bluuebunny/crossref_metadata_2025 huggingface dataset:
Rock Type Constrained 3D Reservoir Characterization and Modeling
Authors: Silva Fernando P. T. , Ghani Ahmed A. , Al Mansoori Abdulla , Bahar Asnul
Published: December 2007

This paper presents the results of a reservoir characterization and modelling study based on reservoir rock typing (RRT) of Lower Cretaceous carbonate reservoirs in one of Abu Dhabi Onshore oil fields. The final goal is to obtain multiple realizations of 3D descriptions of the petrophysical properties, namely porosity and permeability, which match and are consistent with the underlying RRT scheme, at the grid block level. The RRT were described in all sections of the reservoir for all cored-wells.

The established reservoir rock types were based on depositional facies sequences, diagenetic overprints and petrophysical properties, including pore throat size distribution, porosity and permeability. The model reveals that the vertical changes in the rock types are a function of depositional facies, while the lateral variation down structure across the same lithofacies unit are controlled mainly by diagenesis.

Considering the limited number of cored wells compared to the total number of loged-wells, the characterization started by predicting both permeability and rock type at the non-cored wells. Permeability was predicted using a combination of regression analysis and geostatistics. The use of geostatistics not only has been usefull in capturing the high variability of permeability but also has ensured that the core data is fully honored at plug locations. Rock type was estimated at the non-cored well using discriminant analysis. Consistency checks were been applied to the results of both prediction to ensure consistency between properties and rock types. Non-consistent results were assigned as unestimated-points. A geological conceptual model, in the form of iso-rock type maps, was used to QC the results of the prediction at the non-cored well and as a tool in deriving soft information about the spatial relationship of the different rock types.

The 3D descriptions of the properties were generated using a geostatistical technique. The technique not only honors the conditioning data and spatial relationship of each property, but also honors the local relationship between each property and the rock type. Additionally, some constraints derived from the diagenetic model were implemented in the modeling process to ensure that the model follows the geological conceptual model as much as possible. In transforming the well-log data into the model grid, appropriate scale-up methods and grid-block thickness were selected to ensure that reservoir heterogeneities are maintained. Multiple realizations of the properties were generated in order to capture and to quantify the intrinsic variability of the model. The results of this characterization study will be used for flow performance evaluation.
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

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

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

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

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

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<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

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

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

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

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

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

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

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.
Dynamic Freeze Plug Process Proves a Viable Barrier Technique in Sajaa Field, Sharjah, United Arab Emirates
Authors: Powers Brian S. , Pruitt Randal D. , Tuppen James
Published: December 2007

A Dynamic Freeze Plug Process (DFPP, U.S Patent 5,649,594 Flak, L.H) was applied to several packerless Sajaa Field wells to achieve a second mechanical annular pressure barrier prior to removing the trees for hydraulic, live well work over operations. Four wells were successfully frozen with minimal fluid lost to the formation. Several equipment and procedural modifications made after the first job improved subsequent jobs and reduced the time required to complete the freeze and achieve barrier. The DFPP is a proven technique to achieve an annulus barrier in a gas filled environment.

BP's Drilling and Well Operations Policy requires two independent pressure barriers before any pressure envelope is broken for well interventions. The barriers must be capable of operating independently and simultaneously and must be pressure tested from the direction of flow. Dual tubing barriers are easily achievable with tubing plugs, tubing hanger backpressure valves, or a combination of the tow. The packerless wells in Sajaa Field only have one permanent annular barrier, the metal-to-metal tubing hanger seal, and during normal well operations the annulus is pressured at the surface. Thus, achieving additional annular barriers is more challenging, Sajaa well completions consist of tubing strings landed above the perforations or horizontal lateral zones, or tubing strings set in permanent packers to separate multi-lateral zones (Figures 1a. and 1b.)
Using Artificial Neural Networks to Develop New PVT Correlations for Saudi Crude Oils
Authors: Al-Marhoun M. A. , Osman E. A.
Published: December 2007

Reservoir fluid properties data are very important in reservoir engineering computations such as material balance calculations, well testing, reserve estimates, and numerical reservoir simulations. Ideally, those data should be obtained experimentally. On some occasions, these data are not either available or reliable; then, empirically derived correlations are used to predict PVT properties. However, the success of such correlations in prediction depends mainly on the range of data at which they were originally developed. These correlations were developed using linear, non-linear, multiple regression or graphical techniques.

Recently, researchers utilized artificial neural networks (ANN) to develop more accurate PVT correlations. ANNs are biologically inspired non-algorithmic, non-digital, massively parallel distributive and adaptive information processing systems. They resemble the brain in acquiring knowledge through learning process, and storing knowledge in inter-neuron connection strengths.

The present study presents new models developed to predict the bubble point pressure and, the formation volume factor at the bubble point pressure. The models were developed using 283 data sets collected from Saudi reservoirs. These data were divided into three groups: the first was used to train the ANN models, the second was used to cross-validate the relationships established during the training process and, the last was used to test the models to evaluate their accuracy and trend stability. Trend tests were performed to ensure that the developed model would follow the physical laws. Results show that the developed models outperform the published correlations in terms of absolute average percent relative error, and standard deviation.
Cement: How Tough is Tough Enough? A Laboratory and Field Study
Authors: Mack David J. , Dillenbeck Robert L.
Published: December 2007

Casing is cemented into the wellbore to provide zonal isolation of producing zones, protect fresh water zones from contamination, prevent casing collapse caused by moving salts or sloughing clays and isolate the casing from corrosive brines. In other words, casing is cemented to create annular isolation. Historically, the major physical property of the cement used to determine whether these results would be attained for the life of the well, was the unconfined compressive strength of the set cement.

Recent studies have shown that there are other "strengths or mechanical properties" that are even more important to consider. These strengths include tensile and flexural.

This paper discusses why tensile and flexural strengths must be considered in slurry design, alonf with the interrelationship of compressive, tensile and flexural stresses that occur in wells, and provides Appalachian Basin field examples, where reduced, unconfined compressive strength cement, with enhanced tensile and flexural strengths has been successfully used.
Selection and Evaluation EOR Method Using Artificial Intelligence
Authors: El-M Shokir E. M. , Goda H. M. , Sayyouh M. H. , Fattah Kh. A.
Published: December 2007

Recently, the theory of Artificial Neural Network has found a worldwide approval from those who are concerned with the research in the field of petroleum and natural gas engineering. This may be due to the neural network potentialities in solving problems to which the network is designed, depending on the gained experiences of some similar problems joined with their solutions. This theory has been found to give high possibilities with amazing results as applied and tested in petroleum engineering.

A model composed of two neural networks was designed to work in series in order to perform the task of EOR project selection through the first network (Technical network), and then evaluate the selected project economically using the second network (Economics network). As the model, with the two networks, performs its task successfully, it is then tested with data seeded with certain level of error affecting the parameters given to the model in the test features in order to determine the power of the model and its ability to overcome what we call noisy data.
Study on EOR Mechanisms by Microbial Flooding
Authors: Feng Qing-xian , Zhou Jia-xi , Chen Zhi-yu , Wang Xiao-lin , Ni Fang-tian , Yang Huai-jun
Published: December 2007

We have carried out flooding test with cores, sandpack, pore level model by microbe NG80, special metabolic products (G01, G02, G03) under reservoir temperature. The results are:

Microbes migrated through core pore and fermented in it; microbial concentration has an increasing trend, part of cells were absorbed on sand surface. Oil recovery that flooded by bacteria with concentration 10% is over 6% higher than in water. The highest recovery is 13.8%, flooded at best flooding mode, NG80 products and its constitute; The earlier the time of injecting fermented broth, the better the result obtained; Metabolites bear effect of denudation on oil films; and metabolisms result in alteration of wettability, in witch a special biochemical process and "in situ growth" effects characterized by bacteria take place; Mechanisms observed in the pore level model during microbial flooding are: starting residual oil re-flowing by emulsification-carrying, changing the wettability, denuding oil films and producing "Jamin Effect" in the pores while flooding.

We performed microbial flooding program in G69 block, which has 5 injections wells and 7 drainage points. Mixed original, NG80, 80 and DG2, fermented broth 720m3 was injected in with three slugs during March to July,2001. Monitored preliminary results show that the decline trend of the block oil production was controlled and some wells' production began to increase. That the mechanism of microbial flooding in the oilfield improves poducibility.
Combined Global and Local Optimization Techniques Applied to History Matching
Authors: Schulze-Riegert R. W. , Haase O. , Nekrassov A.
Published: December 2007

Evolutionary Algorithms and local optimization methods are applied to the problem of history matching in reservoir engineering. Application of global optimization methods to history matching of complex reservoir models is generally limited by the convergence behavior. In this paper concepts for an integrated workflow of different optimization methods, parallel computing and statistical analyses are developed.

Global optimization methods and a Bayesian approach to identify best results are combined to improve the convergence behavior. Result data generated in the course of an optimization cycle are used for analyzing sensitivities, correlations and trends of model parameters in a global search space. Statistics are used to reduce the search space by combining correlated model parameters, to exclude less important parameters and to identify regions by correlating well parameters. These techniques are applicable, irrespectively of the quality of a converging objective value.

Results are presented for different complex real three phase reservoir models. The potential and area of applicability is discussed.

In conclusion, results suggest that presented techniques are well prepared to extend the manual process of history matching. The introduction of a workflow based on parallel computing combined with global optimization methods effectively allows to investigate the solution space. Identification of different parameter sets which equally match history data represent an existing model diversity and prepares a basis for uncertainty estimations of production forecasts.
Experiences With Automated History Matching
Authors: Kabir C. S. , Chien M. C. H. , Landa J. L.
Published: December 2007

Matching historical performance of a reservoir is a time-consuming exercise with uncertain outcome. The current practice of manual matching is subjective and goodness of the match owes largely to the experiences of the team members involved in a study and to the quality and quantity of various input and observed data.

This paper describes approaches taken to speed up the history matching effort during the course of replicating multiyear performance of two West African reservoirs. The study entails validation of production data, and matching of single-well and full-field performances with two automated-history-matching (AHM) approaches based on the Gauss-Newton algorithm. These finite-difference results obtained with AHM are contrasted with those obtained from the traditional manual approach.

Results show that both AHM approaches shorten length of a study, and preserve objectivity of a history match. The use of grid coarsening results in impressive speed gain that can quickly provide clues whether adjustments of certain parameters are justified for some wells. That multiple parameter adjustments can be made within specified bounds with a few iterations in a 24-hour run is a profound improvement in our speed of learning of key reservoir flow behavior. This speed, in turn, guides the study in a path that leads to rapid conclusion in a fraction of time taken in a traditional study.
Quantifying Production Strategy Impact in Risk Analysis of an E&P Project Using Reservoir Simulation
Authors: dos Santos J. A. M. , Schiozer D. J.
Published: December 2007

Recent computer developments allow the quantification of geological and physical uncertainties in the appraisal phase of a reservoir using numerical flow simulation. However, such a process is normally performed with a fixed production strategy because a variable strategy is very time consuming. The objective of this work is to study the impact of the production strategy in the risk analysis process. That risk analysis methodology comprises: definition of the uncertain attributes, construction of a base simulation model, selection of the most critical attributes using sensitivity analysis, simulation of all possible models, risk calculation using the Net Present Value (NPV) as the objective function, and choice of a few simulation models that represent the geological uncertainty. An optimization procedure is applied to both base and representative models. Finally, the changes in the objective function are measured and some conclusions and recommendations are made. In this work, two examples are analyzed. In the first case, the study is applied to a real offshore field in Brazil. In the second one, it is considered a very heterogeneous reservoir with greater uncertainty in the structural model and in the hydraulic connectivity between reservoir blocks. Both cases are solution gas drive reservoirs with water injection. In the cases studied, the variation in the NPV due to optimization procedure was small when compared with the uncertainty in the geological model, and changes in the optimized production strategy and investments are not significant, leading to the conclusion that, in such cases, the optimization procedure can be applied only to the base model. The use of a unique production strategy in the whole process can reduce significantly the computational effort. It is also shown that a more accurate result can be obtained by optimizing only selected models called here representative models.
New Developments in Multiblock Reservoir Simulation: Black Oil Modeling, Nonmatching Subdomains and Near-Well Upscaling
Authors: Lee S. H. , Wolfsteiner C. , Durlofsky L. J. , Jenny P. , Tchelepi H. A.
Published: December 2007

In multiblock reservoir simulation techniques, the reservoir model is divided into a number of subdomains or blocks. In our current implementation, these blocks are locally structured but globally unstructured. This representation enables the modeling of geometrically complex reservoir features such as fault surfaces and nonconventional wells while avoiding many of the complications of fully unstructured formulations. In this paper, we present several important developments within this frame-work. These include the extension of a previous two phase flow finite volume formulation to the general black oil case, the implementation of techniques for treating systems in which grid lines do not match between adjacent subdomains, and the application of a near-well radial upscaling technique to the multi-block paradigm. Simulation results illustrating the accuracy and efficiency of these new capabilities are presented. These include a black oil simulation for a local well study, flow through a realistic reservoir with several wells and faults, flow through a fault surface represented by nonmatching grid lines, and a two phase flow simulation demonstrating the applicability of the near-well upscaling procedure to multiblock models. With the new developments presented in this paper, the finite volume based multiblock simulator can be applied to a variety of problems of practical interest.
Use of PEBI Grids for Complex Advanced Process Simulators
Authors: Skoreyko Fraser , Sammon Peter H. , Melichar Herbert
Published: December 2007

PEBI ("perpendicular bisector") grids have been shown in the past to have the potential to reduce computational times for the simulation of relatively straight-forward processes. It is the purpose of this paper to investigate PEBI-based gridding for a much more complex thermal process in a full field setting using commercial simulation products. The goals are to study both computing efficiency and accuracy by comparing results obtained by modelling a field using the more conventional corner point-based gridding with local grid refinement to those obtained using a PEBI gridding approach.

The field in question has been produced for about 20 years, with an operational history that includes cyclic steam stimulation in portions of the field. Many vertical faults have been mapped in the reservoir, and over 140 wells, many of them deviated or horizontal, have been drilled. A simulation study had been done using approximately 170 000 active corner point cells. It was found that the inclusion of foamy oil behaviour was necessary to get a good match of the production history. It appeared though that this simulation was lacking in accuracy near horizontal wells. This was probably due to the inability of the model to align its locally refined grids properly with many of the wells, and the difficulty in getting reasonable refinement levels where cyclic steam stimulation was being carried out, without making the problem considerably larger.

A second simulation study was carried out using a PEBI-based grid. The more flexible aspects of this gridding system allowed construction of a better aligned grid, especially near the horizontal wells and near faults. Moreover, the characteristics of the PEBI-based grid also allowed efficient grading of grid cell sizes, so that particularly fine-scale gridding could be used near wells, while still maintaining an overall model size that was about half that of the corner point model. All processes modelled in the original simulation were replicated in the PEBI-gridded model, including the foamy oil and thermal aspects.

The PEBI gridded model ran in about a third of the time of the original corner point model, and showed accuracy improvements which were attributable to the better placement of grid cells. These results showed that the simulator's ILU-based sparse matrix solver technology was very capable of computing in an unstructured grid environment, even while using cells near wells that were smaller than those used in the corner point model.

Thus, PEBI-based gridding can be used to efficiently model complex processes in a full field setting. These grids can demonstrably improve accuracy and are much more adaptable for modelling near wells and in a complex geological setting. A three-fold run time improvement was noted for the field in question when comparing to a more conventional, corner point gridded model.
High Order Upwind Schemes for Two-Phase, Multicomponent Flow
Authors: Mallison B. , Gerritsen M. , Jessen K. , Orr F. M.
Published: December 2007

In this paper, we investigate high order finite difference schemes for compositional simulation. Results presented for one-dimensional (1D) gas injection problems suggest that a third order essentially non-oscillatory scheme is more accurate and efficient than first order methods and is more robust than traditional total variation diminishing schemes. We investigate also the use of adaptive mesh refinement (AMR) to further improve the efficiency of high order schemes. Preliminary results indicate that the savings in computation time with AMR can be significant for compositional problems. Our 1D results can be extended to three dimensions through conventional finite difference approaches but we plan to apply them in a compositional streamline simulator.
Coupled Simulation of Reservoir Flow, Geomechanics, and Formation Plugging With Application to High-Rate Produced Water Reinjection
Authors: Bachman R. C. , Harding T. G. , Settari A. Tony , Walters D. A.
Published: December 2007

Produced water re-injection at high rates presents a coupled problem of reservoir flow, formation damage, stress alteration around the injector, and fracture propagation. Accurate prediction of permeability changes, fracture propagation pressure, and fracture dimensions is required for minimization of disposal costs and design of surface equipment. The paper presents the formulation and numerical implementation of a coupled reservoir, damage and geomechanical model which includes the above couplings. Details of the model are first described. A simple empirical damage model, calibrated to field data is then presented. Finally, application of the complete model to high rate reinjection in the Masila Block in Yemen is presented. The model predictions show that it is feasible to sustain over 100,000 BWPD in a single Masila disposal well by injecting above fracture pressure.
Coupled Geomechanical and Reservoir Modeling on Parallel Computers
Authors: Gai Xiuli , Dean Rick H. , Wheeler Mary F. , Liu Ruijie
Published: December 2007

In coupled geomechanics and reservoir modeling, the finite element discretization of the force balance equation leads to very large linear systems, whose solution is both time and memory consuming. ICCG (Incomplete Cholesky Factorized Conjugate Gradient) is a popular technique for solving for displacements, but the technique is limited to about 60,000 nodal points on desktop machines. Most large 3D field scale problems will have to be run on parallel machines. In this paper, we present a reduced-communication, super coarsening multigrid method that can be combined with other domain decomposition-based preconditioner to achieve faster convergence with high parallel scalability. A preliminary test case of 1.5 million grid blocks with up to 59 processors shows a parallel efficiency of above 90%.
Uncertainty Quantification to Evaluate the Value of Information in a Deepwater Reservoir
Authors: Portella R. C. M. , Salomão M. C. , Blauth M. , Duarte R. L. B.
Published: December 2007

In petroleum industry, the development of oil resources is performed under strong uncertainty conditions, not only related to the geological and reservoir characterization, but also concerning the economic parameters. Depending on the number of appraisal wells drilled at the time of the decision, we may choose to start the execution of the development plan, or to pay for more information. This includes the realization of a new seismic acquisition, the drilling of a new well, or the execution of pressure tests.

In the present work, we applied a value of information analysis, under uncertainties conditions, to optimize the exploitation of a new block in a deep water field, located in Campos Basin, Brazil. The reservoir rock consists on high permeability sandstone, with good lateral continuity, without internal sealing faults. The most important properties that impact the volumetric uncertainty are the net to gross relation, and the position of the oil-water contact. Equally, the dynamic parameter that strongest affect the recovery factor are the absolute permeability and the well productivity. In order to simultaneously study the geometric and dynamic uncertainties and minimize the number of simulation runs, we performed an experimental design process

The calculated economic value of the information from the new well, which results essentially from the optimization of the exploitation project, was much higher than its cost, recommending for its application. In contrast, the anticipated production did not show to be advantageous, and was discarded. Based on these results, the new well was drilled, and the reduction of the volumetric uncertainty permitted to implement a sharper design to the exploitation project.