bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fully Integrated 3D-Reservoir Characterization and Flow Simulation Study: A Field Case Example
Authors: Al-Deeb Maged , Bloch Gerard , El-Abd Salem , Charfeddine Mohsen , Bahar Asnul , Ates Harun , Soeriawinata Tono , Kelkar Mohan 
Published: December 2007

Abstract
This paper presents the result of fully 3D integrated reservoir description and flow simulation study of a giant oil field in Middle East using the state of the art technology. The overall goal is to develop a representative reservoir model to form the basis for reservoir management and long-term development planning. This is done by generating alternate reservoir descriptions, based on stochastic models, to quantify uncertainties in the future performance. The data that were integrated include well cores and logs, geological interpretation (stratigraphy, rock type, depositional model), seismic (structure, curvature analysis and inversion-derived porosity), well test, SCAL, production data and fracture distribution.
The 3D multiple realizations were generated by considering rock type and petrophysical properties at well location, obtained from well logs and cores, and simultaneously constrained by seismic derived porosity. The simulations of properties were generated using simultaneous sequential Gaussian simulation where the seismic constraint was introduced via Bayesian Updating procedure. Special consideration was given to the spatial modeling of data where soft information was derived both from hard data and depositional environment. Fracture distribution, derived from seismic curvature analysis, was used in the integration process to match the core-based derived permeability with well test permeability. This distribution was used to obtain permeability anisotropy distribution using newly developed tensorial approach.
A total of forty-eight realizations were generated considering four major types of uncertainties: structure, spatial model, petrophysical properties and simulation path. The results have been used as the basis for fluid in place (STOIIP) calculation using Monte Carlo simulation technique. These realizations are then ranked based on the sweep efficiency, obtained from multiphase streamline simulations, and the STOIIP. Three realizations, representing medium, low and high realizations, were selected and upscaled. An optimum vertical upscaling level was determined using streamline simulator and developing quantitative criterion. This ensures that the representative heterogeneity of the reservoir was maintained during the upscaling process.
Comprehensive history matching was done for the three selected realizations for the entire nineteen years of production history using objective criterion so that the quality of the three matches is similar. The observed data matched include water cuts and measured pressures. The parameters used to match the history are restricted to the parameters that have not been accounted for in the static model. Using probabilistic concepts, uncertainties in future performance were quantified for various scenarios.
Real time data transfer to 3D model. Maximising wellbore value.
Authors: Nicholson H. , Folstad P. G. , Pedersen T. A. 
Published: December 2007

Abstract
A real time data link has been employed recently on the Ula Field (Norway), with new data loaded directly to the subsurface database. The data were used to assist in the optimal placement of two geosteered wells. Onshore staff were therefore able to participate fully in the steering process, focusing on rapid data interpretation rather than data management. Well results were highly positive.
Karstic high permeability layers: Characterization and Preservation while modeling carbonate reservoirs
Authors: Botton-Dumay Roselyne , Manivit Thierry , Massonnat Gérard , Gay Viviane 
Published: December 2007

Abstract
Diagnosis, characterization and modeling of high permeability layers constitute a very challenging issue while building carbonate reservoir models for flow simulation.
In karstic reservoirs, the evaluation of the dual permeability behavior is the key to assess reservoir heterogeneity. This heterogeneity is expressed by highly variable and non-stationary reservoir properties. The 3D organization of these reservoir properties depends on the parameters, which drove the karst development (fracture network, sequence stratigraphy, hydraulic gradient).
This paper presents an integrated methodology for the evaluation of the karst network and its 3D modeling in single porosity models.
In a Middle-East reservoir, a synthesis of dynamic data shows a clear dual porosity/permeability behavior, which is explained both by the core description and the well test interpretation.
The karst network is proved to be driven by an early diagenesis along sequence boundaries. The 3D organization of the karst network is assessed from the integration of sedimentological/structural models and dynamic data.
Fine gridded models are achieved before the full field simulation to evaluate matrix-drains exchanges. Results from these sensitivity models enable to input realistic reservoir properties in the coarse full field. A methodology for preservation of dual permeability behavior through downscaling process is presented.
The reservoir layering is defined in order to preserve the key heterogeneity in the coarse model, moreover, homogeneous equivalent petrophysical parameters are assigned to high permeability layers. A specific modeling of permeability, saturation and Rock-type in karstic layers is performed.
The matching of the production history is obtained without any drastic changes in reservoir properties; that confirms the distribution of the karst network.
Pushing the limits in extra-long cased horizontal drains acidification: use of double trigger perforation technique to maximize productivity and optimize Rig time.
Authors: Buffet Michael , Derbez Emmanuel , Leschi Pierre , Mac Rae Scott 
Published: December 2007

Abstract
Building on the successful acidification of long cemented and perforated drains (∼1000m) during the Central Area Development Phase of its AlKhalij Offshore field in Qatar (refer to SPE 54739), TotalFinaElf faced a new challenge for upcoming South-East Area Development Phase: how to boost productivity in extra-long drains applying previously proven principles, without going through unaffordable rig time?
To snatch the maximum productivity (highest Productivity Index – PI) from horizontal drains in the over 2000m range, an homogeneous participation to production of the perforated intervals throughout the drain is crucial.
In the matrix Mishrift carbonated horizon, a successful acid job is the key to meet the high production expectations that such long drains promised. The success of the stimulation relies on the necessity to open first the "toe" of the drain prior to bull heading - through a DST string - emulsified acid and water soluble balls sealers as the diverting agent.
To deal with the here above requirements and in a "Rig time saving" approach, the "toe" and the remaining zones (the "heel") were successively perforated in one TCP run while ensuring pre-acidification of the lowermost perforations. The "double trigger" perforation technique was designed by the TotalFinaElf team in collaboration with the Service supplier.
This technique consists in shooting the lower perforations in acid, squeeze this "in place" acid through annulus at a high pumping rate (to ensure a good Injectivity Index at the toe) and trigger the remaining perforations (remaining production intervals) in the same TCP run. Once TCP are pulled out of hole, a DST / acid string is run in hole and the main acid job performed in bull heading. The reservoir being hydrostatic to sub-hydrostatic, the well is kept on losses while running final completion.
This paper documents the engineering approach and operational methodology implemented to reach high efficiency targets. Case histories are presented to illustrate these procedures, treatment designs and productivity results.
Management and Control of the Inventory of Problematic Wells; A Stochastic Process Approach
Authors: Alhanai Waddah T. 
Published: December 2007

Abstract
Queuing theory provides models for the analysis, management and control of service facilities where customers arrive and are serviced in a particular probability distribution.
In this work, the Poisson distribution is used to analyze a system of inactive strings as a queuing system in which both arrivals and service of inactive strings are assumed completely random, with average arrival rate = λ and average service rate = μ.
The design of a queuing system to manage and control the inventory of inactive strings is optimal when a steady-state prevails. If the number c of service rigs is to be determined, the procedure starts with determining the smallest integer c such that the "rig utilization factor" ρ=λcμ&lt;1 and to study the resulting values of the corresponding "measures of effectiveness" until a specific measure (such as the "waiting time") is obtained that is acceptable to the Company.
The specific choice of the number c depends on what the Company considers as acceptable from an economic viewpoint of the number of inactive strings to be repaired and the time lost during repairs.
The numerical examples given in this work provide insight into the problem that may not be obvious intuitively.
Meticulous Planning and Exhaustive Preperation for Testing of the Super Deep HP-HT Well in North Kuwait- A Case Study
Authors: Srivastava Sanjeev , Abdullah Shehab 
Published: December 2007

Abstract
A super deep well was drilled in 1999-2000 to test the Pre-Khuff and Jurassic formations of Unayzah, Marrat and Najmah-Sargelu. The Unayzah formation had never been tested in North Kuwait before, therefore meticulous planning was required to successfully test this unknown HP-HT formation. The objective of the test was to obtain fluid samples, flow to surface and measure flow rates and establish basic formation properties to determine commercial viability from the deep formations of North Kuwait. This was the deepest well drilled in that area to the depth of more than 20,000 ft, having a formation pressure of 16,158 psi and log temp. of 350 DegF. The well was drilled with 19.6 ppg oil base mud, which was consistent with the formation pressure.
Since the well was rated as one of the deepest well in the Middle East, and it was new experience to KOC to deal with such type of wells, it was a challenging task for the management to successfully test this well. The complications in the drilling also generated lot of constraints, which were to be taken into consideration while designing the test. More than 10 months of careful planning and preparation for special equipment lead to the successful testing of the deepest formation. Special care was taken to take into account the HSE issues to eliminate any chance of loss of life or property, without compromising the test objectives. This case study details the complete sequence of planning and preparation for designing and testing a super deep well like this one, which might be referred as a bench mark for HP-HT testing of deep wells in Kuwait and other places.
Gas Seepage at the Sea Floor, Part 2: The Remedy and Results
Authors: Al-Marri F. , Fawakhiri A. Y. , Rouatbi R. , El-Zeghaty Said , Dajani N. , Boyd D. , Cossey Simon , Okuyiga Moyo 
Published: December 2007

Abstract
This paper documents the job methodology and the remedial cementing actions taken to cure an offshore subsurface gas and oil leak in a prolific gas producer that crosses multiple, hydrocarbon-bearing horizons. It is a follow-up to ADIPEC–0938 describing the investigative process used to diagnose the multiple leak sources. A detailed risk assessment and contingency plan preceded each operation. Seven squeezes proved necessary to control the leaks. Continuation of the leak to surface and downhole noise activity defined the success or failure of each cementing operation. Cement squeeze operations took place through two to three sets of casing, after perforating with TCP guns at shot densities from 12 to 36 shots per foot. An ultrafine cement formula ensured the smallest diameter flow conduits were penetrated. Monitoring of the annuli leak rates over a sixteen-month period with a custom designed separator, suggests the leak is cured. Final declaration of success or failure must wait until the well is place back on line following its recompletion.
Prediction of Critical Gas Flow Rate for Gas Wells Unloading
Authors: Osman El-Sayed A. 
Published: December 2007

Abstract
The gas well loading phenomenon is considered one of the most serious problems in the gas industry. It occurs as a result of liquid accumulation in the wellbore, when the gas phase does not provide sufficient energy to lift the produced fluids, imposing additional hydrostatic pressure on the reservoir and causes more reduction in the transport energy. Eventually, if the reservoir pressure is low, then the accumulated liquids may completely kill the well. If the reservoir pressure is higher, then liquid slugging or churning may take place and gives more chance for liquid accumulation and the well may die. To solve such a problem, the well may be unloaded mechanically using a pump or by gas lift; or to let the well continuously unloading itself. Analysis of the mechanisms of gas-well load-up indicates that there is a critical gas rate to keep low pressure gas wells unloaded. Predicting that minimum gas flow rate is very crucial. Several researchers have developed various mathematical models to calculate the critical flow rate necessary to keep gas wells unloaded.
This paper presents an Artificial Neural Network (ANN) model for predicting the minimum flow rate for continuous removal of liquids from the wellbore. The model is developed using field data from different gas wells. These data were used to train a three-layer backpropagation neural network model. The model was tested against published field data which was not used in the training phase. The results show that the developed model provides better predictions and higher accuracy than the published models. The present model provides prediction of the critical gas flow rates with an absolute average percent error of 4.61 % and a correlation coefficient of 99.11%.
Reducing the Uncertainty on Residual Oil Saturation in a Gas Injection Pilot Project
Authors: Gyllensten Asbjorn , Petricola Mario J. C. 
Published: December 2007

Abstract
In several of ADCO's fields, potential gains from an improved recovery mechanism are large. Several such projects are therefore being tested to optimise the next phase of field development. Gas injection pilots have been designed to verify the feasibility and estimate the efficiency of gas injection for enhanced recovery of oil left behind by natural depletion and water flooding. Conclusive evaluation of these pilots requires a good understanding of the various sources of error that affect monitoring data.
Initially, the main purpose is to detect gas breakthrough at the observers. This is generally straightforward, as long as the wells have been correctly designed, and a suitable set of logs is acquired on a regular basis.
As the gas flood progresses, the hydrocarbon properties in the reservoir change; oil becomes heavier as some intermediate hydrocarbons are carried over to the gas phase. When gas, oil and water saturations have stabilized; the question arises of how accurate the log-derived saturations really are. This is important since the residual oil saturation is one criterion by which the efficiency, and thus commercial viability, of the project can be assessed.
A lot of effort goes into reducing log uncertainty by acquiring numerous passes and using systematically the same logging tool over the monitoring period. Quantitative log interpretation requires careful environmental corrections and using the right properties for various formation and fluid components.
This paper presents a method to help reduce uncertainty in residual oil saturation to a level where the results can be used in reservoir simulation. The uncertainty in this number is estimated by analytical and numerical means.
Upscaling of Multimillion Cell Geological Model into a Practical Simulation Model of a Major Carbonate Oil Reservoir in Offshore Abu Dhabi
Authors: Ghedan Shawket G. , Gunningham Tom W. , Ehmaid Bassam H. , Azer Samir R. 
Published: December 2007

Abstract
It is vital to retain the 3D geological model main structure and heterogeneity features in the simulation model. This could be assured only through careful design of the simulation model areal grids; representative reservoir simulation layering system and quality controlled petrophysical data up-scaling process. This paper presents the methodology and the QC tools followed to upscale a 25 million cell geological model into a 0.72 million-cell dynamic simulation model, while maintaing reservoir structure and heterogeneity features.
The layers of simulation models have to be as detailed as possible to capture identified key geological features such as barriers, high permeability streaks, and pinchouts. Mechanistic simulation modeling, along with permeability variance maps, and permeability profile graphs are utilized to check the adequacy of the reservoir layering system. When required, new simulation layers are introduced into the model.
Mechanistic sector simulation is employed to evaluate the appropriate level to which the simulation model areal cell size are coarsened and still maintained the main heterogeneity features of the geological model. The cells are kept as small as possible in order to keep minimum number of grid blocks between existing producers for future infill wells and sidetrack workovers. Effort is made to make sure that most of the grid cells are mapped exactly over the geological model cells to reduce the unescapable errors introduced in the upscaling process of petrophysical data. The cells are oriented in the direction of the main faults of the field, which were modeled as slanted faults. The design maintained the orhogonlity of grid cells sitting next to the fault surfaces.
Upscaling of the model petrophysical data is a very sensitive and crucial process. Different upscaling techniques were applied to insure best practice. QC tools are developed to check the quality of the upscaling process and its adequacy.
A successful application of the structural and petrophysical data upscaling is a key to the construction of a quality simulation model, which is successfully initialized and in the process of history matching.
Optimisation of the Incremental Development Policy for a Mature Waterflood Project
Authors: Vincent Gilles , Corre Bernard , Lendres Pascal , Charles Thierry 
Published: December 2007

Abstract
The definition of incremental developments, such as additional perforations, work-overs or in-fill wells, for mature fields is sometimes a difficult exercise. The use of reservoir flow simulators is often required to forecast the incremental oil, which can be associated with any new operation. However, in fields with a large number of wells available, the number of possible alternative arrangements can be very large and very difficult to handle for the person in charge of the simulations. The situation becomes even more complicated when interactions appear between the different operations under consideration. In such cases, new tools are needed.
In this paper, we present a methodology for the optimisation of a pressure maintenance project for an offshore reservoir in West Africa. The starting point is a "history matched" dynamic model. The method is based on the use of experimental design. Experimental design can be defined as the strategy for choosing simulations in such a manner that the information required is obtained as efficiently and precisely as possible. In a first part, the theoretical background of the technique will be described briefly. Then application of the method to the field case will be presented. The field has been developed by water flooding for approximately 7 years, with a total of about 30 wells. Prior to our intervention, 11 production wells had been identified as potential candidates for conversion into water injectors.
The work was performed in two phases with two different experimental designs:
Ranking of the 11 candidate wells leading to the identification of the most promising operations. This phase requires a strong reservoir expertise to interpret the simulations results. Detailed determination of the best work-overs to be performed
The final results consist of reservoir simulation runs with the best configurations. The optimal result was obtained by converting 6 of the 11 wells. Use of our methodology enabled a better result to be found more rapidly than by a conventional "trial and error" approach, while keeping to a minimum the number of simulation runs required.

Conclusion:
In this study, we provided the reservoir engineer with an efficient method to manage a problem where a large number of possible combinations could be considered. The methodology used is systematic.

Technical Contributions
Improved K-value Correlation for UAE Crude Oil Components at High Pressures Using PVT Laboratory Data
Authors: Almehaideb R. A. , Ashour I. , El-Fattah K. A. 
Published: December 2007

Abstract
In this paper, 732 high-pressure K-values obtained from PVT analysis of 17 crude oil and gas samples from a number of petroleum reservoirs in the UAE are used. Material Balance techniques are used to extract the K-values of crude oil and gas components from the Constant Volume Depletion (CVD) and Differential Liberation (DL) tests for the oil and gas samples respectively. These K-values are then correlated and the resulting correlation compared with published correlations. Comparisons of results show that currently published correlations give poor estimates of K-values for nonhydrocarbon and hydrocarbon components, while the proposed new correlation improved significantly the average absolute deviation for non-hydrocarbon and hydrocarbon components. The average absolute error between experimental and predicted K-values for the new correlation was 20.5% compared with 76.1% for the Whitson and Torp correlation, 84.27% for the Wilson correlation, and 105.8 for the McWilliams correlation. Additionally, the bubble point and dew point pressures are calculated for these 17 samples and compared with experimental values. The average absolute error in the saturation pressures for the new correlation was 6.08 % compared with 56.34 % for the Wilson correlation, 57.84 % for the Whitson and Torp correlation, and 9.28 % for the Peng-Robinson equation of state with default parameters.