bluuebunny/crossref_metadata_2025 huggingface dataset:
Constraining a Complex Gas-Water Dynamic Model Using 4D Seismic
Authors: Pannett Stephen , Slager Sven , Stone Greg , Dekker Sanne
Published: December 2007

The Maui C Sands reservoir contains most of the remaining gas-condensate reserves in the mature Maui Field. Technical and commercial management of a hydrocarbon producing field such as Maui relies heavily on the confidence in the forecasted production and reservoir performance predicted by dynamic reservoir models. This paper describes how the complex dynamic model of this reservoir has been constrained by detailed information gained from the interpretation of a timelapse 3D seismic survey (4D). Firstly, the paper briefly discusses the reasoning for acquisition of time lapse seismic at this stage of field life. Next, the interpretation results are presented, highlighting the level of detailed vertical and areal resolution achievable in the timelapse response in a stratified gas-water system such as the Maui C Sands reservoir. These results are supported by evidence of correlation between the timelapse seismic results and timelapse saturation well logging. The paper then discusses the methodologies applied to incorporate these interpreted results into the history matching of the dynamic model, and how this has constrained the quantification of remaining reserves. A check of how closely the model matches the seismic data is made by comparing synthetic timelapse seismic generated from the dynamic model with the actual timelapse seismic. Finally, further insights are presented on the implications of timelapse seismic results on the current structural understanding of the field, and the impact on future development planning.
A New Gravimetric – Swelling Test for Evaluating Water and Ion Uptake in Shales
Authors: Zhang Jianguo , Chenevert M. E. , AL-Bazali Talal , Sharma M. M.
Published: December 2007

The primary cause of wellbore instability is the interaction of water-based muds with shales. The movement of water and ions into or out of a shale can result in large changes in pore pressure in the vicinity of the wellbore, potentially leading to wellbore failure.

A new method, the Gravimetric – Swelling Test (GST), for determining the compatibility between shales and drilling fluids is presented in this paper. An experimental protocol and equations are presented that describe how such measurements can be conducted and interpreted with relative ease. The mass of water and ions entering or leaving shale samples is determined. With additional swelling measurements, the impact of the water and ions uptake on swelling pressures generated can also be obtained.

In this paper, results are presented for two preserved shale samples obtained from the field. The influence of different types of ionic solutions on water and ion movement is presented for each shale. It is shown that water uptake and swelling of shales is controlled not only by differences between shale water activity and water activity in the mud (as assumed in the past), but ion type and concentration also play an important role. In these tests the water uptake decreases, while the ion adsorption increases with increasing salt concentration. Different types of cations are shown to have a large influence on water/ion movement.

This paper presents a data set showing the influence of ion type and concentration on water uptake by shales. The role of capillary pressure, osmotic effects and ionic diffusion on swelling behavior of shales is also discussed. The technique presented herein may possibly be used at the rig-floor to determine the compatibility of shales with salt-water drilling fluids.
Drift-Flux Parameters for Three-Phase Steady-State Flow in Wellbores
Authors: Shi H. , Holmes J. A. , Diaz L. R. , Durlofsky L. J. , Aziz K.
Published: December 2007

Drift-flux models represent multiphase flow in wellbores or pipes in terms of a number of empirically determined parameters. Because of the lack of data for two and three-phase flow in large-diameter inclined pipes, existing parameters are commonly based on small-diameter pipe experiments, which can lead to significant errors when the models are applied to wellbore flows. In this work, we use recent large-diameter experimental data for the determination of drift-flux parameters for oil-water-gas flow. The parameters are computed through application of an optimization procedure. It is shown that gas holdup in three-phase systems can be estimated using a two-phase flow model by viewing the system as an effective gas-liquid system, with oil and water comprising the 'liquid' phase. This approach is, however, generally inaccurate for the determination of oil and water holdups, in which case the effect of gas must be taken into account. Specifically, for pipe inclinations away from horizontal, even small amounts of gas can act to eliminate the slip between oil and water. As the pipe deviation approaches horizontal, however, oil-water slip persists, even in the presence of gas. We develop and apply a unified two and three-phase flow model to capture this gas effect. The new model is shown to provide much more accurate predictions for oil and water holdups in three-phase systems than were achievable with previous models.
Effect of Grid Size in Risk Assessment of Petroleum Fields
Authors: Ligero Eliana L , Schiozer Denis J , Maschio Célio
Published: December 2007

It was shown recently that it is important to evaluate risk through probabilistic methodologies that involve a high number of simulation models because of the number of uncertain attributes. Geological modeling yields reservoir models that are represented through fine grids with millions of blocks. A probabilistic risk evaluation based on such grids would require a very high computational effort. Therefore, an upscaling procedure is necessary to reduce the grid size but it is difficult to select a grid size that could represent an adequate balance between precision of risk assessment and computational effort.

The methodology applied to quantify risk involves a sensitivity analysis in order to reduce the number of critical attributes and the simulation of reservoir models obtained through all possible combinations of these attributes. After the simulation of the models, a statistic treatment is used to evaluate the risk involved in the process. Several procedures can be used to speedup the process; however the number of simulation runs may be very high. Upscaling of the simulation models can decrease significantly the computational effort and global time of the risk analysis process but it can also yield an inadequate risk assessment.

In this paper the effect of the grid size on the process is evaluated. It was developed a methodology (1) to select an adequate grid size and (2) to speed up the risk analysis process. The choice of geological representative models from coarse grid risk evaluation can to be useful to represent the risk on fine model, avoiding the simulation of all fine models, yielding a significant speedup up of the process.

Practical applications of upscaling in a probabilistic risk assessment, that use the concept of representative models selected to characterize geological uncertainties, are shown through calculations performed in a petroleum field represented by a fine grid simulation model with geological uncertainties.
A Comparative Study of Laboratory Techniques for Measuring Capillary Pressures in Tight Gas Sands
Authors: Newsham K. E. , Rushing J. A. , Lasswell P. M. , Cox J. C. , Blasingame T. A.
Published: December 2007

This paper presents results from a laboratory study comparing capillary pressure measurement techniques for tight gas sands. Included in our evaluation are the more traditional high-speed centrifuge and high-pressure mercury injection methods as well as the less conventional high-pressure porous plate and vapor desorption techniques. The results of our study show significant differences between the mercury injection data and composite capillary pressure curves constructed with data from the other three methods. Consequently, we have concluded that high-pressure mercury injection can be used to quantify pore size distribution, but often inaccurately characterizes capillary pressures, particularly at the irreducible water saturation. Moreover, our study suggests that a composite capillary pressure curve constructed from a combination of the vapor desorption data for the low water saturation range and high-speed centrifuge or high-pressure porous plate data for the high saturation range provides the most accurate capillary pressures for tight gas sands.
Generalized Capillary Pressure and Relative Permeability Model Inferred from Fractal Characterization of Porous Media
Authors: Li Kewen
Published: December 2007

The Brooks-Corey capillary pressure model has been accepted widely in the petroleum and other industries. However the Brooks-Corey model cannot represent capillary pressure curves of some rock samples such as those from The Geysers geothermal field. In fact, few existing capillary pressure models work for these rock samples. To this end, a more general capillary pressure model was derived theoretically from fractal modeling of a porous medium. It was found that the more general capillary pressure model could be reduced to the frequently-used Brooks-Corey capillary pressure model and the Li-Horne imbibition model when the fractal dimension of a porous medium takes a limiting value. This also demonstrates that the Brooks-Corey model and the Li-Horne model, which have been proposed empirically, have a solid theoretical basis. The results demonstrated that the new capillary pressure model could represent the capillary pressure curves of The Geysers rock while the Brooks-Corey model cannot. A relative permeability model was also developed from the new capillary pressure model. Fractal dimension, a parameter associated with the heterogeneity of the rock, determines the shape of relative permeability curves according to the new relative permeability model. The model can also be reduced to the Brooks-Corey relative permeability model.
Estimates for the Growth of a Condensate Bank from a Simple Compositional Model
Authors: von Schroeter Thomas , Gringarten Alain C.
Published: December 2007

This paper studies the growth of a region of liquid drop-out in gas condensate reservoirs. For this purpose, we develop a line source solution for a two-phase compositional flow model in which the thermodynamic properties of the phases are modelled by a cubic equation of state with zero binary interaction coefficients, gravity and capillary pressures are neglected, the formation is assumed to be laterally unbounded and homogeneous, and the production rate constant over time. The absence of fixed time or length scales allows a similarity transformation under which the governing equations reduce to a system of coupled ordinary differential equations in the similarity (Boltzmann) variable with two fixed and two free boundary conditions. As an example, we include simulation results obtained with data from a gas condensate field in the North Sea.
Analytical Modeling for Two-Phase EOR Processes: Splitting between Hydrodynamics and Thermodynamics
Authors: Pires A. P. , Bedrikovetsky P. G. , Shapiro A. A.
Published: December 2007

Compositional models describe chemical flooding and gas-based IOR processes. It is possible to show from the known analytical solutions of multicomponent polymer/surfactant flood, that the concentration "part" of the solution is completely defined by adsorption isotherms and does not depend on relative permeability and phase viscosities. Analytical models for 1-D displacement of oil by gas have been developed during last 15 years. It was observed from semi-analytical and numerical experiments that several thermodynamic features of the process (MMP, key tie lines, etc) are independent of transport properties.

In this paper, we introduce potential coordinates that allow for splitting of the compositional model into a thermodynamics auxiliary system and one transport equation. The number of auxiliary equations is less than the number of equations in the compositional model by one. Explicit projection and lifting procedures are derived. The splitting is valid for either selfsimilar continuous injection problems or for non-self-similar slug injection problems. Analytical models for displacement of oil by a polymer slug and for oil displacement by rich gas slug with lean gas drive were developed by the splitting procedure.

With respect to 3-D flows, splitting takes place only for the case of constant total mobility.
Subsidence and Horizontal Earth Surface Movement During Reservoir Depletion for 3D Reservoirs With 3D Earth Surface
Authors: Suzuki Ikkou , Morita Nobuo
Published: December 2007

Oil or gas production causes reservoir depletion. It induces reservoir compaction and subsidence and earth surface lateral movement. Gas and oil are found in 3D shape traps such as anticline traps, and inclined fault traps. In addition, the earth surface above such 3D reservoirs, where we observe subsidence and lateral movement, may not be flat, that is, mountains or valleys may exist above the reservoirs. The subsidence and horizontal movement are affected by the size and the location of mountains above reservoirs and also they are affected by the 3D reservoir shape. This paper analyzes 3D reservoir and earth surface geometry effects on subsidence and horizontal earth surface movement during reservoir compaction.
Asphaltene Precipitation in a Saturated Gas-Cap Reservoir
Authors: Kokal Sunil , Al-Dokhi Mohammad , Al-Zubail Makki , Al-Saeed Saeed
Published: December 2007

Asphaltene deposits were obtained from three high gas/oil ratio (GOR) wells in an offshore field in the Arabian Gulf. The reservoir is saturated and there is a gas-cap present in the field. In many wells the gas cones into the producing wells and causes precipitation of asphaltenes from the crude by stripping. These asphaltenes deposit in the wellbore and have the potential to create plugging problems.

This paper describes the results of an investigative study that was initiated to determine the precipitation mechanism and ways to alleviate the deposition problem. Asphaltene precipitation experiments were conducted at reservoir conditions in a special pressure-volume-temperature (PVT) apparatus. The effect of GOR on asphaltene precipitation was determined by titrating the reservoir oil with gas-cap gas. Bulk deposition tests were also performed at different GORs with reservoir fluids. The results demonstrate that the onset of asphaltene precipitation occurs at relatively low GOR values. The amount of asphaltene precipitated at the onset is small. Asphaltene precipitation and deposition increase with increasing GORs. Asphaltene deposition envelopes are provided for the reservoir oil as a function of pressure and temperature. Recommendations were made to alleviate the problem by controlling the maximum producing GORs to less than 1000 scf/stb. Recipes for solvent treatment including asphaltene dispersants are also described in the paper and are currently being considered for implementation in the field.
Predicting the Impact of Non-Newtonian Rheology on Relative Permeability Using Pore-Scale Modeling
Authors: Lopez Xavier , Blunt Martin J.
Published: December 2007

Polymers are frequently used in waterflooding to ensure stable displacement and to control excessive water production. The viscosity of the polymer is a function of shear rate. Typically they are shear-thinning fluids whose apparent viscosity in a porous medium decreases with increasing flow rate.

We use pore-scale network modeling to predict the single-and multi-phase properties of shear thinning fluids in porous media. The model uses networks that represent the disordered topology of real rocks. For single-phase flow we can accurately predict experimentally measured relationships between apparent viscosity and flow rate.

We simulate two-phase primary drainage and secondary imbibition in a water-wet system, where the wetting phase (polymer in aqueous solution) is non-Newtonian (shearthinning) while the non-wetting phase (oil) remains Newtonian. We can predict the relative permeabilities for Newtonian fluids in Berea sandstone accurately. We then use the pore-scale model to predict trends in relative permeability as a function of flow rate in Berea sandstone for a non-Newtonian wetting phase. The relative permeability is defined as the ratio of the flow rate in multi-phase flow to the corresponding flow rate in single-phase flow with the same pressure gradient with the same shear-thinning fluid. The non-Newtonian phase relative permeability initially decreases with increasing pressure gradient before increasing again, while always remaining below the Newtonian values. This effect is most pronounced at low wetting phase saturation. When the wetting phase is confined to layers in the pore space, the shear rate is less than that experienced in single-phase flow when the pore is completely filled with fluid. This leads to higher effective viscosities and an apparent decrease in relative permeability.
Revisiting Ekofisk and Eldfisk Wettability
Authors: Hamon G.
Published: December 2007

The Ekofisk and Eldfisk fields, located in the North Sea, are currently waterflooded to increase the oil recovery of these naturally fractured, low matrix permeability, chalk reservoirs. The wettability of these reservoirs has long been a concern due to the extensive fracture network and was widely studied. However, the large and unexplained scatter in wettability index, the discrepancy between laboratory and water injection results questioned the representativity of laboratory data. Recently, a review of 370 wettability tests has been performed. The effect of a large number of parameters has been investigated, including reservoir data and core handling and laboratory procedures.

The main results of this review are: A strong relationship in both the Ekofisk and Eldfisk fields between the water wetness and the elevation above the free water level, whatever the laboratory experimental conditionsA clear tendency of increasing water-wet characteristics with depth,A significant noise regarding this main trend due to experimental conditions

In the second part of this paper, the method used to generate the matrix water-oil relative permeability curves using pore network modelling is described. This approach allows incorporating the variations of both the rock characteristics and of the depth dependent wettability and complements the experimental core floods when no data is available for a given combination of lithology and wettability.
Optimizing Fracturing Fluid Cleanup in the Bossier Sand Using Chemical Frac Tracers and Aggressive Gel Breaker Deployment
Authors: Sullivan R. , Woodroof R. , Steinberger-Glaser A. , Fielder R. , Asadi M.
Published: December 2007

Proper fluid and proppant placement are critical to a successful propped fracture stimulation treatment. Despite effective placement of the treatment, well performance is often detrimentally affected by incomplete gel breaking and fluid recovery. A technique employing a family of environmentally friendly, fracturing fluid compatible chemical tracers has been employed for quantifying segment-by-segment fracturing fluid recovery. Utilizing this technology, it is demonstrated that individual fluid segment cleanup and recovery can be enhanced by optimizing fracturing fluid selection and by using aggressive gel breaker deployment schemes. The validation of improvements in fracturing fluid cleanup and the resultant effects on well performance are presented using Bossier Sand case histories. Comparisons between crosslinked gel systems and between conventional and aggressive gel breaker deployment schemes are highlighted.
Carbon Dioxide Sequestration in Coal Seams: A Parametric Study and Development of a Practical Prediction/Screening Tool Using Neuro-Simulation
Authors: Odusote Olufemi , Ertekin Turgay , Smith Duane H. , Bromhal Grant , Sams W. Neal , Jikich Sinisha
Published: December 2007

Fossil fuels are a major source of the world's energy production and this is expected to be the case well into the 21st century. Consequently, the extensive utilization of fossil fuels has measurably increased the total load of one of its byproducts, carbon dioxide (CO2), in the atmosphere and concern about the effects on global warming has prompted the inception of various methods and policies geared at reducing the concentration of this green-house gas in the atmosphere. One of the more promising technologies is CO2 sequestration which involves the capture, separation and storage of CO2.

Production of coalbed methane is a well-developed technology, but enhanced recovery by CO2 injection has undergone relatively limited research. Recent research suggests that CO2 preferentially sorbs to coal, replacing the coalbed methane which can be produced and sold to offset the costs of sequestering CO2 thereby providing a dual role for unmineable coal seams; a source of coalbed methane and a repository for the sequestration of CO2. Production operations from a carbon dioxide-enhanced coalbed methane recovery pilot project, in the San Juan Basin, indicate that the process is technically and economically feasible.

In this work, PSU-COALCOMP, a compositional coalbed methane reservoir simulator, is used to model the primary and enhanced recovery of coalbed methane by CO2 injection for a variety of coal properties and operational scenarios. The results obtained from the simulations performed include the cumulative amount of CO2 injected and retained in the coal seam, the cumulative amount of coalbed methane produced as well as the CO2 breakthrough time. These results are considered as the performance indicators of the CO2 sequestration process. The effects of various intrinsic coal-seam properties and operational scenarios on the performance indicators of CO2 sequestration are investigated to develop a better understanding of the process.

Based on the data, results and analyses obtained from the simulations performed during the parametric study, a CO2 performance predictor tool is developed by employing neurosimulation methods. This tool is able to predict the values of the performance indicators of the CO2 sequestration process for a wide range of coal-seams and various production schemes within an acceptable margin of error and in a timely and efficient manner. The predictive capabilities of this tool also enables it to be used as a screening tool that has the ability to ascertain the viability of various coalbed reservoirs for the sequestration of CO2, as well as the optimum production scheme to be used in any given project.
An Improved Implementation of the LBFGS Algorithm for Automatic History Matching
Authors: Gao Guohua , Reynolds A. C.
Published: December 2007

For large scale history matching problems, where it is not feasible to compute individual sensitivity coefficients, the limited memory Broyden-Fletcher-Goldfarb-Shanno (LBFGS) is an efficient optimization algorithm1,2. However, computational experiments reveal that the original implementation of LBFGS may encounter the following problems: (i) the algorithm often does not give as good a match of production data as is expected; (ii) occasionally a bad search direction is encountered that either leads to false convergence or a restart with the steepest descent direction which radically reduces the convergence rate; (iii) on rare occasions, the LBFGS converges to a model which results in overshooting/undershooting problems, i.e., converges to a vector of model parameters which contains some abnormally high or low values of model parameters. This overshooting/undershooting occurs even though all history matching problems are formulated in a Bayesian framework with a prior model providing regularization.

Here, we show that the rate of convergence and the robustness of the algorithm can be significantly improved by: (1) a more robust line search algorithm motivated by the theoretical result that the Wolfe conditions should be satisfied; (2) an application of data damping procedure at early iterations; (3) rescaling of model parameters prior to application of the optimization algorithm; (4) an application of constraints on the permeability/porosity fields; and (5) a minor modification of the LBFGS updating formula for the inverse Hessian matrix calculation.
Applications of New Reservoir Simulation Technology in GOM Oil Fields
Authors: Litvak Michael , Johnson Daniel , Towery Lisa
Published: December 2007

The applications of the following new reservoir simulation tools are presented in the paper: Latest achievements in geophysics for the construction of sand/shale 3-D volumes based on seismic spectral decomposition;Synthesis of rock physics and fluid PVT analysis for correlation of seismic data to reservoir properties;Geostatistical modeling constrained by seismic and well data;History matching based on production data and time lapse seismic;Integrated reservoir and facility modeling;Field production optimization.

Object based geostatistical modeling tools are applied for the construction of the 3-D facies models constrained by seismic, well data and consistent with depositional environment. The placement of these facies bodies is conditioned to a seismically derived sand/shale 3-D volume used to detect differences in a dual-facies system. The main purpose of adding the generation of these facies bodies into the workflow was to add internal heterogeneities to the model both laterally and vertically, and to ensure proper facies placement at the well locations.

Three-dimensional models of reservoir properties (net-to-gross ratio, porosity, permeability, and initial fluid saturations) are built using geostatistical methods with seismic and well constraints. Correlations from rock physics are applied to directly derive rock properties from seismic attributes (separately for each facies). The seismically derived rock properties are used as the 3-D trends in the geostatistical modeling.

Integrated modeling of multiphase fluid flow in reservoir, well tubing strings, pipeline system, and separation facilities are applied. Production optimization tools are used to determine well production/injection rates constrained by well and surface facility limitations.

The applications of the new simulation technology in Gulf of Mexico (GOM) oil fields are presented. Included examples demonstrate robustness of the integrated models of reservoir geology and surface facilities and their business values. New reservoir simulation tools presented in the paper are very general and they are applicable in large variety of oil and gas fields.
A Stochastic Optimization Algorithm for Automatic History Matching
Authors: Gao Guohua , Li Gaoming , Reynolds A. C.
Published: December 2007

For large-scale history matching problems, optimization algorithms which require only the gradient of the objective function and avoid explicit computation of the Hessian appear to be the best approach. Unfortunately, such algorithms have not been extensively used in practice because computation of the gradient of the objective function by the adjoint method requires explicit knowledge of the simulator numerics and expertise in simulation development. Here we apply the simultaneous perturbation stochastic approximation (SPSA) method to history match multiphase flow production data. SPSA, which has recently attracted considerable international attention in a variety of disciplines, can be easily combined with any reservoir simulator to do automatic history matching. The SPSA method uses stochastic simultaneous perturbation of all parameters to generate a down hill search direction at each iteration. The theoretical basis for this probabilistic perturbation is that the expectation of the search direction generated is the steepest descent direction.

We present modifications for improvement in the convergence behavior of the SPSA algorithm for history matching problems and compare its performance to the steepest descent, gradual deformation and LBFGS algorithm for history matching examples. Although the convergence properties of the SPSA algorithm are not nearly as good as our most recent implementation of a quasiNewton method (LBFGS), the SPSA algorithm is not simulator specific and it requires only a few hours of work to combine SPSA with any commercial reservoir simulator to do automatic history matching.

To the best of our knowledge, this is the first introduction of SPSA into the history matching literature. Thus, we make considerable effort to put it in a proper context.
Direct Prediction of the Absolute Permeability of Unconsolidated and Consolidated Reservoir Rock
Authors: Jin Guodong , Patzek Tad W. , Silin Dmitry B.
Published: December 2007

A procedure of estimating the absolute rock permeability directly from a microscopic 3D rock image has been developed. Both computer-tomography and computer-generated images of reconstructed reservoir rock samples can be used as input. A physics-based depositional model serves to reconstruct natural sedimentary rock, and generate 3D images of the pore space at an arbitrary resolution. This model provides a detailed microstructure of the rock, and makes it possible to calculate the steady state velocity field in the single-phase fluid flow. In particular, using our model, one can analyze unconsolidated rocks whose micro-tomographic images cannot be obtained. The lattice-Boltzmann method is used to simulate viscous fluid flow in the pore space of natural and computer-generated sandstone samples. Therefore, the permeability is calculated directly from the sample images without converting them into a pore network or solving Stokes' equation of creeping flow. We have studied the effect of compaction and various styles of cementation on the microstructure and permeability of reservoir rock. The calculated permeability is compared with the Kozeny-Carman formula and experimental data.
Three-Phase Flow in Porous Media: Wettability Effect on Residual Saturations During Gravity Drainage and Tertiary Waterflood
Authors: Caubit C. , Bertin H. , Hamon G.
Published: December 2007

Three-phase flow configurations occur in many situations in petroleum engineering, gravity assisted gas displacement, tertiary waterflood, water alternating gas process (W.A.G.). Therefore residual saturations (oil and gas) knowledge during three-phase flow is a crucial point for reservoir engineers.

In this paper we present experimental results dealing with the influence of wettability on two and three-phase flow in porous media in short (0.25m) and long (1m) cores.

Forced displacement of gas by water and oil have been performed on the short cores while gas/oil gravity drainage in presence of irreducible water (Swi) followed by a tertiary waterflood have been performed on the long cores.

For all the experiments the saturation profiles are measured using a dual-energy gamma-ray attenuation technique.

Originality of the experiments lies on the fact that gas/oil gravity drainage and tertiary waterflood are performed on the same core during the same experiment. Two phase flow is obtained at the bottom of the core (in the capillary head region) while three-phase flow is observed in the upper part of the core. Local measurement of saturation profiles show that residual oil saturation at the end of gravity drainage depends on wettability. However we do not observe a wettability effect on three-phase residual gas saturation. Behaviour of three-phase residual oil saturation is much more complicated because its value and saturation profile depends strongly on wettability.
Evaluation Study of Various Produced-Water Treatment Technologies to Remove Dissolved Aromatic Components
Authors: Descousse A. , Mönig K. , Voldum K.
Published: December 2007

In the frame work of the zero discharge work ongoing in Norway, all oil companies operating on the Norwegian Continental Shelf have been obliged to deliver a field specific strategy to the Norwegian Pollution Control Authority (SFT) in 2003 explaining how to achieve the zero discharge goal in 2005. A high focus within the various presented strategies was given to the implementation of new technology or combination of existing and new technologies, especially for reducing the amount of harmful aromatic components. These components often constitute a considerable contribution to the total environmental risk of produced water.

The traditional technologies such as separators, hydrocyclones, etc. in general only remove dispersed oil and the aromatic fraction dissolved in the oil phase. However, fairly new water treatment technologies on the market are also able to remove the aromatic components dissolved in the water phase. These new technologies are usually based on extraction, stripping or adsorption technology.

By knowing the amount of aromatic components present in the dispersed oil, the removal of aromatics by traditional treatment techniques can be assessed. The results from such an assessment are presented in this paper for the Ekofisk field and compared to results from other fields, all located in the North Sea. Based on these results and on recent pilot field tests on Ekofisk, various new technologies such as CTour and Cetco units have been evaluated for their possible increased efficiency on the removal of aromatics from the water phase, compared to traditional technologies.
When is Steady-State Upscaling Valid?
Authors: Jonoud S. , Jackson M. D.
Published: December 2007

Steady-state upscaling techniques for multi-phase transport properties have been proposed as an alternative to dynamic methods because they are faster and simpler to implement: there is no need for fine grid simulation and the upscaled transport properties are not case dependant. However, although their speed and ease of implementation is attractive, it is still not clear under what circumstances the assumption of steady state is valid and whether the upscaled transport properties properly capture flow.

We have run numerical experiments on some simple geological systems, to investigate the validity of the capillary equilibrium limit (CEL) method, in which it is assumed that capillary forces dominate the distribution of fluids. The CEL method is likely to be valid at small length scales and low flow rates.

We begin by demonstrating that existing criteria are not sufficient to accurately specify the conditions under which the method is valid. Upscaling using steady-state methods outside this range can yield significant errors in predicted recovery. However, we are able to match upscaled and fine grid simulation results under a different range of conditions. We have derived a new set of criteria to specify the conditions under which the CEL method is valid, which are applicable to a variety of different geological heterogeneities including those in which capillary trapping occurs.

We find that the CEL method can be applied over length-scales of up to tens of meters for thinly laminated systems (i.e. high aspect ratios) and with low to near typical flow rates. Our results demonstrate that the CEL method can be used in the first step of a two-step upscaling process, to generate effective multi-phase transport properties quickly and cheaply which capture the impact of small-scale heterogeneities at the scale of a geological model grid-block.
Use of a Fiber Optic Pressure/Temperature Gauge in an Exploration Well to Minimize Formation Damage Potential and Reduce Costs During Production Testing
Authors: Bond Andy , Blount Curt , Kragas Tor , Mathias Steve
Published: December 2007

The addition of real-time, permanent, downhole pressure and temperature monitoring systems to completion design is often regarded as a "nice to have" that is difficult to economically justify. Management is hesitant to commit up-front capital for downhole surveillance systems whose value is uncertain and not easy to quantify and whose reliability in the past has sometimes been less than outstanding. However, in recent years the reliability of many conventional systems has improved and new, high-reliability alternative sensing technologies such as fiber optics have become available. In addition, the value of real-time downhole data in both production and reservoir management is becoming more and more recognized and demonstrated in case studies.

This paper discusses the installation, application, and value of a permanent fiber optic pressure and temperature gauge system installed in a sidetrack of an exploration well at Cape Starichkof, Alaska in June, 2003 (Fig. 1). Prior experience in the original completion and testing of this well suggested that significant formation damage might have been caused due to the lack of real-time pressure drawdown data during initial production well testing. Because of the importance of the real time data, a conventional electronic gauge was included in the completion design for redundancy. The gauges were installed and subsequently operated in this well to provide real time bottom-hole flowing pressures and temperatures. Challenges and unique aspects of the installation included survival of the gauge during multiple trips in and out of the hole and a splicing operation below the tubing hanger. Comparisons of data from the two gauges and the value of having the ability to obtain high resolution downhole shut-in buildup information during the multi-stage tests are discussed. Fiber optic gauge data proved invaluable in monitoring flowing pressures during initial well productivity tests and providing downhole pressure buildup data during shut-ins. The high speed, high resolution data stream from the fiber optic gauges allowed the well to be tested without significant damage to the formation and in a minimum time period.
Analysis of Imbibition in Mixed-Wet Rocks Using Pore-Scale Modeling
Authors: Behbahani Hassan , Blunt Martin J.
Published: December 2007

Counter-current imbibition is an important recovery mechanism during waterflooding in fractured reservoirs. While this may be a rapid and efficient recovery process in strongly water-wet systems, the vast majority of reservoirs show some mixed-wet or oil-wet characteristics. If the reservoir is mixed-wet, it is possible for some water to imbibe spontaneously, but the ultimate recovery is lower and the imbibition rate may be several orders of magnitude slower than for strongly water-wet rock.

We use quasi-static pore-scale network modeling as a tool to study the behavior of mixed-wet rocks and to predict relative permeability and capillary pressure. The model uses a topologically disordered network that represents the pore space of Berea sandstone. We adjust the distribution of contact angles at the pore scale to match previously publised experimental co-current waterflood recoveries and wettability indices on Berea. We then input the relative permeabilities and capillary pressures into a conventional grid-based code and simulate counter-current imbibition in one dimension. We make predictions, with no matching parameters, of the recovery as a function of time and compare the results with the experimental measurements. We are able to reproduce the observed dramatic increase in imbibition time as the system changes from being water-wet to mixed-wet. In a mixed-wet system spontaneous imbibition, where the capillary pressure is positive, is limited to a narrow saturation range where the water saturation is small. At these low saturations the water is poorly connected through the network in wetting layers and the water relative permeability is extremely low, leading to recovery rates tens to thousands of times slower than for water-wet media.

We present a semi-empirical equation to correlate imbibition recovery in mixed-wet rocks with different wettability states and for a wide range of viscosity ratios. We show that the recovery rate is proportional to the water mobility at the end of imbibition.
A Framework for History Matching Using Local Optimization in Streamline Defined Regions
Authors: Barthelemy Maud , Fenwick Darryl H. , Gautier Yann , Blunt Martin J.
Published: December 2007

We develop a general methodology for history matching that uses the method of local deformation and streamline-based simulation. We generate a geostatistical realization that can obey constraints at wells and other geological information. The history matching process consists in a chain of optimizations. First, streamlines are used to define regions of the field influencing each producer. In each step of the chain one single parameter is used to deform the reservoir description in each streamline-defined region independently. The optimum value of the deformation parameter that minimizes for each well the mismatch between observed and predicted data is found. Then, the reservoir description is updated and the streamline regions are re-defined. A new chain begins and the process continues.

We demonstrate that the objective function is an irregular, multiple valued function of the deformation parameters, making optimization using a gradient-based method difficult. We also define objective functions based on matching time moments of the production data. This approach does not eliminate the multiple-valued nature of the objective function.

We test the validity of the local deformation method on a simple case. We compare it with the global deformation method on this same case.
Effects of OBM Invasion on Irreducible Water Saturation: Mechanisms and Modifications of NMR Interpretation
Authors: Chen J. , Hirasaki G. J. , Flaum M.
Published: December 2007

In this study, the effects of synthetic oil base mud (OBM) surfactants (emulsifiers and oil-wetting agents) on wettability alteration, NMR response and irreducible water saturation (Swir) were systematically examined with Berea and limestone cores. Results show that the originally strongly water-wet Berea and limestone cores are altered to be intermediate-wet or oil-wet by OBM surfactants. As a result, Swir from NMR T2,cutoff model with the default assumption of water-wetness generally underestimates the measured value. The magnitude of underestimation depends on three parameters: the type of OBM surfactants, their concentration in the flushing fluid, and the flushing volume. The magnitude of underestimation correlates with the Amott-Harvey wettability index. These results suggest that the effects of OBM invasion on estimation of Swir can be minimized by controlling the volume of OBM invasion and the concentration of OBM surfactants.

The mechanisms of Swir underestimation and modifications of NMR interpretation when wettability alteration occurs were investigated. In the case of an oil-bearing zone at irreducible water saturation, OBM invasion does not significantly decrease the actual Swir, but changes the water and oil relaxation time distributions due to wettability alteration. This is visualized by the diffusion editing technique. When wettability alteration occurs (water-wet to intermediate-wet or oil-wet), a T2, cutoff value larger than the one based on water-wetness is needed because the irreducible water relaxes at a longer relaxation time. Correlation between this modified T2,cutoff value and the Amott-Harvey wettability index was found.
Rotating Jet Technology Improves Stimulation Fluid Placement to Effectively Treat Horizontal and Gravel Packed Wells – Lab Model Tests and Global Results Are Reviewed
Authors: Stanley F. O. , Serrano Fabrizio , Knopp Steve
Published: December 2007

Effective placement of stimulation fluids on horizontal, long interval and/or gravel-packed wells is critical for cost-efficient production enhancement. Successful case history work in 19991, using precision rotary jetting technology (R-Jet) on the end of coiled tubing (CT), demonstrated to the oil and gas industry that fluid placement is a key factor in removing near-wellbore damage and optimizing well stimulation treatments.

This paper will review continued efforts relating to precision rotary jet technology including extensive laboratory tests using a full-scale gravel pack (GP) model. Tests were videotaped for further visual study. Established guidelines applying lab results, computer modeling, and field validation provide a well-engineered, non-damaging (low nozzle pressure) treatment for optimum stimulation performance. Proper damage identification coupled with skillful stimulation fluid design are important steps to a successful job and will be highlighted in the global R-Jet case histories.

The data clearly shows that a highly effective method of placing stimulation fluids into a completion, such as sand control screens or slotted liners, is to use CT-conveyed, rotary speed-controlled, forward-angled radial jets. This technique yields 360° coverage of the treatment area, is more efficient than traditional bullheading and CT methods and allows reduced treatment volumes to be considered. It applies to a wide selection of completions including horizontal wells which can now be successfully stimulated at reasonable costs.
Underbalanced Drilling of Fractured Carbonates in Northern Thailand Overcomes Conventional Drilling Problems Leading to a Major Gas Discovery
Authors: Pinkstone Henry , Timms Andy , McMillan Scott , Doll Rick , de Vries Hans
Published: December 2007

In the Phu Horm Field in Udon Thani Province, Northern Thailand, conventional overbalanced drilling of fractured carbonates had presented severe difficulties. The first 2 wells drilled in the field, Phu Horm 1 and 2, were sub-economic. Therefore, the Phu Horm 3 location was chosen to maximize the likelihood of encountering an extensive fracture network that would increase productivity and deliver economic flow rates.

Amerada Hess commenced drilling the Phu Horm 3 well conventionally using a water-based mud. The well was drilled into the top of the Pha Nok Khao Limestone reservoir, wherein severe fluid losses were encountered. The loss of hydrostatic head resulted in a gas kick with 1200 psi at surface. After pumping large quantities of loss circulation material in an attempt to block the fractures, the bottomhole assembly (BHA) became stuck. The drillstring was explosively severed, 71m of BHA were cemented in the hole, and operations were suspended.

This paper will discuss how a sidetrack was drilled on Phu Horm 3 using underbalanced drilling techniques in order to overcome the problems of lost circulation and safely maintain pressure control. The well was flow drilled underbalanced by injecting fresh water as the underbalanced fluid and producing gas, water, solids and condensate back to a four-phase separation package. The well was successfully completed barefoot and underbalanced. The paper will discuss the planning and execution of the underbalanced drilling operation, including some of the challenges, and learnings gained for future operations.

On Phu Horm 3 the primary objective of using underbalanced drilling technology was to enable the well to be drilled safely while maintaining pressure control and minimizing the potential of severe fluid loss. These problems had been experienced while drilling the over-pressured reservoir section of the original well. Other objectives were to reduce formation damage and evaluate productivity and reservoir characteristics during the drilling operation.

The Phu Horm 3 underbalanced project is categorized as a Level 5B5 well in the IADC UB classification system due to circulating wellhead pressures in excess of 3000 psi and gas flow rates of 50 MMscfd being seen during the course of operations. The well was drilled without any safety or environmental incidents, or loss or damage to equipment.

This underbalanced drilling project verified the applicability of underbalanced drilling in the Phu Horm field, as well as discovering major gas reserves.