bluuebunny/crossref_metadata_2025 huggingface dataset:
Integration of People, Process and Technology for Right-Time Production Management and Optimisation in Brunei Shell Petroleum
Authors: AlKhadhuri S. , Narasayamy D. , Said Sheik-Mohamed Sheik
Published: December 2007

Intelligent wells and Smart Field concept have been introduced, and recently applied in some assets as a solution to increase production, reduce deferment and increase recovery. The value of Smart Field however can only be fully realized by integrating three main elements, Technology, Process and Resources. Combining subsurface smart well technologies, real-time data gathering, integrated modeling and control elements through appropriate resources and skills are core to close the smart field value loop and will result in better optimization, cost saving and enhancing ultimate recovery.

Brunei Shell Petroleum (BSP) is a regional lead E&P Company and one of the Shell Companies to apply Smart Field value loop concept. Smart well applications have been implemented for a long time before in BSP. In mid 2003 BSP have taken further steps beyond Smart Well applications, when smart field value loop concept has been initiated in its East Asset. Subsurface smart well technologies, surface control engineering and real-time application systems have been integrated to achieve higher production gains, cost saving and enhance ultimate recovery.

The smart field philosophy is not only about automation, it is about making available the three key ingredients that are needed to efficiently operate any machinery: reliable performance data, an integrated suite of tools to turn these data to information and operational advisories and a cadre of appropriate skilled professionals that use the information to make the right decisions.

The objectives of this paper are to share the experience on smart field applications and operations in BSP, demonstrate the value of integrating Smart Field elements, demonstrate the importance of team integration to achieve the value loop and share the challenges encountered, lessons learnt and recommendations.
Drilling High-Angle Casing Directionally Drilled Wells With Fit-for-Purpose String Sizes
Authors: Borland B. , Watts R. , Warren T. , Lesso B.
Published: December 2007

This paper discusses the design and testing of 10 ¾-in. and 7 5/8-in. casing directional drilling equipment and procedures that ConocoPhillips plans to use on a mature North Sea asset. ConocoPhillips has worked with Tesco Corp. and Schlumberger in building the tools necessary to complete this task. These include: downhole casing drilling tools, under-reamers, positive displacement motors, MWD tools, rotary steerable systems (RSS), and high capacity winches for this work. Testing this equipment in commercial North Sea operations is prohibitively expensive. Therefore, tests were conducted at a drilling test facility near Cameron, Texas, where operations were conducted over a wide range of rotating speed, weight and flow conditions as well as inclinations from vertical to horizontal. High frequency surface and downhole drilling mechanics measurements were made that allowed for diagnosing problems and improving the systems.
EPINET in ONGC India: Transforming E&P Information Into Energy Intelligence
Authors: Mittal P. K. , Chatterjee D.
Published: December 2007

Indian state-owned Oil and Natural Gas Corporation (ONGC) is nearing completion of a major data management initiative that began in 1999. This paper presents a case study of the Exploration & Production Information Network (EPINET) Project. Rather than communicating detailed facts and IT aspects, the paper will show how EPINET has dealt with the critical "people, process, and technology" aspects of project implementation. It also includes a discussion of maturity levels in data management and how EPINET is helping the company to evolve along the maturity path in its information management practice.

The objective of the EPINET project was setting up a live E&P information network across the length and breadth of India. It included setting up infrastructure (machines and software) in as many as 18 sites, empowering the sites with suitably trained people, and creating and implementing policies and procedures for managing a steady flow of information. It required standardization, change management and motivating people. It ongoingly deals with data aggregation, organizing disparate information, and providing easy and free access to information.

The project targets information sources (field offices known as assets, basins, forward bases, laboratories and interpretation centers) and utilizes the "own, populate, use" model to manage data quality. In short, the EPINET project brings a paradigm shift from personalized local databases in individual personal computers to a truly integrated countrywide corporate database. The ultimate goal is to improve the quality and speed of business decisions through more efficient team collaboration. This is enabled by the availability of reliable multidisciplinary (seismic, wireline, well completion, drilling, and production) technical data. The EPINET project is expected to create substantial value for the organization.
A Pilot Test of High-Concentration Polymer Flooding To Further Enhance Oil Recovery
Authors: Fulin Yang , Demin Wang , Wenxiang Wu , Junzheng Wu , Weijie Liu , Chunling Kan , Qinghai Chen
Published: December 2007

The results of lab tests show that an incremental recovery over water flooding of more than 20% OOIP (original oil in place) can be obtained by early time injection of high molecular weight, high concentration polymer solutions, and the earlier the better. The incremental recovery is comparable to surfactant flooding but at a lower cost.

After the success of a pilot test injecting high concentration polymer fluids in Daqing Oil Field, a high concentration (concentration 1,500 ppm ~ 2,000 ppm, viscosity 400 mPa.S ~ 500 mPa.S) polymer flood pilot test has been started in May 2003. The purpose is to (1) study the feasibility of high concentration polymer flooding, (2) provide technical and practical experiences for expanding this technique to other areas of Daqing Oil Field. The pilot is located in the West Central area of Daqing Oil Field and consists of 9 injectors and 16 producers. Before high concentration polymer flooding, 0.247 pore volumes of low concentration (1,000 ppm, viscosity 44mPa.S~51 mPa.S) polymer solution had been injected and the water cut at the central area had reached its lowest point (65.5%). By the end of Dec. 2005, the water cut at the central area was 79.1%. After injecting high concentration polymer solution, the rate of the water cut increase slowed down and then the water cut decreased from a maximum of 79.6% to a minimum of 73.1% (a decrease of 7.5%) again. The current daily oil production is 29.5 tons. The daily oil production increased from a minimum of 29.8 tons to a maximum of 40.5 tons (an increase of 35.9%). The current recovery over that of water flooding is already 14.3% OOIP. According to numerical simulation, when the water cut reaches 98%, 19.8%~22.9% OOIP incremental recovery over that of water flooding will be attained.

Recently, 6 dispersed wells located in the West Central area of Daqing Oil Field started to inject a higher concentration of polymer fluid also. The 6 wells were first stimulated and then increased the concentration of the injected polymer solution from 1,000ppm to 1,300ppm. At present, good results have been obtained.

The above results illustrate that the injection of high concentration polymer fluids in the field is feasible and can further enhanced the oil recovery significantly. Very few fields have injected such high concentrations of polymer fluids; it should be of reference value to the design and implementation of future chemical (especially polymer) floods.
A Consistent Approach Toward Reservoir Simulation at Different Time Scales
Authors: Nikolaou M. , Cullick A. S. , Saputelli L. , Mijares G. , Sankaran S. , Reis L.
Published: December 2007

Reservoir simulation has become the de facto design and analysis tool to plan, develop, and manage oil and gas assets. With increasing complexity of flow networks and advanced recovery mechanisms in the fields, the model description and features of the reservoir simulator have also been progressively advancing.

The goal of a single, evolving, life-cycle model for oil and gas assets has many benefits for effective and efficient field development and exploitation. However, the size and complexity of the reservoir models often require characterization at several resolutions, thus ranging from full field strategic models to short range operational models. Full field strategic models can be used to evaluate various production scenarios and development strategies and to estimate future drilling and facilities requirements. Short range operational models concentrate on issues such as rate requirements, production decline analysis, etc. However, the approach to integrate and maintain these separate reservoir models while describing the same field is often ad hoc and many times, inconsistent.

This paper describes a new methodology for enhanced and effective use of reservoir simulation. Specifically, the application of a new method is presented to consistently integrate the full field strategic models and the short range operational models using a parametric system identification approach. The measurements from the field are used to continuously update the short range operational models over a moving time horizon, while simultaneously preparing the data for a history match of the full-field, strategic model. This hierarchical model structure at different scales avoids frequent and costly history-match runs of the larger strategic models without compromising on short term accuracy, for example, those required by production optimization. In addition, the hierarchical model structure improves effectiveness and efficiency in carrying out the simulation objectives. A case study of a full-field performance is presented to highlight the benefits of the method.
Risk Minimization by the Use of Failure Mode Analysis in the Qualification of New Technology, Applied to Intelligent Field Systems
Authors: Hother J.
Published: December 2007

Industry has recognised the value of failure mode analysis, which is being used on a rapidly expanding scale, to minimise risk, increase the probability of success and target product development spend to optimise life cycle costs for new technology, especially when applied to upstream projects. This paper illustrates best practice in failure mode analysis for oil and gas projects, by using recent case studies addressing intelligent well completions, and sand control including expandable technologies. The paper explores how these methods are applied to larger integrated systems, such as intelligent fields.

The paper highlights how methods originating in the defence and aerospace industries are adapted for the specific requirements of oil and gas projects, and identifying the key issues from recent project experience, namely – Complete system approachFunctional requirementsLife-cycle phasesTraceabilityCost of failureDirectly usable results that are fed back into the design, development and implementation processes.

-and it shows how the methods suit the analysis of large complex systems, including intelligent fields.

The paper shows how versatile the method is, identifying the different roles in which this type of analysis is proving valuable, namely – Business case – feasibility study of development optionsDesign optimizationQualificationReliability improvementVendor pre-selection

… and it shows how the method can be used to step beyond supply-chain conflicts and avoid commercial issues distracting from productive technical progress.
Experimental Confirmation of Analytical Composition Routes in Three-Phase Partially Miscible Flow
Authors: LaForce T. , Cinar Y. , Johns R. T. , Orr F. M.
Published: December 2007

In this paper effluent data from laboratory experiments are compared with analytical composition routes and profiles for three-phase partially miscible flow of three-component mixtures. Core flood experiments were run in vertical glass bead packs to achieve approximately one-dimensional displacements with stable displacement fronts. The displacements employed in this study include modest effects of dispersion, but dispersion does not substantially alter the composition routes.

Complex analytical composition routes are developed by the method of characteristics (MOC) for one-dimensional, dispersion-free flow where up to three partially miscible flowing phases may be present. The exponents used in the relative permeability model were obtained by fitting profiles from one drainage (oil injection) and one imbibition (water/alcohol injection) displacement. The resulting parameters were used to construct the analytical solutions for the remaining displacements. Development of the analytical solutions to Riemann problems is outlined.

Different parameters are obtained for the imbibition and drainage experiments, indicating that hysteresis occurs in the experiments. Comparison of the experimental results with the analytical solutions shows that the mathematical model captures the essential features of the experimental displacements. In the cases in which the analytical solutions fail to model accurately the physical displacements, the effect of simplifying assumptions in the model are examined.
Control of a Displacement Front in Potential Flow Using Flow-Rate Partition
Authors: Fyrozjaee H. , Yortsos Y. C.
Published: December 2007

We consider the problem of the control of a displacement front in a porous medium, via flow-rate partition in a well. We assume that the flow is potential and that the displacement is at a unit mobility ratio. These assumptions are for mathematical convenience only and can be relaxed. They allow, however, significant insight into the problem. The specific question we address is how to partition the flow rate within the injection well, so that the induced displacement front can be steered according to pre-determined dynamics.

When the reservoir is homogeneous and isotropic, we derive an integral equation in an analytical form, the solution of which determines the desired injection rate profile. We provide illustrative applications. A similar approach applies for an anisotropic or a heterogeneous system, except that the kernel in the integral equation must be determined numerically. This can be obtained by repeated calculations of the Green's function in a heterogeneous system or a modified two well system.

For the solution of the integral (Fredholm) equation, a regularization technique is necessary. However, it is found that numerical instabilities do develop, even with the use of regularization, for later times, when tranverse cross-flow is large. Conversely, the instabilities diminish with a more stratified structure.

The results find applications to the rapidly emerging field of smart wells and the optimization of displacement problems in oil reservoirs using flow rate control.
Proppant Placement Using Reverse-Hybrid Fracs
Authors: Liu Y. , Gadde P. B. , Sharma M. M.
Published: December 2007

In conventional gel fracturing treatments, the damage induced by the gel can have a significant impact on well performance, particularly in low permeability gas formations. Slick-water fracs have been shown to be more successful in some tight gas formations because of reduced gel damage and limited height growth. Proppant placement is a major concern in water fracs. Hybrid water-fracs (using slick water as the pad fluid and gel to place the proppant) provide some improvements to the performance of water-fracs.

This paper proposes a new method, reverse-hybrid fracs (RHF), for the efficient placement of proppant deep into created fractures while minimizing gel induced damage. Experiments were conducted in a simulated fracture (slot cell) to study the transport of proppant. Slick-water was injected first into the slot, followed by gel. Finally slick water containing proppant was injected to displace the gel. The water that carried the proppant, quickly formed viscous fingers through the gel. The gel was observed to form long thin layers which effectively hindered proppant settling and helped transport the proppant further into the slot. This resulted in the formation of proppant packs above the gel layers.

In this paper, experimental results are presented to show how the gel layers distribute in the slot and how proppant distribution is affected by the gel layers. A transparent cell made up of rough walls was set up to investigate the effect of fracture wall roughness. The effects of fluid viscosity ratio, fracture wall roughness and gel pad volume were investigated. Based on the experiments and scaling relations, recommendations are made for the pumping sequence and the size of the gel and slick water stages in reverse hybrid fracture treatments.

This method of proppant placement requires less gel than conventional gel-fracs and smaller pump horsepower than water-fracs. Other advantages include: less gel damage to the proppant pack and less penetration of the pad fluid into the formation resulting in shorter cleanup time following fracture treatment.
Comparative Evaluation of a New MMP Determination Technique
Authors: Ayirala S. C. , Rao D. N.
Published: December 2007

A new experimental technique of vanishing interfacial tension (VIT) has been reported in recent literature for quick and cost-effective determination of gas-oil miscibility. However, this technique has been criticized due to the perceived absence of compositional path specification as well as for lack of the confirmation against standard gas-oil systems. In this paper, we address these concerns by conducting interfacial tension measurements at elevated pressures and temperatures in two standard gas-oil systems and at varying molar compositions of gas and oil in feed mixtures. The two standard gas-oil systems used are: CO2 against n-decane at 100°F, and CO2 against live decane consisting of 25 mole% methane, 30 mole% n-butane and 45 mole% n-decane at 160°F. In addition to the pendent drop technique, the capillary rise technique has been adapted and successfully used for low gas-oil interfacial tension measurements at elevated pressures and temperatures.

Though gas-oil ratio was found to have an impact on mass transfer rates, the interfacial tension between gas and oil was unaffected as the fluid phases approached equilibrium. This indicates the compositional path independence of gas-oil interfacial tensions measured at near-equilibrium and miscibilities determined using the VIT technique. The minimum miscibility pressures determined using the VIT technique matched well (within 4-8%) with the reported slim-tube miscibilities for both the standard gas-oil systems used. This paper relates first- and multiple-contact miscibility development in gas injection displacement processes to laboratory gas-oil interfacial tension measurements. We also found that the dynamic behavior of gas-oil interfacial tension reflects the multi-stage contact between gas and oil that occurs in the reservoir displacement processes. Thus this experimental study demonstrates the indisputable interrelationship between interfacial tension and miscibility and hence encourages the wide use of VIT technique for rapid and cost-effective determination of minimum miscibility pressures and enrichments in improved oil recovery applications.
High-Resolution Prediction of Enhanced Condensate Recovery Processes
Authors: Jessen K. , Gerritsen M. G. , Mallison B. T.
Published: December 2007

This paper investigates the accuracy of first and high-order numerical methods in simulating enhanced condensate processes in 1D, 2D and 3D. We compare the predictions of a standard single point upwind (SPU) scheme with a third-order accurate finite difference (FD) simulator based on a third order essentially non-oscillatory (ENO) flux reconstruction with matching temporal accuracy. We include physical dispersion in the mathematical model of these multi-phase multi-component systems.

The comparisons demonstrate that SPU schemes may fail to predict the formation of the mobile liquid bank at the leading edge of the displacement unless an impractical number of grid blocks is used in the simulation. In contrast, the high order FD simulator is demonstrated to accurately predict the liquid bank at much lower grid resolution providing for a more efficient simulation approach. In 2D displacement calculations with gravity, the CPU requirement by the SPU scheme was found to be more than 50 time that of the ENO scheme for a given level of accuracy. In 2D vertical cross-sections, the predicted component recovery is demonstrated to vary upwards of 8% depending on the selected numerical scheme for a given grid resolution and dispersivity. In these settings the SPU solutions converge to the ENO results upon significant grid refinement.

In 3D displacement calculations, the magnitude of the predicted condensate bank is also found to be very different depending on the selected numerical scheme. Relative to the 2D displacement calculations, condensate banking and gravity segregation is observed to have less impact on the process performance prediction due to the permeability configuration in the 3D model used here, but it could have a high impact in different settings.

We include an explicit representation of longitudinal and transverse dispersion in the porous medium to demonstrate the grid resolution required to resolve physical dispersion at a given simulation length scale, and to show that condensate banks can also form in more realistic dispersive systems. Grid refinement studies in 1D and2D demonstrate, again, that the ENO scheme outperforms the SPU scheme for a given Peclet (Pe) number. Converged solutions are obtained with the ENO scheme using a relatively small number of grid cells. In addition, we show the behavior of the two schemes for varying Peclet numbers on a fixed simulation grid. For this grid, the ENO scheme is shown to be sensitive to the Peclet number, signifying that physical dispersion is not overwhelmed by numerical diffusion. For the SPU scheme, however, the solutions are almost independent of the Peclet number which indicates that numerical diffusion dominates.
Reservoir-Conditions Laboratory Experiments of CO2 Injection into Fractured Cores
Authors: Darvish G. R. , Lindeberg E. , Holt T. , Utne S. A. , Kleppe J.
Published: December 2007

During CO2 injection into fractured reservoirs the overall oil recovery will be the result of the complex interplay of several mechanisms such as viscous flow, extraction by molecular diffusion and gravity drainage. In order to study the component exchange between the matrix and the fracture system during the CO2 injection, CO2 injection experiments at reservoir conditions have been carried out using 60 cm long 4.6 cm diameter composite cores from an outcrop analogue to one of the North Sea reservoir rock.

The core and core holder assembly were designed to allow a 2 mm fissure to surround the core plug simulating a fracture. Live reservoir fluid was prepared and used for saturating of the matrix system. Because of the large permeability contrast between core (4 mD) and fracture it is difficult to saturate the core by simply flooding the system with live oil. Oil would flow through the fracture and only partially saturate the core To overcome this problem a unique technique has been developed for saturating the matrix system with reservoir fluids. This method ensures a homogeneous fluid composition within the pore system before the fracture system is initialized with the CO2. During the experiments CO2 was injected at a low and constant rate into the fractured system. The component exchange between the oil in the matrix and CO2 in the fracture was monitored by analyzing the produced fluids. The recovery profiles and the fluid compositions were used to construct a compositional numerical model.

The results from the experiments in the long core as well as the simulation studies show the importance of the diffusion mechanism in these experiments. The results have proved that the key mechanism to recover oil from the tight matrix block was diffusion and the gravity drainage had no significant effect at the experimental conditions used.
Transport of a pH-Sensitive Polymer in Porous Media for Novel Mobility-Control Applications
Authors: Choi S. K. , Ermel Y. M. , Bryant S. L. , Huh C. , Sharma M. M.
Published: December 2007

Injection of a pH-sensitive polymer into a heterogeneous reservoir as a novel deep-penetrating mobility control method has been proposed earlier (Al-Anazi and Sharma 2002b). A polyelectrolyte that forms molecular-network microgels in solution is injected into high-permeability zones under acidic conditions. Upon contact with reservoir rock, the injected fluid experiences an increase in pH due to geochemical reactions between the injected fluid and carbonate and other mineral components in the rock. The pH increase swells the polymer, which drastically increases the apparent viscosity of the polymer "solution", significantly lowering the mobility of water in the high-permeability zone. For the controlled application of this novel process, the mechanisms for each of its three sub-processes need to be understood: (1) dependence of polymer viscosity on ionic (pH) conditions in the reservoir; (2) geochemical characterization of pH change in the rock; and (3) polymer microgel transport in porous media. Viscosity characterization has been reported earlier (Huh et at. 2005). The geochemical characterization and the microgel transport are reported in this paper.

For geochemical characterization, brine at pH=2 was injected into a Berea sandstone core. The pH and cation concentrations in the effluent were matched, employing our geochemical simulator, KGEOFLOW. An approximate representation of sandstone with three mineral components adequately matched the pH change during the acid-injection coreflood. For a preliminary characterization of soft microgel transport, a pure-silica sandpack at a constant pH was employed to remove any geochemical effects (i.e., no microgel swelling). From the pressure gradient data available from internal pressure taps, the permeability reduction due to polymer retention was obtained as a function of polymer structure (represented approximately by rheological parameters) and polymer concentration, and with addition of surfactant. The retention can be explained by adsorption on the silica surfaces, with a small contribution from straining by size exclusion.
In-Well Optical Sensing—State-of-the-Art Applications and Future Direction for Increasing Value in Production-Optimization Systems
Authors: Drakeley B. K. , Johansen E. S. , Zisk E. J. , Bostick F. X.
Published: December 2007

For any production optimisation system to function effectively it must reliably receive quality data on demand. Over the past decade the reservoir monitoring industry has been addressing the issue of reliability including implimentation of a step-change technology – Passive Optical Sensing Systems.

Since the first installation of an in-well optical pressure gauge over 10 years ago, the industry has built a substantial track record with over 85 installations of P&T gauges and hundreds of DTS installations – acceptance is growing!

Initially Optical Sensing systems were expensive, complicated to install, and could only support limited applications. Today, they are on a par with electronic gauges with respect to performance, cost and installation simplicity. The state- of-the-art in optical sensing technology includes Bragg-grating based Pressure and Temperature sensors, permanent Distributed Temperature Sensing (DTS), Single-and Multiphase Flowmeters, and Seismic sensors.

This paper describes the operation of each of the sensing systems mentioned above, the data/information provided, together with details of application case histories. These range from simple single-gauge installations to complex wells with integrated pressure sensing, flow measurements and remotely activated zonal flow control – true Smart or Intelligent Wells.

The future direction includes even more complex intelligent completions and subsea deployments. Also high accuracy distributed array temperature sensing, optical distributed pressure sensing, sand detection, and distributed strain (e.g. for riser monitoring), are just a few of the new generation of sensing systems that are described in the paper.

As subsea continues to play an important role in our industry, the presentation (not included in this paper) will also include a synopsis from the SPE ATW "In-well Optical Sensing – Subsea Well Applications – Are We Ready?" held February 7th and 8th, 2006 in Galveston.
Enhancing Oil Production From Mature Fields by Focusing on Well-Intervention Management: North Oman
Authors: Al-Bimani A. , Al-Sharji H. , Aihevba C. O. , Fadhil A. , Al-Touqi M. , Al-Salmi M.
Published: December 2007

North Oman comprises four mature assets, producing 90% of its oil from old wells. In the drive to enhance oil production of the existing well stock, while arresting the natural decline of oil rate through better Well and Reservoir Management (WRM), well intervention work has increased in importance in the Company’s portfolio of activities. From 2003 a robust subsurface Well Intervention program is rigorously generated and vigilantly implemented and closely tracked. In 2005, some 3,600 well work activities were executed in the areas of Well Surveillance (well and reservoir data gathering); Well Optimization (oil generating activities, i.e. additional perforations, water & gas shut-off, stimulations, etc); Well Restoration (to maintain the old wells’ oil potential by ESP replacements, tubing wash, re-dress Gas-lift valve, etc) and Well Integrity (production casing repairs, fishing operations, annulus pressure testing) activities. Implementation of this program calls for utilization of various types of intervention technologies such as work-over hoists, electric / normal coiled-tubing units, electric wireline units, slick-line units and non corrosive pumping units. The oil generating (optimization) activities delivered some 5.4%, while restoration and integrity repair activities safeguarded some 23%, of the total oil production from North Oman, there by arresting the natural oil rate decline during 2005, at a low unit technical cost per barrel. As the fields get older, the well intervention work is expected to grow in term of magnitude, complexities, need for new technologies, cost impact and new challenges. Hence, the directorate has foreseen a need for continued concentration on improving the management of the well intervention to maximize the value realized in terms of oil reward and arrest of the natural decline oil rate.

This paper describes recent improvements to the Well Intervention Management Process in the North oil fields; from ranking of the activities, resource planning and optimization; activities planning and scheduling; execution of the plan, tracking of the operational / reservoir performance and feed back of learning for further improvement. These improvements are described by real examples of well interventions and the results achieved from managing the overall well intervention operations. It will also discuss the current operational challenges and limitations, and new technologies needed to address the issues.
Improving Production in Gas/Condensate Reservoirs by Wettability Alteration to Gas Wetness
Authors: Liu Y. , Zheng H. , Huang G. , Li G. , Li K.
Published: December 2007

Many gas-condensate reservoirs experience a sharp drop in gas production due to condensation near the wellbore as pressure drops lower than the dew point. Wettability alteration approach has been demonstrated successful in laboratory. However few experiments have been conducted in real reservoir rock with a low permeability. The gas-condensate reservoirs impaired by condensation near the wellbore usually have low permeabilities. In this study, we conducted experiments in core samples from the Dongpu gas-condensate reservoir with a permeability of about 0.1 md. Firstly a new and cheaper chemical was found to change the wettability of the rock from water-wetness to gas-wetness effectively. This chemical was thermally stable at a temperature of 170°C. Experimental results also showed that this chemical was effective at very high salinity. Secondly spontaneous water imbibition tests were run to show the effect of wettability alteration on recovery. Thirdly relative permeability data of gas and water were measured before and after the wettability alteration to preferential gas-wetness. Experimental results demonstrated that the relative permeabilities of both the gas and the water phases were increased significantly after the wettability alteration to preferential gas-wetness. The residual water saturation was decreased and the gas production was enhanced greatly due to the wettability alteration.
Field of the Future: Making BP's Vision a Reality
Authors: Reddick C.
Published: December 2007

Rapid changes in digital technology are revolutionising the ways in which we acquire and process data and are improving the quality and efficiency of decision making. Through the application of these digital technologies, both new and existing, BP aspires to operate its assets at the technical limit of efficiency, recovery and cost.

To make this aspiration a reality, BP has implemented a programme called FIELD OF THE FUTURE. The scope of this programme covers development and deployment of technology and business process solutions to most aspects of oil and gasfield operations - from reservoir to export, in both mature and new fields, onshore as well as offshore. The purpose of grouping these technologies under a single programme is to obtain maximum leverage from these technologies by ensuring appropriate integration between them, making strategic choices about where they are deployed and ensuring rapid propagation of early learnings.

This paper describes the portfolio of technologies needed to deliver its vision of FIELD OF THE FUTURE. The following technology themes form the core of BP's FIELD OF THE FUTURE Programme:

Real-time reservoir management Production optimisation Remote performance monitoring and collaboration Advanced collaborative environments Connecting global know-how and expertise, 24/7

The paper will also describe how BP is deploying these technologies and capabilities, with particular emphasis on the revised business processes and enhanced people capabilities needed to underpin successful deployment at scale across its assets.

Finally, the paper will summarise current status of technology development and deployment in BP, the successes achieved to date and challenges that remain.
The Field of the Future Business Process Transformation: Insights and Challenges
Authors: Feineman D. R.
Published: December 2007

BP's FIELD OF THE FUTURE concept makes use of sensors, automation, and computer networks to move real time operations data to remote sites for analysis, enabling informed and fast intervention decisions. Realizing the value from BP's FIELD OF THE FUTURE technology investments requires an integrated design and change implementation approach to business processes, information flows, and people's roles: excellent implementation of the enabling technologies alone rarely solves business problems. Since most oil companies have access to similar base technologies, how we approach process, people, and change management is a strategic differentiator in digital oilfields.

Within BP, we now have more than two years of experience in holistically approaching the issues of business strategy, process, people, and technology in E&P operating assets. Some key insights include:

Transforming the business starts with process: teams often don't have a holistic view of how they work today, so it is difficult for them to assess the impact of real time information and continuous optimization. Understanding work processes, and their assigned roles, is the logical starting point for this analysis. Building an integrated view of asset activities requires people with systems thinking skills: comparatively few people have the high level view of operating asset integration and information flow to facilitate the development of a current or future work design.

The challenges that remain include:

Communicating and positioning the transformation offering Educating implementation project managers about the benefits of including process and people tasks in their plans Establishing reasonable expectations on the engagement and time commitment needed in redesigning and implementing new processes Knowing the right level of analysis: not confusing process with procedure Recognizing the special challenges of greenfield startups: how to start-up a new asset with new processes from day one.
Alkaline/Surfactant Flood Potential in Western Canadian Heavy Oil Reservoirs
Authors: Liu Q. , Dong M. , Ma S.
Published: December 2007

For heavy oil reservoirs (with oil viscosities ranging from 1,000 to more than 10,000 mPa-s), primary production and waterflood can only recover 5 to 10% initial oil-in-place (IOIP) due to the unfavourable mobility ratio of the water phase to the oil phase. Heavy oils usually have a relatively high content of organic acids, which can be neutralized by alkalis to form in-situ surfactants. With the assistance of these in-situ surfactants, an oil-in-water emulsion with a much lower viscosity than heavy oil can be generated. In this way, the heavy oil is entrained in the water phase and produced out of the reservoir.

An initial study was carried out to evaluate the feasibility of alkaline/surfactant (A/S) flooding for western Canadian heavy oil reservoirs. The integrated approach included extensive emulsification tests, oil/brine interfacial tension measurements, viscosity measurements, and sandpack flood tests. The experimental results showed that the dynamic interfacial tension of oil/water can be lowered to an ultralow level (< 0.01 dyne/cm) by an alkaline solution and a very dilute concentration of surfactant, leading to easy emulsification of heavy oil in formation brine under slight interfacial disturbance. A series of sandpack flood tests were carried out to investigate the recovery performance of A/S flooding for five western Canadian heavy oils with viscosities ranging from 650 to 18,000 mPa-s at 22°C. Tertiary oil recoveries in sandpack flood tests were between 20 to 30% IOIP. The results of these sandpack flood tests suggest that A/S flooding is a promising enhanced oil recovery process for thin heavy oil reservoirs, in which thermal processes are not suitable.
Learnings on Sustainable Model-Based Optimisation—The Valhall Optimiser Field Trial
Authors: Stenhouse B.
Published: December 2007

Full field optimisation is a key element of BP's FIELD OF THE FUTURE technology strategy aimed at delivering a capability for remote operation and remote performance management of BP's upstream producing assets. Field of today, Valhall, is a BP operated asset in the Norwegian sector of the North Sea with a track record of applying model-based optimisation technology to support production delivery.

In 2002, Valhall identified the potential business prize from using model-based optimisation technology to support operation of the Valhall platform. The opportunity arose out of the complexity of the Valhall facilities together with the potential to optimise CO2 emissions taxation as well as production. Initial application of this on-line, advisory optimisation technology indicated significant benefits yet, paradoxically, usage of the optimiser fell away gradually after approximately a 6 month period.

In 2004, in order to capture learnings for BP's FIELD OF THE FUTURE programme, the BP Exploration and Production Technology Group, together with the Valhall asset embarked on a field trial of the optimisation technology. The objectives of the field trial were two-fold:

To demonstrate measurable value delivery from the optimisation technology. To establish the federal requirements for sustainability of the technology and associated value delivery.

Optimisation of an upstream producing asset is a cross-disciplinary process requiring close team-working and ownership of optimiser advice from all engineering disciplines, reservoir management, well performance and facilities, through to operations and commercial staff.

Working with the FIELD OF THE FUTURE business process transformation team, the field trial focused on all aspects of the people, process and technology required to deliver sustainable value. The paper discusses key conclusions from the field trial and also how the learnings will influence the way forward for this technology in BP.
Influence of Temperature on Wettability Alteration of Carbonate Reservoirs
Authors: Hamouda A. A. , Gomari K. A. R.
Published: December 2007

Carbonate reservoirs become more water-wet during thermal recovery. The effect of temperature on wettability-altering process is caused by contribution from several parameters involving fluid/fluid and fluid/rock interactions. This paper aims at describing the interrelationship between different parameters of a simple oil/water/rock model over temperature range of 25 to 130 degree centigrade.

Saturated and unsaturated fatty acids as well as naphthenic acids with saturated and unsaturated rings are selected for this work to alter the water-wet calcite surface. The type of selected acids is based on the distribution of these components in reservoirs in the Norwegian continental shelf.

Contact angle measurements on the treated calcite surfaces are used as indication of wattability alteration. At fluid/fluid interface the interfacial tension and distribution of the solutions of n-decane /fatty acids /water systems are measured at elevated temperature. A set of experiments is also performed in order to understand the role of the temperature on fluid/rock interface by zeta potential measurements.

As the temperature increases, calcite surface becomes more water-wet. The obtained results at fluid/fluid interface (IFT and distribution coefficients) and contact angle measurements show that the trend of decrease in contact angles with temperature follows the same trend as IFT and distribution coefficients, specifically if one divides acids to saturated and unsaturated separately. Electro-kinetic measurements (zeta potential) of calcite surfaces with temperature demonstrate that increasing temperature reduces surface charge to less positive, which may enhance the repulsive forces between dissociated acids and calcite surface. Due to this change in surface charge, the adsorption of acids on the surface becomes less effective at high temperatures; hence wettability of the calcite surface tends to be more water-wet.
ISIS—A Real-Time Information Pipeline
Authors: Foot J. , Webster M. , Trueman D. , Yusti G. , Grose T.
Published: December 2007

BP's ISIS technology (Integrated Subsurface Information System) is changing the way BP manages reservoirs through the provision of multi-disciplinary analysis and visualisation of real-time integrated dynamic surveillance data, information and knowledge processes. The technology enables faster and integrated operational decision making, provides continuous real-time access to all digitally acquired sensor data in a well or on the platform, on a 24/7 basis, alerting users to production events which require their attention and can be acted upon. The tools developed by the ISIS Technology Program turn the vision of a real-time data pipeline into a reality by providing an innovative solution for remote visualization of information. The technology provides a robust environment for the transfer of data from the point of acquisition to the point of decision-making.

ISIS and the parallel facilities/operations project entitled D2D (data to desk) use common systems for real-time data management and visualisation. While these developments serve the distinct discipline needs of the subsurface and facilities/operations communities in terms of computational processes, there is a single collaborative system sharing technology of mutual benefit to all communities.

The ISIS system is being deployed across BP's operations as a key element of BP's FIELD OF THE FUTURE programme (1). Initial installation has been completed in seven operational assets across BP that has proven the capabilities and business benefit of the technology. Installation of the technology has been the catalyst for changing the way the field teams approach surveillance; these changes are being enhanced through use of adaptive change projects with the field teams which are changing the way BP operates its fields.
Seismic Geomorphology and Connectivity of Deepwater Reservoirs
Authors: Ragagnin G. M. , Moraes M. A. S.
Published: December 2007

Assessing reservoir connectivity and permeability heterogeneity is essential for predicting reservoir performance. As reservoirs are three-dimensional entities, there is little value in trying to predict reservoir connectivity based on two-dimensional data such as geological sections or maps. A new method for seismic volumetric visualization, complemented with outcrop analog data, was used for assessing reservoir connectivity and permeability heterogeneity of the deep-water reservoirs of Marlim Sul field, Campos Basin, Brazil.

The method consists of combining reflectivity and impedance seismic volumes. For the reservoir target zone, reflectivity was used as top drape covering the whole area, with color contrasts discriminating reservoirs and non-reservoirs, whereas in the impedance volume a cutoff value was used to show only the reservoirs. Such volumetric visualization technique permits the better identification of architectural elements and the better understanding of the evolution of the depositional system. However, some limitations still remain. Before building a reservoir model, it is necessary to assess (1) the internal permeability heterogeneity of the different architectural elements, and (2) the petrophysical nature of the boundaries among the different elements. This was performed by comparing geometries and facies observed in subsurface with geometries and facies documented in outcrop analogs. The main controls on connectivity and permeability heterogeneity in deep-water reservoirs are permeability barriers and baffles, such as hemipelagic shales and marls, turbiditic drapes, debris-flow deposits, shale-clast breccia and cemented zones. Such features present a complex and varied distribution. Barrier and baffle 3D maps of the different architectural elements and of the limits among them obtained in representative outcrops were used to complement seismic information.

The integration of seismic volumetric visualization with outcrop analog data, calibrated by well information and tested again production data, proved to be useful for improving reservoir models.