bluuebunny/crossref_metadata_2025_split huggingface dataset:
CO2 Injection and Storage: A New Approach Using Integrated Asset Modeling
Authors: Primera A. , Sifuentes W. , Rodríguez N. 
Published: June 2009

Abstract
The reduction of greenhouse gas emissions in order to decelerate the global warming process could be achieved through the emerging process of geological CO2 storage. Also in terms of Enhanced Oil Recovery (EOR) the injection of CO2 as a pure component or as part of a mixture has proved to increase the productivity of oil and gas reservoirs.
Optimization techniques have been applied independently to the reservoir and surface models, leading to non-optimal solutions due to the non-dynamic integration between models. A recent trend of the industry is the integration of sub-surface and surface simulators to have a better representation of the fluid production/injection, taking into account the constantly changing interaction between systems.
The integrated approach has been used to integrate multiple reservoirs with common and advanced surface facilities to properly model the fluid flow behavior of the asset. Different injection variables, facilities, well completion, number of wells have been included in the analysis and numerical reservoir simulation models have been integrated with a network. As CO2 is captured, it is transported and re-injected to neighbor reservoirs, as an enhancement process for productivity or for storage purpose.
After proving the feasibility of facilities for CO2 injection as EOR process or storage, the integrated approach has shown a more comprehensive solution that could be used for the design and further optimization of this type of projects. Analysis of reservoir properties as permeability, temperature, etc. is also taken into account in order to asses the viability of the CO2 optimal injection and storage strategy, while minimizing cost. Finally, integrated asset modeling also shows the flexibility to represent different types of settings such as CO2 source (reservoir and/or fossil fuel power plants), types of reservoirs and network scenarios.
Reservoir Management Challenges and Improved Hydrocarbon Recovery Activities on Kvitebjørn HPHT Gas Condensate Reservoir
Authors: Talukdar Saifullah , Rasmussen Janikke , Wennberg Kjell Erik , Lien Linda Storetvedt 
Published: June 2009

Abstract
The Kvitebjørn medium rich gas condensate field in the Norwegian North Sea is characterized as a high pressure high temperature (HPHT) reservoir with 770.5 bar pressure and 150°C temperature at about 4000 m TVD MSL. Despite high temperature and depth, the average reservoir properties are reasonably good. The main reservoir is Brent Group of Middle Jurassic age which is extensively faulted.
One of the main challenges is the drilling in depleted reservoir. The strategy to mitigate the problem has been to put the field on reduced production and/or to actively manage reservoir pressure by producing more from areas far away from the drilling locations. Advanced drilling technologies have also been developed to improve drillability.
Several improved oil/gas recovery methods are currently under consideration, which include infill drilling, process capacity upgrading, low pressure-production and gas recycling. Infill drilling is challenging due to reservoir depletion. Capacity upgrading is to be implemented to expedite hydrocarbon recovery. Gas recycling has some potential for improved condensate recovery, but the project economy is poor. Low pressure production appears to be a very attractive option. A compressor concept has been selected based on thorough evaluation of space and weight limitations on the platform, possibility for future drilling and intervention operations, explosion hazard, tie-in of other prospects and future export facilities etc. Subsurface challenges include uncertainties related to well integrity and productivity, reservoir communication, reservoir volumes, etc.
The purpose of this paper is to present the challenges related to development and management of this HPHT gas condensate reservoir, the strategies to overcome the challenges and the methods to improve gas and condensate recoveries from this field with special focus on the low pressure production and gas recycling.
Improving Reservoir Simulation Models Using 4D Data at the Snorre Field
Authors: Seldal Mailin , Reime Arild , Arnesen Dag 
Published: June 2009

Abstract
New reservoir simulation models have recently been established for the Snorre field based on updated geological models and fully revised input data. The Snorre reservoir is highly heterogeneous, comprising stratified and heavily faulted fluvial deposits. The field is pressure supported by water alternating gas (WAG) injection, resulting in complex drainage patterns.
Time-lapse seismic is amongst the technologies applied to improve reservoir understanding and has provided valuable information on fluid front movement and fault communication.
The paper describes a first systematic effort on honouring 4D data in the Snorre reservoir simulation models. A workflow converting 4D responses into 3D volumes in the reservoir modelling software for easy comparison to simulated reservoir performance proved very useful in the multidisciplinary work process. The models are history matched with respect to pressures, production rates and fluid front movement from tracer and 4D data. Though the seismic time-lapse responses are matched qualitatively, they have improved the overall Snorre reservoir understanding.
Different applications of 4D data in the history matching process are discussed, e.g. determining fault transmissibilities and water front movement, identifying water producing intervals and re-allocation of zonal contributions in wells. A successful water shut-off based on 4D interpretations and simulated future performance is also discussed.
Fluid Pressure Gradients in Tight Formations
Authors: Larsen J. A. , Urkedal H. , Lønøy A. 
Published: June 2009

Abstract
Low-permeable reservoirs have long been recognized as a challenge for economical production. Characterization of complex carbonate reservoirs exhibits some special challenges. Pay zones may be poorly defined due to marginal reservoir properties, i.e., uncertainties regarding the distribution of oil on the pore scale and the ability of oil to flow at high initial water saturation. Hence, the oil water contact may not be a precise level in the reservoir and the vertical span of the oil-water transition zone may be greater than 100 meters in such reservoirs. The traditional reservoir engineering approach defines free water level and hence the water- and oil-zones from the oil- and water pressure gradients. Pressure gradients are, however, difficult to obtain in low-permeable media and it has been reported that supercharging effects may be the result of mobile oil and water at the same place in the reservoir.
A case study is made for an offshore exploration well in a complex and heterogeneous carbonate oil reservoir. The well is not production tested and gives a clear water gradient. However, there is indication of relatively high oil saturation with possible live oil properties. This is not typical for a reservoir that has been completely water washed during historical time.
Different initial fluid distributions are studied in simulation of filtrate invasion in order to explain the observations in the exploration well. The results are of general interest, with application to many low-permeable reservoirs. This work gives new insight into the important interplay between type of drilling mud, reservoir wettability and interpretation of fluid gradients. The novel implication of the results is that a water-gradient is measured in the transition zone if an oil-wet reservoir is drilled with water-based mud. A water gradient can therefore exist even though the oil saturation is high. The shift between the water gradient and oil gradient occurs when mobile oil is present in water-wet pores giving a positive oil-water capillary pressure.
Opportunities for Geothermal Energy in Franekeradeel, Netherlands
Authors: Heijnen L. J. , Buik N. A. , Willemsen A. , Bakker T. , Diephuis G. 
Published: June 2009

Abstract
The potential for the exploration and exploitation of geothermal energy for greenhouses in Franekeradeel in the north of the Netherlands has been investigated. Available borehole and seismic data have been used for the evaluation of the subsurface. These data show that the Slochteren Formation sandstone reservoirs are very likely present at a depth of ca 3,000 m. These reservoirs are deemed to be suitable for the production of hot water. From interpreted 2D seismic lines could be inferred that the Slochteren Formation is around 200 m thick at the proposed location. Based on the local geothermal gradient, the temperature at the top is estimated to be around 100 °C. At the surface location a fault zone is present in the subsurface complicating the siting of the injection and production wells. Towards the northeast the proposed reservoir is seemingly less faulted. A minimum transmissivity of 11 Dm is expected, based on the measured porosity in nearby boreholes and porosity-permeability relationships in the surrounding area. A potential flow rate of 160 m3/h is hence inferred, leading to a thermal capacity of 11 MWt which can be delivered with one doublet. Different well configurations were studied. The conclusion is that deviated wells from the edge of the surface location towards the northeast carry the lowest risk at still acceptable costs. From financial analyses taking different options into account, it was concluded that geothermal energy can deliver significant amounts of renewable energy for heating of greenhouses. In the optimum situation, the cost price of heat amounts to 6,20 Euro/GJ delivering annual 202 TJ of energy. This price is below the current price (January 2008) of natural gas at 0,20 Euro/m3.
Uncertainty Evaluation in Field Development and Export Planning
Authors: Akeze Azuka Christian , Sikandar Ali Shahbaz , LaForce Tara 
Published: June 2009

Abstract
Decision making in the face of uncertainty is a problem encountered at every strategic level within the exploration and production value chain. This problem is evident in new field development projects when there is limited and uncertain geologic and engineering data. Key uncertainties encountered in reservoir engineering models include drive mechanism, permeability, aquifer support, fluid properties, reservoir extent and connectivity, end point saturations and reservoir structure. Evaluating uncertainty using conventional methods, where model parameters are varied individually, makes it impossible to make an objective business decision without underestimating the effects of uncertainty.
This work proposes a systematic approach to evaluate uncertainty in a field development decision process. Initially parameters are varied individually to rank the key uncertainties. Subsequently the experimental design approach is used and a response surface is developed to estimate the impact of uncertainty in the parameters with the largest influence on project economics. In order to integrate the uncertainty in availability of surface facilities, project economics and sub-surface properties, a decision tree is designed to incorporate risk into a logical and consistent decision strategy. Information analysis is also performed to estimate the value of acquiring additional information.
The proposed decision-tree is applied to development planning of a field comprising of marginal stacked reservoirs. Numerical simulations are performed to optimize the field development and generate a range of oil recovery predictions. The surface facilities options, project economics and predicted recoveries were then integrated into the decision tree. The value of the project was positive for most outcomes, with negative value occurring only for the lowest oil recovery combined with delayed access to surface facilities. The economic value of obtaining additional information was much lower than its cost.
Rapid Evaluation of Geological and Reservoir Uncertainty in a Multi-Field Development
Authors: Edwards Glyn , Sadikoglu Kasim 
Published: June 2009

Abstract
An automated modelling process for rapidly evaluating differing multi-field development production strategies under geological uncertainty has been developed. We demonstrate the use of the technique on the Charlie, Alpha, and Bravo (CAB) fields lying in deepwater, offshore Angola. The names of the fields have been changed to preserve confidential data.
CAB is a planned clustered development with all CAB reservoirs producing back into a single Floating Production Storage and Offloading (FPSO) vessel. Due to a challenging seismic environment causing considerable geological uncertainty, stochastic modelling was used to populate reservoir models bounded by seismically interpreted deterministic channel system surfaces. The CAB team developed a systematic modelling workflow combining static and dynamic data for simulation using a multi-field reservoir simulator. Evaluating each new geological model was a manual process taking up to 10 days.
To accelerate the modelling process, the entire workflow was automated and BP's Top-Down Reservoir Modelling (TDRM™) philosophy and toolkit (Williams et al., 2004) was used to investigate the affect on hydrocarbon recovery of different possible geological models. Automation involved generating stochastic geological realisations for each CAB field and simulating simultaneous production from all three fields with reinjection of the produced gas. Up to 30 different multi-field simulations could be generated and simulated every 24 hours, with the workflow using 10 CPUs
Approximately 700 multi-reservoir simulation runs (2100 individual reservoir simulations) were conducted within a two month period. By automating the workflow, more time was available for evaluating simulation results and less time was spent preparing data and running the simulations. The automated workflow has been used to decide FPSO capacities and to gain confidence that the Charlie field could take all produced gas without flaring or significant loss of production. The workflow continues to be used to quantify the effects of geological uncertainty on different gas management strategies.
SAGD Subcool Control with Smart Injection Wells
Authors: Gotawala Dharmesh R. , Gates D. 
Published: June 2009

Abstract
Steam-Assisted Gravity Drainage (SAGD) is a widely used in situ recovery process for heavy oil and bitumen reservoirs. The performance of the SAGD process is tied with growth of the steam chamber which in turn depends on uniform steam delivery along well length and the underlying geology and fluid properties in the near wellbore region. If the reservoir has poor injectivity due to poor underlying geology oil production suffers. This can be avoided in by examining the interwell subcool. The subcool is the temperature difference between the injected steam and produced fluids. In this study, Proportional-Integral-Derivative (PID) feedback control has been employed to control inflow control valves settings to promote subcool to a target value. This control strategy is examined by using a PID algorithm to control SAGD in a detailed three-dimensional heterogeneous reservoir model with properties typical of an Athabasca bitumen reservoir. Specifically, the SAGD injector is divided into six intervals each with its own steam injection pressure. The interwell subcool is calculated and the PID feedback control algorithm is used to direct the subcool to a target value by changing the steam injection pressure in each well interval. The results show that this control method can be used to enhance uniform steam chamber growth and ultimately more oil production with less steam injection. The key benefit of dynamic well control is that the injection strategy is adjusted dynamically to fit the underlying geological and fluid compositional heterogeneity to obtain improved steam conformance along the wellpair. This implies that potentially a priori detailed knowledge of the geological and fluid compositional heterogeneity may not be as critical for well placement for uniform steam conformance.
Potential for Hydrogen Generation during In Situ Combustion of Bitumen
Authors: Kapadia Punitkumar R. , Kallos Michael S. , Leskiw Chris , Gates Ian D. 
Published: June 2009

Abstract
The volume of heavy oil and bitumen in Alberta, Canada is estimated to be about 1.7 trillion barrels. The majority of the produced heavy oil and bitumen in Alberta is converted in surface upgraders to synthetic crude oil, a crude oil with API gravity typically between 31 and 33°API, which in turn can be converted to fuel, lubricant, and petrochemical products in standard refineries. To upgrade bitumen requires hydrogen. In current practice, much of this hydrogen is generated from steam reforming of methane together with the water-gas shift reaction. This means that heavy oil and bitumen upgrading, as is currently done, requires huge amounts of natural gas to generate hydrogen. The potential for in situ generation of hydrogen by gasification of bitumen reservoirs offers an attractive alternative which can also have both economic and environmental benefits. For example, hydrogen generated from bitumen gasification can also be used for in situ upgrading as well as feedstock for ammonia and other chemicals. The water-gas shift reaction also generates carbon dioxide which could be potentially sequestered in an in situ gasification process so that emissions to the atmosphere are reduced. This study evaluates the effect of operating parameters such as temperature and pressure on the amount of hydrogen generated during in-situ combustion. Combustion of Athabasca bitumen incorporating thermal cracking, oxidation, and hydrogen generation and consumption reactions has been simulated. The results indicate ranges of temperature and pressure where bitumen combustion yields optimal hydrogen production. This research emphasizes the conditions at which hydrogen production can be maximized from the in-situ combustion of Athabasca bitumen. This technology provides a potentially clean method to produce fuel and feedstock material from bitumen, a relatively "dirty" fuel and feedstock oil, in addition to more energy efficient ways of extracting in-situ heavy oils.
Assisted Procedures for Definition of Production Strategy and Economic Evaluation Using Proxy Models
Authors: Avansi G. D. , Schiozer D. J. , Suslick S. B. , Risso F. V. A. 
Published: June 2009

Abstract
New techniques for reservoir development are essential for dealing with the complexities of geological models. In this sense, numerical simulation is the tool used to define the quality of a production strategy. However, the process to define variables such as well numbers, completion layer, open timeline and operational conditions demand several simulations due to the high time consumption and computational effort. Sub-optimal results can be obtained from manual processes. Automatic processes can mitigate this problem but the computational effort is increased as a result of the number of simulations generated in the process.
In order to minimize this problem, this paper proposes an assisted procedure for its automatic part using proxy models to accelerate the process. Furthermore, due to the reduced time to evaluate options, it allows a better evaluation of the solution space using better optimization techniques. Proxies have been used in important applications such as risk analysis and history matching but the use for definition of production strategy is not common.
The proposed methodology involves the following components: statistical methods, experimental planning to generate the response surface methodology for the generation of proxies and consistency checking.
The results show that it is possible to apply proxy models for this type of problem and they can identify the best production strategies, reducing the computational effort during the process. The suggested procedure is to use proxies in the automatic part of the assisted procedure used in the optimization process.
The main contribution of this work was the demonstration that proxy models can be used for the definition of production strategies, bringing an additional option to the decision analysis process linked with petroleum field development.
A Cost Effective and User Friendly Approach for Mini-DSTs Design
Authors: Bertolini C. , Tripaldi G. , Manassero E. , Beretta E. , Viberti D. , Verga F. 
Published: June 2009

Abstractmini-DSTs are gaining more and more popularity as a possible alternative to conventional well testing especially where there are major environmental and economical constraints. The increased offshore exploration activity, which often implies highly risky and huge operational costs, makes the conventional well testing less attractive in favor of other technologies that can provide some of the key dynamic information about the well-reservoir system through relatively quick and less expensive operations. The design phase is recognized to be one of the most critical aspects in order to guarantee an acceptable value of information in exploration scenarios where very limited data is available. The success of any mini-DST operation can be significantly compromised if two major issues are not addressed in the design phase: possibility to clearly identify the radial flow behaviour, and avoidance of noise in the pressure response due to the gauge resolution.The paper describes a new user-friendly approach for mini-DST design, which allows one to easily identify whether this technology can be successfully applied. The approach is based on the use of dimensionless and dimensional charts, which are of general validity because they can be applied to any lithological environment and for any type of hydrocarbon. Field applications proved the charts to be very powerful because they could predict the range of effectiveness of mini-DST's.