bluuebunny/crossref_metadata_2025_split huggingface dataset:
The BP FIELD OF THE FUTURE Programme: The Continuing Mission To Deliver Value
Authors: Dickens Jeff , Latin David , Verra Graeme , Blosser William , Edmonds Greg , Grimshaw Greg 
Published: July 2010

Abstract
BP's digital oilfield initiative, the Field of the Future Technology Flagship, has been developing and deploying distinctive operational capabilities since it's inception in 2005. This paper describes the growing track record of value delivery, achieved through pace and scale deployment. These capabilities, which continue to be developed, support a relentless drive for continuous improvement in our asset operations, aiming at delivery of significant production (100mboed BPnet) and reserve (1bnbbl) targets by 2017. We report significant progress toward meeting these targets and highlight new key lessons from our growing body of experience.
The Field of the Future concept is now a routine part of how BP builds projects and operates fields across much of our portfolio. It impacts a significant and growing proportion of net production and routinely supports &gt;80% of our top 100 wells. A range of monitoring, analytical, optimization and collaborative solutions are applied according to asset needs and value opportunities.
The in-house solutions have delivered over a third of the production target so far - ahead of plan. When integrated with general bought-in solutions, base infrastructure and collaboration benefits, we are routinely adding more than 50mboed gross production per annum.
The Paper presents examples of the variety of capability, technology and solution applications that have underpinned this continuing successful value delivery.
Key to this success has been: Establishing an effective, balanced approach to R&D, deployment and value realization;Developing clear linkage to business needs and functional priorities as a basis for effectively engaging the customer.
Areas of continuing challenge include: Sustaining uptake and usage when faced with issues and barriers arising from technical, business and organizational diversity in the asset portfolio;Competing or aligning with other business priorities and initiatives, especially in a cost challenged environment.
Looking forward, the common challenge all operators face is firmly on making it an industry-wide reality, and to fully embed "intelligent energy" in all that we build and operate.
Model Based Operational Support - Adding Assurance to Operational Decision Making
Authors: Stenhouse Bryn , Woodman Malcolm , Griffiths Peter 
Published: July 2010

Abstract
Managing and optimising BP's integrated operations presents an increasingly complex challenge with the move to deeper- water production and the use of sub-sea processing and multiphase tiebacks from satellite fields. Production system optimisation requires the simultaneous assessment of flow stability and well draw-down maximisation whilst honouring the constraints of reserves recovery though the reservoir management depletion strategy.
BP has a strong track record of applying fundamental mechanistic models to support operational decision making and optimisation. When reconciled with real-time and historical production data, physical models of a production system increase operators understanding of the system and allow changes to operating strategy to be made with increased confidence. Moreover, inferred model parameters can be use to track the health and efficiency of component parts of the system feeding an enhanced predictive maintenance capability.
Mechanistic models of a production system are themselves complex and challenging to use and maintain. Normally their use is restricted to modelling experts primarily for design purposes or to support troubleshooting following a production upset condition. Delivering such models for use within an operational environment requires a large number of issues to be addressed, in particular how such models can be applied quickly and robustly with assurance, and how they are scoped and maintained.
This paper outlines how BP E&P is tackling these issues through the Field of the FutureTM Model Based Operational Support programme as the capability is deployed further within the Upstream organisation.
Enough is Enough: Data Sufficiency
Authors: Bailey Richard , Ziegel Eric , Sprague Kip , Hedges Bill 
Published: July 2010

Abstract
BP can now target its corrosion inspection program on pipelines where there is a statistically validated shortage of data. Resources can be shifted from lines where the same statistical approach indicates that adequate quantities of data have already been acquired. This exciting capability has been realised and trialed by the FieldoftheFuture flagship technology team and builds on its successful track record of working with large quantities of data from real time applications. What has been demonstrated is that BP's experience with real time process data is equally applicable to very large databases of historical inspection data. Strategies can be developed that respond to the most recent inspection results as these are acquired.
A Step Forward in Collaborative Well Planning: Deployment Challenges Under Windows Platform for Drilling Application in the Ekofisk Operations
Authors: Lahlah Nour-Eddine , Herbert Mike , Bashford Karen 
Published: July 2010

Abstract
The implementation of a 3-D visualization platform for drilling application within the Onshore Drilling Center in Tananger was among one of the targets in the new plan for enhancing the drilling efficiency and evaluating NPT. The most challenging step was to deploy collaborative well-planning software under a Windows platform in addition to the interaction between the Norway database and the drilling application.
The implementation process of the visualization platform was carried out by deploying Windows machines in different locations. The challenge faced was the connectivity between the global database and the drilling platform. This implementation follows the Integrated Operation vision, which is enabled by connectivity, collaborative technologies, and multi-discipline workflows.
Historically, this visualization platform under Linux has been used by the GGRE (Sub Surface and Reservoir Evaluation) engineers, but not deployed through the drilling community. This paper discusses the new synergy of enhancing the collaborative work in logical steps. The first step is to provide the appropriate hardware and software for the integrated operation, and the second step is to accommodate the new tools within the ODC workflows.
Another way of working is starting to take place through bringing GGRE and drilling staff engineers together. This collaborative well planning requires the coordination of different operating platforms, databases, disciplines, and hardware to ensure effective well planning. Specific operational preparedness and coordination are needed prior to the well session.
The live well planning sessions illustrate how the reservoir team, overburden team, and drillers can all work together on the plan simultaneously through importing or exporting targets from the drilling database. Different platforms can be used during the well planning session to allow for free access to G&G data, third-party data, and well planning data through the use of a visualization drilling engine.
The case history provided in this paper discusses how real-time visualization was used to monitor drilling trajectory with a geological model.
A New Approach to Knowledge Capture: Center of Excellence for Sand Control Completions as a Model
Authors: O'Neill Dennis M. , Walls Lauren R. , Sickle Ed Van , Baker Brad 
Published: July 2010

Abstract
In large global organizations, experts who collaborate with their colleagues in the Digital Oilfield of the Future (DOFF) are geographically dispersed and mobile. Their time is precious and they cannot readily be distracted from their primary functions to participate in traditional knowledge-capture activities. Therefore, it is extremely desirable to automatically identify these experts, capture and codify their knowledge, and provide access to them from anywhere in the world at the time their knowledge is needed. This paper describes a new approach to this challenge.
We investigated a number of approaches including a prototype system to automatically identify communities of interest, capture and index the electronic documents relevant to the community of interest, and populate a globally accessible "knowledge space." This knowledge space provides a mechanism to access the relevant experts in real time using location-/presence-aware collaboration tools.
We evaluated this method in the context of establishing a Center of Excellence for Sand Control Completions. In establishing this Center, we began using conventional techniques. This initiative, however, was also viewed more strategically – as a vehicle for establishing "a new way of doing business," and it also served as a platform for testing approaches that would allow us to rapidly deploy the solution to other domains.
This exercise demonstrated that significant improvements can be made in collecting, organizing and disseminating actionable knowledge from a dispersed community of technical experts. It also provides a real-time mechanism for leveraging the implicit knowledge of these experts in a globally mobile workforce. This has significant relevance in the DOFF arena as it enables an organization to "know what it knows" with less effort than traditional knowledge management and collaboration tools.
Well and Reservoir Management Project at Salym Petroleum Development
Authors: Mabian Andrew , Volokitin Yakov , Beliakova Natalia , Genkin Jean-Mark , Hagelaars Ad , Pickles Mike , Diamond Joe 
Published: July 2010

Abstract
Salym Petroleum Development (SPD) has embarked on an ambitious Oil Field Management Improvement Program with as key objectives to: Optimise Production (2.5% additional production through reduction of Locked-in-Potential and better reservoir pressure maintenance; unscheduled deferment less than 1% through reduction of ESP trips).Increase Ultimate Recovery (Increase RF by 1%; platform for future EOR project; robust basis for infill drilling).Reduce OPEX (increase ESP mean time between failure; contain chemical consumption costs; in field staff journies reduced by 10% /annum; less than 3 non-critical loss of integrity incidents per year).
The goal of this paper is to present SPD's approach to Oil Field Management in the context of a West-Siberian water flood. Oil Field Management is based on the Value Loop (Figure.1) where data is acquired from physical assets (reservoir, wells, facilities) and subsequently incorporated into models that drive the optimization of these same physical assets. The value loop has different cycling times ranging from seconds to decades (Figure.2). Traditionally, the shortest value loop is called Real Time Optimization ("RTO") with a time span measured in seconds, minutes and hours, followed by Well and Reservoir Management ("WRM") with a time span measured in weeks, months or years, and finally Hydrocarbon Development Planning ("HDP") with a time span measured in years, if not decades. Figure.1Value LoopFigure.2Cycling Time
Energy and Environment: The Ultimate Test of E&P "Intelligence"
Authors: Kapteijn Pieter 
Published: July 2010

Abstract
In the next few decades the E&P Industry will face a unique confluence of two major challenges: it must continue to provide the world with sufficient oil and gas to support global development, while at the same time help it reduce the environmental impact of fossil fuel use, with a focus on the reduction of green-house gas CO2 emissions. This calls for innovative technical solutions and new approaches to the design and management of increasingly interdependent energy- and CO2 value chains.
The "intelligent" capabilities that the industry has developed over the past decade can be leveraged to meet these twin challenges. The combination of CO2 EOR with Carbon Capture and Sequestration (CCS) in particular, offers attractive opportunities to combine enhanced oil- and gas recovery with GHG reduction, in a profitable way. This can be done at the level of individual field developments but also at the level of integrated energy/CO2 systems.
The technical and economic implications of an "eco-efficient" approach to the design of CO2 EOR projects are discussed, taking a North-Sea EOR feasibility study and CO2 supply project example. These types of projects greatly benefit from "oilfield intelligence" to improve ultimate recovery and optimize CO2 capture, use and storage.
It is concluded that eco-efficient and intelligent technical and commercial design will have to become a core capability of the E&P Industry.
Single-Well In-Situ Measurement of Residual Oil Saturation after an EOR Chemical Flood
Authors: Arora Shyam , Horstmann Dirk , Cherukupalli Pradeep , Edwards John , Ramamoorthy Raghu , McDonald Tom , Bradley David , Ayan Cosan , Zaggas John , Cig Koksal 
Published: July 2010

Abstract
The MicroPilot* is a log-inject-log technique providing a single-well in-situ measurement of enhanced oil recovery flood geometry and changed residual oil saturation. The fluid to be injected is transported downhole in a sample chamber and injected into the formation through a pencil sized hole. Borehole electric images and high resolution saturation logs are recorded before and after fluid injection. The logs show the change of residual oil saturation. The dimensions of the swept zone and surrounding oil bank are visible on the borehole image. These dimensions and saturations can be used to history match the reservoir simulation of the EOR process.
Thermal Developments in Petroleum Development Oman's Southern Fields - An Update
Authors: Thum M. , Leith E. S. , Van Wunnik J. N. , Mandhari M. S. , Clark H. P. 
Published: July 2010

Abstract
A programme of thermal developments is being rapidly matured in Petroleum Development Oman's (PDO) Southern Oil Directorate. This targets several billion barrels of heavy oil deposits in clastic reservoirs at depths between 800m and 1800m. Cyclic steam stimulation and steam drive applications dominate the current development program. High-pressure steam injection and air injection applications are also pursued in some fields through studies and laboratory experiments.
Steam trials in three heavy oil fields spearhead the thermal developments and results are presented. These steam trials provide further insights to optimise the ongoing full field developments. The paper also describes a portfolio management approach to thermal developments, given that many of the target fields are in close proximity and can share the same infrastructure and development methodologies.
One of the main heavy oil full field developments has been matured from a Feasibility stage to Final Investment Decision in just three years. In this particular case, unique opportunities and challenges for thermal development arise due to the depth and thickness (200m) of the heavy oil column, with an underlying large regional aquifer. Specific topics addressed include thermal well cost reductions, urban planning, minimising additional gas requirements through COGEN, water management, development of a new Operating Model for Lean Steam Well & Reservoir Management and Operations, and overall integrated project management.
SAGOGD Feasibility in a Sparsely Fractured Carbonate Reservoir with a Thin Oil Column
Authors: Said Dhiya MM , Van Wunnik Johannes M 
Published: July 2010

Abstract
The field under study is a fractured carbonate of low matrix permeability (∼15mD) and modest fracture permeability (&lt;1200mD). The structure is relatively flat with a maximum movable oil column of 60m and a median thickness of 30m and is underlain by a strong aquifer. The live oil viscosity is 7cp. To date the field has recovered a small fraction of its STOIIP, mostly under natural depletion and WOGD. The field is scheduled for re-development by Cold Gas-Oil Gravity Drainage (CGOGD). The feasibility of a later phase of development by Steam-Assisted GOGD (SAGOGD) was evaluated and is the subject of this paper.
The field's reservoir properties present a unique set of challenges for an SAGOGD development. Firstly, the relatively low oil viscosity at initial conditions is unfavourable for a large viscosity reduction by heating. Also, the extent of the structure together with the modest fracture permeabilities complicates the spread-out of steam over the field. Finally, heat transfer efficiency to the matrix is problematic given the small thickness of the reservoir and the large matrix blocks.
The SAGOGD development strategy calls for simultaneous gas and steam injection by injectors that are spread out over the field, which stabilises the oil rim, spreads out the steam and reduces aquifer water influx. The incremental recovery over CGOGD was demonstrated to be substantial (16% of STOIIP) with an acceptable oil-steam ratio. Analysis of physical processes contributing towards recovery showed that viscosity reduction was still the main contributor to oil recovery.
Significant uncertainties remain to be reduced before committing to an SAGOGD development. Besides the wide range of uncertainty in incremental recovery (+/-60% from the base case), water supply and disposal requirements are major challenges for the steam project. Whilst these latter are being evaluated, the initial phase of CGOGD will narrow subsurface uncertainties for SAGOGD development substantially. In this paper the subsurface elements of the study will be discussed.
Steam Flooding a Thick Heavy Oil Reservoir: Development of Numerical Tools for Reservoir Management
Authors: Al-Hinai Suleiman M. , van Wunnik John , Al-Shureqi Hamed 
Published: July 2010

Abstract
In a number of fields in Oman thermal developments are being implemented. One of these fields is located in South Oman and contains an exceptional 200 m thick oil thick column of medium to heavy oil (200 to 800 cp). This sandstone reservoir is at a depth of 1050 m below surface and is underlain by a modestly strong aquifer. The field has been in production for 20 years, the main production mechanisms are pressure depletion and natural ingress of aquifer water. For the next phase of development a vertical pattern steam flood re-development is planned which will increase the ultimate recovery significantly. The extreme thickness of the heavy oil reservoir is unique for steam floods and poses both opportunities as challenges. There are no direct analogues and the normal practices of managing a steam flood need to be verified and adjusted. For that reason a range of numerical tools has been developed.
The tool box consists of: 1) An explicit well bore model to understand e.g. the internal well fluid dynamics and heat exchange between tubing, annulus liquids and reservoir fluids at the reservoir level as well as the overburden. Particular interesting is the impact of cool aquifer water inflow on condensation of steam in the annulus and near well bore area. 2) Radial models for detailed analysis of recently performed steam soaks. 3) Sector models (1/12 pattern) for capturing overall steam flood performance and to understand the impact of fine scale reservoir heterogeneity, 4) A single pattern model for analysis of the ongoing steam flood trial in the field and 5) A 10- pattern model cut-out of the geological model for understanding of pattern interference and impact of major reservoir features like faulting and structure. The models have been constrained by the long production history of the field. The performance of the tools is illustrated by the work-out of some specific well and reservoir management examples.
Polymer Injection in Heavy Oil Reservoir under Strong Bottom Water Drive
Authors: Al Azri N. , Jamal E. , Murshidi A. , Al Mahrouqi A. , Al Busaidi I. , Kazzaz A. , Al Ajmi W. , Ramalingam S. , De Kruijf A. , Al Kharusi B. , Brooks D. 
Published: July 2010

Abstract
Implementing Enhance Oil Recovery techniques in heavy oil reservoirs with strong bottom water drive has been a challenge in the oil industry. This paper describes an Enhanced Oil Recovery process in which polymer is injected into a clastic reservoir with a strong bottom aquifer drive bearing heavy-oil (250-500 cP). The high reservoir permeability (2-5 Darcy) enables stretching the viscosity limit of a standard polymer application.
The presence of a strong bottom aquifer maintains high reservoir pressure, which could provide a challenge to injectivity. The close proximity of injectors to the oil water contact reduces the efficiency of the polymer flood through water fingering, and polymer loss to the aquifer. To best understand details of the influence of aquifer on the recovery process, test different development scenarios and address key uncertainties, detailed simulation study was conducted. The simulation results showed that the optimum development concept which would help reduce impact of polymer loss to the aquifer would be to utilize the currently existing and future horizontal producers, augmented with additional infill horizontal injectors placed approximately mid-way in the oil column. Optimization of the development was performed using the simulation model where the polymer viscosity, slug size, and injector location were optimized for net present value.
Uncertainty analysis using the simulation model showed that factors such as poor injectivity, poor conformance control and high kv/kh ratio have negative impact on process efficiency. To address and mitigate these key risks and uncertainties a number of activities are underway. These activities include intensive laboratory tests, field injectivity test and a field trial where polymer is injected in newly drilled injectors. The paper discusses study to identify the optimum development concept, key uncertainties and associated risk reduction activities. Finally, this paper discusses the design and the surveillance aspects of the upcoming field trial.
Application of Novel Chemical and Mechanical IOR Techniques to Northwest Louisiana Fields
Authors: Reynolds Jay C. , Berger Paul 
Published: July 2010

Abstract
The Nacatoch B formation in the Caddo Pine Island oilfield is a semi-consolidated, massive blanket sand containing 20–22 API gravity oil with an active water drive prone to rapid radial matrix coning. The area has been very intensively drilled with well spacings as high as seven per acre affording excellent mechanical access to the reservior.
Chemical IOR in combination with an innovative, one man deployable, corrosion-proof production system requiring no workover rig was employed to allow rapid evaluation of reservoir response to the chemical treatment employed.
Analysis of oil and water was conducted and the surfactant SS 1688 from Oil Chem Technologies was chosen for this set of trials.