation of a Foamed Viscoelastic Surfactant Diversion Fluid Applied During Coiled-Tubing Matrix-Acid Treatment
Authors: Nasr-El-Din H. A. , Chesson J. B. , Cawiezel K. E. , De Vine C. S.
Published: December 2007

When designing an acid treatment, the engineer often faces the question of what diversion method will be the most effective yet least damaging to the formation. Previous work has been published about evaluation methods, and conceptually diversion theory seems straightforward, but detailed post-job analysis and treatment optimization is often forgotten, especially when post-job production results meet or exceed expectation. Once a particular diverter is selected, the next question often is how much is required? If too small of volume is used, then treatment diversion will not be achieved. If too large of volume is used, then cleanup times and the risk of permanent damage increases.

Viscoelastic surfactants have recently become a popular additive for diversion pills, based on their polymer-free chemistry. Various formulations, including foam, have been successfully applied in acid stimulation treatments, but little post-job analysis has been published. Viscoelastic fluid properties vary over a pH range during acid spending on the formation and when foamed, determination of bottomhole properties is further complicated.

A tube viscometer and parallel core flow cells were utilized to determine the rheological properties and diversion effectiveness of various formulations of foamed viscoelastic surfactant at bottomhole conditions. An optimum formulation was determined, and this fluid was then applied and evaluated in a field application. A down-hole memory gauge was run during a coiled tubing acid treatment, and delta pressure changes were evaluated to determine the diversion effect.
A New Approach for Dynamic Optimization of Waterflooding Problems
Authors: Lorentzen R. J. , Berg A. M. , Nævdal G. , Vefring E. H.
Published: December 2007

Technological advances have resulted in use of smart wells, which are typically equipped with remotely operated downhole chokes. We present an approach for controlling these chokes so that the water flooding is optimized. The optimization problem is done by maximizing either total cumulative oil production or net present value.

The new methodology presented here avoids the limitations related to using optimal control as no adjoint equations are needed and the model equations are treated as a "black box".

In the new approach the ensemble Kalman filter is used as an optimization routine, and the methodology is compared to the Partial Enumeration Method.

We demonstrate the methodologies on a simple synthetic reservoir with five layers of different permeabilities. The conclusions from this work are that the ensemble Kalman filter approach is working robustly, and the results are in agreement with, or superior to, the results obtained with the Partial Enumeration Method and a reference solution.
A Multivendor Data-Exchange Format To Support Digital Oilfields
Authors: Weltevrede B. C. , Foreman R. , Morneau R. , Rugland B. , Booth J. E. , De Vries S. , Little T. , Ormerod L. , Doniger A.
Published: December 2007

Over the past decade the rapid evolution of Information Technology has enabled oil companies to much more effectively exploit hydrocarbon reserves than was possible up to now. These technologies all rely on an extensive set of instrumentation and controls.

The expected benefits of this novel approach to oilfield management are very high, but can only be harvested by means of an appropriate IT infrastructure and data exchange protocols.

PRODML (PRODuction xML) is a proposed data exchange mechanism which will facilitate the integration between software tools that are used in combination to turn raw production data into control actions.

PRODML intends to be an industry standard XML-based exchange format for production data. The scope of the first version of PRODML will be determined by what can reliably be delivered in a one year period.

This first version will support data exchange between applications in the office domain with emphasis on near-real time optimisation. In this context, near-real time optimisation is defined as optimisation that can be achieved by making changes in the existing production configuration that can be effectuated within one day.

The overall approach follows the successful example of the WITSML project, which established a similar set of specifications for the drilling domain.

PRODML was initiated jointly by BP, Chevron, ExxonMobil, Shell and Statoil in early 2005.

The initiative has since been joined by Halliburton, Invensys, OSIsoft, Petex, Schlumberger, Sense-Intellifield, Tietoenator and Weatherford, and is now in the process of developing the standard. POSC has agreed to take over stewardship of the effort once work on the first version has been completed and to foster further developments.

The paper represents the work of the entire team.
Rolling Anchor System
Authors: Bakke M. , Berg G. M.
Published: December 2007

The service industry continually strives to improve well service technology and help ensure that those developments can ultimately be deployed economically

The Rolling Anchor System (RAS) is designed to allow the use of Coiled Tubing (CT) in high torque operations where otherwise snubbing or conventional work over operations would be required.

The Rolling Anchor is designed to isolate the reactive torque generated by a motor from the work string, while at the same time allowing reciprocal movement of the bottom hole assembly (BHA). The Anchor is hydraulically activated by the pressure drop through the lower BHA (motor, mill etc.).

The Rolling Anchor System is patented in Norway, the USA and in the UK with Patent Pending status in several other countries.

This paper will provide a detailed overview of the tool’s design and discuss testing the tool has undergone to qualify it for service in various applications.
Utilizing Compositional Simulation for Material Balance and Bottomhole Pressure Calculations in CO2 WAG Floods
Authors: Kelly T. R.
Published: December 2007

In the current environment, carbon dioxide (CO2) flooding is gaining popularity as an enhanced oil recovery (EOR) technique worldwide. Despite this popularity, the complex phase behavior as well as reservoir and operational phenomena associated with CO2 flooding have dramatic effects on sweep efficiency, material balance calculations, and overall reservoir management. A technique for modeling the phase behavior of CO2 in injection wells was developed to address difficulties in material balance methods. Additionally, modification of the Cullender and Smith method of calculating bottom hole pressure (BHP) is proposed. The Peng Robinson equation of state is incorporated into the Cullender-Smith method to accurately predict CO2 phase behavior throughout the wellbore.

This technique uses the gas composition, temperature, and pressure from each injection well to calculate the volume factor at surface; additionally these parameters are used along with the wellbore configuration to determine BHP. This method greatly reduces errors in material balance calculations caused by using static rather than dynamic volume factors. Using this technique helps to maintain a constant BHP which facilitates volume-balanced injection cycles. In addition to injection rate, BHP targets can be set on continuous CO2 or water-alternating-gas (WAG) injectors such that it may be possible to establish and maintain a uniform flood front in patterns, no matter what fluid is being injected. In other words, the effects of reservoir heterogeneity, viscous fingering, and unfavorable mobility ratios are reduced by maintaining a constant BHP. A reliable knowledge of BHP is helpful in preventing injection above the formation parting pressure.
Modeling of Multilateral and Maximum Reservoir-Contact Wells in Heterogeneous Porous Media
Authors: Yang Y. , Deo M. D.
Published: December 2007

Maximum reservoir contact and multilateral wells offer more efficient production capabilities for certain classes of oil and gas reservoirs. These wells can be configured to have maximum contact with reservoir production zones. This is particularly important for highly compartmentalized, heavy oil, and off-shore reservoirs.

In computer modeling of reservoir production, traditional well models can only represent wells in directions that are parallel to the simulation grid which is usually not the case for maximum reservoir contact wells. An accurate well model that can effectively represent maximum reservoir contact and multilateral wells is necessary.

Current state of the art numerical well model for complex wells uses Green's function to compute the production index for each finite-difference block. The advantage of this approach is that the calculated production index fits naturally into the current finite-difference method used. The disadvantages of this method are such that it only partially accounts for heterogeneity, it is based on slightly-compressible single-phase flow and it sometimes generates negative production indices.

A novel line-well model for complex wells is proposed and studied. The line-well model places wells on the edges of computational blocks instead of centers as in traditional well models. This approach offers a physically meaningful yet simple way to compute production index for each individual segments of a complex well. This configuration also insures the proper handling of heterogeneity around wells. The line-well approach also allows easy implementation in both finite-difference and finite-element methods.

Verification of this well model for a traditional well arrangement with a commercial finite-difference simulator shows excellent agreement. Case studies show the efficiency and effectiveness of this well model in modeling reservoirs with multilateral wells.
Estimation of Relative Permeability from Displacement Pressure Data
Authors: Barroeta R. G. , Thompson L. G.
Published: December 2007

The solution of the inverse problem to estimate oil-water relative permeabilities, or history matching, has been widely used in the oil industry for many years. Usually, in this procedure, the production behavior, i.e., observed oil and water flow rates and pressure data versus time, is modeled and matched using a numerical regression process where the model relative permeabilities are modified until an acceptable solution is obtained. In some cases, only the production data versus time (without corresponding pressure data) are used to obtain the model relative permeability curves. To our knowledge, there have been very few instances where researchers attempted to use only pressure versus time data from core flood experiments (without the corresponding fractional flow) to estimate relative permeability curves.

In the laboratory environment, the pressure drop across a core during a displacement test can be determined with extraordinary precision - much more accurately than fractional flow data measurements. Since pressure measurements can be obtained easily, accurately and inexpensively, the number of data points collected during the experiment could be significantly increased, and also, data measured before breakthrough could be included. Based on this, a method has been developed to determine relative permeabilities through the solution of the inverse problem (numerical regression), by modeling, through the Buckley-Leverett procedure, the observed pressure versus time data only, and dismissing the recovery measurements. This approach significantly reduces the cost and time required to perform displacement experiments.

The results of the new technique, using power law representations for water relative permeability and oil relative permeability, are compared with relative permeability curves obtained using the standard history matching technique (finite difference simulator) and with relative permeability curves obtained using the standard unsteady state laboratory procedure (JBN). It is shown that there are only minor differences in the results, both from the point of view of the generated relative permeability curves and the estimated fractional recoveries, when the new approach is compared with the standard history matching procedure. Thus, the new method represents a viable and economically attractive procedure for determining relative permeability curves from laboratory displacement experiments.
Development and Installation of a High-Pressure-Rated Bridge Plug With Metal-to-Metal Sealing System
Authors: Adam M. , Lundemo K. , Mackenzie G. , Garfield G. L.
Published: December 2007

This paper will describe the development, testing and installation of a high pressure rated mechanical bridge plug for a major oil and gas operator on the Norwegian Continental Shelf. Due to low reservoir pressure a mechanical high pressure rated bridge plug was required to be set as a zonal isolation barrier prior to a frac operation.

The plug was set in a heavy wall liner with a 4.375" ID, but had to pass a 3.725" ID minimum restriction and hold 7500 psi differential pressure during the frac operation. The combination of high pressure rating and expansion ratio was a challenge to solve. A new metal-to-metal sealing technology was the solution to meet the required criteria.

In July 2005, the first plug was successfully set, conveyed on coiled tubing. This new plug technology has improved the way of performing the zonal isolation and frac operation in low pressure reservoirs.
Capability Development With Remote Drilling Operations
Authors: Lauche K. , Sawaryn S. J. , Thorogood J. L.
Published: December 2007

Improved capabilities for real-time data transfer have given rise to remote monitoring and support for drilling operations, providing faster access to information onshore, reducing personnel on board (POB) and cost. The challenge lays not so much with the technical feasibility but with the impact on work processes, which is still poorly understood. This study investigated the human factors implication for Onshore Operation Centres (OOCs) in four centres in Norway and the UK, which all successfully delivered wells but addressed different strategic aims.

The sample comprised 25 semi-structured interviews, observations over three months and a longitudinal attitude study with 33 participants. Results were content-analysed by a team of industrial psychologists. The findings show that remote operations in drilling produce similar effects as virtual teams and computer-mediated process control in other industries; the monitoring work in the OOC was deprived of some of the physical activity, sensory information and informal interaction. Potentially some of these tasks could be further automated while more cross-trained staff would be required offshore. Different user groups responded differently to the OOC implementation. Onshore teams generally approved of the concept as the OOC helped to create more situation awareness and present an ideal environment for collaborative decision making and learning. The offshore response was mixed, with both strong support for its innovative potential and critical voices about system reliability, contractual concerns and the impact on work-life balance.

OOCs can add value to drilling operations by enabling better-informed decisions but the findings showed that success depends on how well the introduction of organisational change is managed. The study provides evidence how prospective users can be involved in the change process in this dispersed and fluctuating industry and which social and cognitive skills are important for effective collaboration in e-operations.
Seismic Surveillance in the Field of the Future
Authors: Watts G. , Barkved O. , Dickens J.
Published: December 2007

Seismic 4D data has traditionally been acquired using repeat towed streamer surveys every 2–5 years. This is used to track fluid and pressure and has proved highly effective for influencing infill well locations and calibrating the reservoir simulator. Over the last 10 years the technology has evolved and is now relatively mature with several well documented case-studies demonstrating value of 3–5% reserves increase in post-plateau oil fields with a strong fluid response (1).

However, the long elapsed time between surveys limits its value in Reservoir Management where we would like to use time-lapse seismic to monitor the pressure field and the fluid flood fronts and therefore make decisions which maximise the sweep conformance and achieve ‘technical limits’ rate and reserves.

To do this, seismic data needs to be acquired at a frequency consistent with the timescale on which the decisions are made. Thus monitoring gas movement to minimise gas production in oil field may require seismic surveys every 3–6 months whilst providing data useful for optimising Base Well Management decisions on reperforations, restimulations, water shut-off and injection rates may benefit from seismic data every few months or even weeks.

As a first stage towards active management using "seismic surveillance", and specifically to aid in waterflood management, BP has installed a permanent seismic array over 70% of the Valhall field. The array cost $45million but the results have been technically spectacular (2, 3, 4). Learnings from this experience are still evolving but already cover aspects of reservoir management, infill drilling, Base Well Management, flow performance prediction and surveillance including the use of "Seismic PLTs" (2).

Following on from this success, BP is looking at the next wave of field applications as an integrated part of its FIELD OF THE FUTURE programme (5). Plans are now at an advanced stage to take forward two new projects in 2006 and several more are being discussed for application later this decade.
The Challenges of Implementing at Scale: Field of the Future—Technologies in the North Sea
Authors: Dudley G. , Perry J. , Goodwin S. , Critchley C. , Hocking P. , Shahly M. , Barkved O. I. , Saul D.
Published: December 2007

For BP the North Sea is an important mature basin which produces around 15% of the company's total global production of around 4000 mboed. However, like many mature basins sustaining a profitable and competitive future is challenged by the overall decline in oil and gas production rates, increasing trend in unit operating costs, the integrity and operability of the ageing infrastructure and the changing demographics of the work force. In this perspective, North Sea has become a key exemplar that illustrates how BP's FIELD OF THE FUTURE programme can help to meet numerous challenges in the management of mature areas.

To help manage and reduce the negative impact of these business challenges BP is implementing a North Sea regional FIELD OF THE FUTURE Technology programme. The vision over the next 5 years is to deploy FIELD OF THE FUTURE technologies at scale across most BP operated fields with the aspiration to improve overall production by 5% and reduce operating cost by 10%.

For the North Sea mature assets the main focus is around four technical projects: Advanced Collaborative Environments (ACE); Real time data monitoring and surveillance; Advanced control and optimization; Automation and remote control. From the outset BP has discovered many challenges in deploying and implementing at scale across a region. This paper will share some of the key challenges and insights involved in implementing at scale the technical projects through the appropriate process, organisation capability and technology across the region.
Intelligent-Well Technology: Are We Ready for Closed-Loop Control?
Authors: Going W. S. , Thigpen B. L. , Chok P. M. , Anderson A. B. , Vachon G. P.
Published: December 2007

Over a few short years surface control of the reservoir by intelligent well technology has become a reality allowing improved efficiencies and economics by well documented measures. Downhole control valves have evolved from simple open/close zonal control to downhole chokes that allow metering of fluid rates from or to multiple producing zones. Complementary instrumentation of the wellbore provides real time data for pressure, temperature and flow. These capabilities along with computational and communication technologies provide the necessary ingredients to allow remote control of production in a variety of settings. In addition to remote control, the opportunity also exists to automate production even to the extent of closed loop control. As the complexity of surface controlled reservoir control valves has increased, so has the frequency of operators selecting microprocessor controlled surface hydraulic control systems to manipulate the valves. With microprocessor control in place at the well location, remote control options become the next logical step in the evolution of intelligent wells. Once remote operation has been chosen, the options for system architecture and communication are quite extensive. Successful implementation is a matter of effective interface engineering between the operator and the various service providers. Lessons learned in developing remote control solutions will be presented along with an outline of the remaining steps that will be needed to implement closed loop control.
Wireless Condition Monitoring
Authors: Cassar Harry Michael Paul
Published: December 2007

A 130,000-ton oil tanker might be a surprising place to find cutting edge wireless technology, but on BP's Loch Rannoch the world's first maritime "mote" network was developed to prevent critical machinery breakdowns before they happen. Standard monitoring practice is manual and time-consuming, an innovative solution developed by a BP-led team of BP, Intel, Rockwell and Crossbow applied leading edge sensory network technology to create the world's first mote network onboard an oil tanker. Rotating machines begin to vibrate imperceptibly as bearings wear and shafts become mis-aligned. Accelerometers placed on critical machinery capture equipment vibration, the data is passed wirelessly through a mesh-network to a datalogging computer so that machinery status can be monitored every day rather than manually every six weeks. ---helping improve preventative maintenance and safety!

Given the large number of rotating machines on modern oil tankers, it is not feasible for the crew to take readings more than every six weeks using hand-held dataloggers. Faults can develop up to six weeks before detection. Some machines require engineers to take measurements in confined or awkward spaces; wireless sampling removes this safety risk.

30 motes were installed in engine room locations logging vibration signals from 98 accelerometers for 5 months. The wireless, battery-operated motes allowed for rapid installation (17 hours) where traditional wired solutions were not feasible. Motes enable much more frequent sampling (every 6–18 Hours), increasing the quality of predictive analyses and enhancing our ability to spot machine defects early on before serious damage.

Loch Rannoch is an example of how the FIELD OF THE FUTURE programme develops technologies to improve management of BP's assets.

This paper describes the challenges faced in modern day operations and how BP is beginning to face these challenges with modern mesh sensor net technology.
Next-Generation Fluidic Oscillator
Authors: Webb E. D. , Schultz R. L. , Howard R. G. , Tucker J. C.
Published: December 2007

This paper describes the development of a downhole cleaning device based on fluidic oscillation. This fluidic oscillator is used for removal of deposits from the near-wellbore area, perforations, and screens. The cleaning device creates pressure waves within the wellbore and formation fluids that (1) break up near-wellbore damage and (2) restore and enhance the permeability of the perforations and near-wellbore area.

Fluidic oscillators have been used for various purposes in a wide range of industries for many years. They typically exhibit reliable oscillation over a wide range of flow rates and have no moving parts. The cleaning tools presented here are specifically designed for high-pressure, submerged operation and maximum pressure-pulse amplitude. The unique design has been carefully refined through theoretical and experimental methods.

This paper discusses fluidic oscillator theory and presents a numerical analysis of a specific oscillator design, as well as an analysis of experimental test data at various flow rates. The provided case histories demonstrate the utility of fluidic oscillation as a wellbore-cleaning device.
Innovative Approach to Assist History Matching Using Artificial Intelligence
Authors: Al-Thuwaini J. S. , Zangl G. , Phelps R.
Published: December 2007

The study objective is to investigate the use of Artificial Intelligence (AI) methods to accelerate the history matching process.

A new criterion for measuring the deviation of the simulation model from measured and/or observed parameters has been introduced. Instead of comparing parameter deviations in wells to input changes on regional basis, it is proposed to calculate a regional RMS (Root Mean Square)-error, so that the impact of input changes can be directly evaluated. Instead of grouping grid blocks based on geology, it is proposed here, to generate regions of similar trends based on all available information. Artificial intelligence (AI) is used via Self Organizing Maps (SOM) to cluster grid blocks of similar behavior. SOMs can process any kind of information; in this case these types of parameters have been particularly used:

geological description: lithofacies type hydraulic flow units (HFU): permeabilities, porosities initialization: water saturations (initial and critical), initial pressure discretization: spatial discretization (e.g. DZ), grid block pore volumes secondary phase movement: relative permeability endpoints

A three fold approach for improving and/or assisting the history matching (AHM) work-flow using Artificial Intelligence has been tested:

Use production plots, Neural Networks and "Material Balance with Interference (MBI) method for quality control and consistency check of time dependent and static data. Use the multi-dimensional cross-plot and SOM to evaluate reservoir and well performance. Use SOMs and the region RMS error to evaluate the performance of history matching runs.

This new approach is simple and leads to a clear improvement of the match quality and significantly reduces the number of runs needed to achieve the match. Different field models have been used to develop this new AHM workflow. Finally in this paper, two of them are selected to demonstrate the improvement of model pressure and watercut matches using this new method.
Identifying Future Leaders Through Knowledge Management
Authors: Paylow K. , Hickman A. , Zappa D.
Published: December 2007

Simply retaining knowledge within an organization is not enough to ensure its survival unless talented employees are ready to leverage that knowledge. Changing demographics within the petroleum industry raises many concerns for the coming decade including the identification, development and retention of an organization's future leaders.

An existing, advanced knowledge management (KM) community gives an organization's upper management a unique view into key employees' ability and willingness to solve technical problems, communicate, innovate, influence peers and lead group consensus. Disciplined review of collaborative efforts captures peer recognition and provides a more impartial means of generating a list of talented personnel who exhibit leadership qualities and technical ability. This informal list can be used to complement formal succession planning, generating a wider base of candidates and enhancing the selection process.

Examples demonstrate how this application of KM identifies ‘natural thought leaders’, evaluates candidates for key positions, and develops succession plans for future leaders who will drive the direction of the organization.
Production Planning in an Operations-Centre Environment
Authors: Fløysand I. , Nordtvedt J. -E. , Sekkingstad F.
Published: December 2007

The real-time asset management (RTAM) domain has received a lot of attention over the past several years. A key RTAM component has been the uptake and utilization of operations centers for implementing new work processes. In early stages of this development, the operations centers have been utilized for conducting, e.g., morning meetings and increase the communication between the asset and operational teams (e.g., between onshore and offshore teams). In this paper we will address how existing work processes can be implemented in new ways in such environment, in an attempt to take advantage of the new communication opportunities and data and model availability.

Our focus is on parts of the production optimization work process, namely that connected with production planning. Production optimization requires knowledge of well behaviour and topside processing constraints. The production engineer must consider all wells simultaneously in order to optimize the production from the wells to the processing plant. The objective is to use the equipment effectively to maximize oil and gas production. Finding the operating conditions where this is achieved, requires an integrated production planning-with participation from production engineers, reservoir engineers, offshore operators, and topside processing engineers. A typical challenge related to this is the lack of a common framework for integration of work processes between the disciplines, preventing decisions to be made based on a common view of the status and challenges ahead. This paper outlines how this challenge can be addressed using a real time system approach to production optimization work processes. Features of the real-time system will be described and a new work process for production planning using this system will be outlined.
Should "Proactive" or "Reactive" Control Be Chosen for Intelligent Well Management?
Authors: Ebadi F. , Davies D. R.
Published: December 2007

Intelligent Well (IW) Technology combines zonal production control using Interval Control Valves (ICVs) together with installation of appropriate flow monitoring devices to improve well and field performance management. Zonal flow control can maximise produced oil value, minimise unwanted fluids or a combination of both objectives.

We have previously shown1 that a minimum degree of un-evenness of an invading fluid front is needed for effective ICV control. This work studies scenarios to identify when "Proactive" rather than "Reactive" ICV choking policy can add greater value. Reservoir scenarios were created in which inter-zone connection, permeability contrast between zones, zonal length and other reservoir parameters were systematically varied. The interaction between the aquifer and reservoir was observed when producing these reservoirs with a horizontal IW using a range of "Reactive" and "Proactive" choking policies.

An example of successful "Proactive Control" is when the wellbore is intersected by a high-permeability channel. Here, early water or gas breakthrough leads to unwanted fluid being produced along with reduced volume of oil. Too early choking (or being "too Proactive") can result in losing oil as the "Good Water" is also blocked. "Proactive Control" will also be successful when reduced water or gas inflow is required due to tubing or surface handling limitations.

The key factor in successful Single Well "Proactive Control" is that other zone(s) can compensate for the loss of fluid from the choked zone(s). Its value thus increases when Artificial Lift is installed.

The value of "Proactive Control" is well known in multiple well scenarios. Here, value creation requires even-flood front management of an injected fluid at the field level. There is also the opportunity for other wells to supply extra oil production capacity when a (single) well is choked.

The results from this study can be used to screen for scenarios suitable for "Proactive Control", increasing the range of Intelligent Well Technology applications.