bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Mechanical Scale Clean-out Approach to Remove Iron Sulphide Scale from Tubulars in Vertical High Pressure and Temperature Deep Gas Producers: A Case History
Authors: Leal Jairo , Nunez Walter , Al-Ismail Saleh , Solares J. Ricardo , Ramanathan Venkateshwaran
Published: June 2009

As high pressure and temperature Khuff reservoir gas producers are in the Ghawar field in Saudi Arabia, scale deposition has become a problem which requires prompt removal to restore well productivity and regain wellbore accessibility to perform surveillance and well intervention work. The traditional approach in other areas of the field has been to remove scale deposits with chemicals, but this technique is only effective depending on the chemical composition of the scale.

A large number of Khuff reservoir gas wells are classified as sour producers due to the high hydrogen sulfide (4.5 mol %) and carbon dioxide (3-4 mol %) gas content. Moreover, different types of scale deposits have been found in wells around the field, including iron sulfide scale, which typically requires complex and lengthy operations to remove.

A novel mechanical approach involving the use of high pressure coiled tubing along with a "mechanical rotating jet nozzle blaster and engineered sterling beads with foam" at near-overbalance conditions was recently implemented to remove close to three tons of heavy iron sulphide deposits from the tubing string and liner in a gas producer.

The equipment used during the scale removal procedure included the combination of a rotational recessed head with a downward jetting configuration. One of the critical components of the operation was the use of good quality and stable foam to provide the best carrying capacity of particles with specific gravity ranging from 3.7 to 4.3. Due to a high reservoir temperature of 300 °F and pressure up to 7000 psi, achieving and maintaining foam stability was a real challenge. Therefore, extensive lab testing ahead of the job was conducted to identify foam capable of maintaining stability at the previously mentioned extreme downhole conditions for at least 8 hours. Slight over balance conditions were maintained throughout the solids removal operation to avoid any unexpected reduction in the foam's carrying capacity due to the presence of hydrocarbons in the wellbore.

This paper provides the detailed operational steps of the novel mechanical approach used, and discusses lessons learned and other technical considerations that resulted in the successful implementation of a complex and challenging operation.
Enhanced Economic Modeling by Correlated Stochastic Models of E&P Costs and Hydrocarbon Prices: The Limitations of Fixed Price Decks and the Versatility of Least-Squares Monte Carlo Simulation
Authors: Willigers B. J. A.
Published: June 2009

As decision-making processes in the E&P industry increasingly rely on probabilistic economic models, determining the accuracy of its methodologies becomes more problematic. Enhancements can be achieved by (1) better understanding the interdependencies between different sources of uncertainty and (2) the abandonment of fixed time series of either hydrocarbon prices or capital expenditures.

Historical market data of hydrocarbon prices, steel prices, and daily rig rental rates can be used to establish the correlation between different sources of market risk. Uncertainties can be defined as "fixed" or "dynamic." Fixed uncertainties relate to factors that do not change over time, such as many geological parameters during the early stages of exploration. Most uncertainties that relate to market risk are dynamic, that is, they keep developing over time. For example, not only is the realized price of oil uncertain until the moment the oil has been sold, but the expectation of future oil prices changes. The recognition of this Bayesian property of hydrocarbon prices significantly affects projects with multiple decision points. The forecasted hydrocarbon price at a future decision point is a function of the simulated realized price at that given decision point. Traditional decision tree models apply the same series of static price decks at each decision point and therefore do not accurately reflect the impact of the evolving market outlook during the development of a project.

The stochastic model developed in this study accounts for (1) the correlation between different uncertainties and (2) Bayesian price-cost forecasts. The versatility of the Least-Squares Monte Carlo simulation technique is demonstrated by a real option valuation of an asset subjected to a complex tax regime and two future stage-gate decision points.
A Statistical Approach to the Effective Economic Modeling and Portfolio Selection of Unconventional Resource Opportunities
Authors: Gouveia J. , Citron G. P.
Published: June 2009

Many firms are pursuing unconventional resource opportunities across the globe as a low risk vehicle for growth. Unfortunately, not all resource plays have met the expectations of this low risk model. Some opportunities are very product price dependent and others are both price and technology dependent. This paper provides an overview of the North American industry's use of statistically based production and EUR type curves to assess new opportunities and ongoing developments.

This paper highlights an alternative methodology for the selection of future unconventional resource opportunities based on their corporate definition of materiality and the use of analog production type curves. This methodology focuses on appropriate production type curves rather than reservoir models for tight gas sands and shale gas opportunities. Examples of production type curves will be presented to demonstrate the need to align these curves to the geological facies, the well type (vertical versus horizontal), and the completion technology (fracture stimulation size, fracture fluids, and the number of fracture stages).

The appropriate selection from the myriad of unconventional resource opportunities available is often a critical component to achieving corporate goals. Pick the wrong opportunity and even with superb execution, the returns are limited. Selecting the right unconventional resource opportunity enhances your probability to please shareholders. The methodology is similar, yet unique from traditional basin analysis in its use of Common Risk Segment (aka ‘traffic light') maps and production type curves versus a range of reserves in a prospect.
Effect of Brine Salinity on Reservoir Fluids Interfacial Tension
Authors: Alotaibi M. B. , Nasr-El-Din H. A.
Published: June 2009

Water flooding has been used for many decades as a way of recovering more oil. Historically, the salinity of the injection water has not been regarded as a key variable in determining the amount of oil recovered. Crude oil/water/rock chemical interactions can lead to large variations in the microscopic displacement efficiency of water flood. There is increasing evidence, as reported in the literature, that injecting low salinity brines has a significant impact on the amount of oil displaced, but the exact mechanism by which this occurs is an unsettled issue. The main objective of this paper is to determine the effects, advantages, and practicalities of using low salinity water flood to displace more oil in both carbonates and clastics formations. Another objective is to understand the main mechanisms in low salinity waterflood, and to determine the effects of salinity level on oil recovery.

In the present study, we measured the interfacial properties between oil n-dodecane and brines with various salt contents. The interfacial tension between oil and brines was measured using the Pendant Drop Apparatus. The effects of salinity, temperature, pressure and aging were examined in details.

The results obtained indicated that there is a critical salt concentration where the interfacial tension between brine and oil is low. We believe that this salt concentration will enhance oil recovery, and therefore, should be considered when designing water floods. Aging time has a significant effect on the interfacial properties and it depends on the temperature and pressure conditions. Interfacial tension decreased linearly with temperature.
Optimal Design Criteria for SAG Foam Processes in Heterogeneous Reservoirs
Authors: Kloet M. B. , Renkema W. J. , Rossen W. R.
Published: June 2009

Miscible gas injection can displace nearly all of the oil from the portions of the reservoir swept by gas. However, reservoir heterogeneity, low gas density and high gas mobility reduce sweep efficiency and drastically reduce recovery. Foam can reduce gas mobility and the effects of heterogeneity and gravity, and therefore increase sweep efficiency.

Here we extend a previous study (SPE 110408) on optimal design strategy for surfactant-alternating-gas (SAG) foam processes in layered reservoirs. We develop design criteria for the optimal foam strength and slug size for a given permeability contrast between layers.

We reach the following conclusions:

Trends of foam strength with permeability or surfactant formulation, as measured in conventional coreflood tests at fixed injected water fraction, may not correspond to behavior in a SAG process in the field. In the cases examined, foam strength in a SAG process is much less sensitive to permeability and foam parameters than is foam strength at fixed injected water fraction.

Placement of surfactant into low-permeability layers is a key challenge of SAG processes in heterogeneous reservoirs. Gas breakthrough occurs via low-permeability layers that did not receive enough surfactant. For that reason, unlike gas injection without foam, having a low-permeability layer at the top of the formation is a disadvantage because it is difficult to place foam there. Using multiple surfactant and gas slugs allows foam to redistribute surfactant in later slugs. However, this strategy suffers from poor injectivity during liquid injection, which slows the process and promotes gravity segregation.

Injection of both gas and surfactant slugs at the maximum allowed injection pressure, rather than at fixed rate, gives best results.

Injecting gas from only the bottom of the well offers no significant advantages in the best case, where high-permeability layers lie at top and bottom of the reservoir, and performs significantly worse if low-permeability layers lie at the top (where lack of surfactant leads to override) and bottom (where low permeability restricts injectivity) of the reservoir.

A surfactant slug sized for a homogeneous reservoir is too large for a heterogeneous reservoir, because little surfactant enters lower-permeability layers: much of the injected surfactant goes to waste. A surfactant slug sized to sweep high-permeability layers and a portion of low-permeability layers performs nearly as well as one sized to sweep the entire reservoir.
Incorporation of Static and Dynamic Constraints in Optimum Upscaling: A Field Case Study
Authors: Faskhoodi Majid Mohammadpour , Ates Harun , Soeriawinata Tono , Britsch Xavier , Vert Michel , Kelkar Mohan
Published: June 2009

To predict future reservoir performance and uncertainties associated, a series of reservoir simulation runs are required. It is now a common practice to generate multi million-cell geological model to capture the heterogeneity details in the reservoir. However, computational cost of such models is prohibitive for reservoir simulation studies and they need to be upscaled.

Upgridding is an upscaling design technique that provides optimal geologic layer grouping scheme for simulation model construction. In this study, we defined the optimum vertical layering scheme utilizing two different methodologies: analytical approach proposed by King et al1 and streamline simulation approach by Ates et al2. New upscaled layering scheme was further validated by running compositional simulations in different sectors of the reservoir.

We used the analytical method of King et al1, both in its original form and in a modified version. We refer to the original form as map-based approach and the modified form as average-based approach. Map-based approach can be characterized as a local dynamic method which uses each grid cell properties of 3D framework in the calculation. Average-based approach can be characterized as a global dynamic method which evaluates variations in average layer properties. The resultant optimum number of upscaled layers and layering scheme can be significantly different by these two approaches. Detailed comparison between these two approaches and their pro's and con's are presented in this paper using an actual field case study. Each approach was validated and QC'ed based on streamline simulation results.
Southern North Sea Tight-Gas Field Development Planning Using Hydraulic Fracturing
Authors: Vos Bart , Shaoul Josef R. , de Koning Johan
Published: June 2009

This paper presents an overview of the subsurface economic and technical issues involved in developing a Southern North Sea (SNS) tight-gas field using hydraulic fracturing. The paper investigates different kinds of wells (vertical vs. horizontal) and different completions; fracture spacing, fracture orientations (longitudinal vs. transverse).

The investigation was performed using a range of different reservoir qualities with appropriate completion and stimulation designs. Production and Net Present Value (NPV) estimates were developed for the different scenarios for qualitative and quantitative evaluation. The result is a generic strategy to evaluate a Field Development Plan (FDP) using hydraulically fractured horizontal wells.

The paper concludes with general guidelines on what type of recoveries are possible using different completion and stimulation solutions in situations with different kh distributions. The guidelines will help in initial screening of prospects to determine whether the tight gas reservoirs have significant potential for economic development. The latter is also a function of the actual development costs of pipelines and platforms, which is different for different companies and different locations. This paper also demonstrates why stimulation considerations should be put on the agenda early on in the construction of an FDP.
Organic Richness and Productivity Index Relationship in Dual Porosity Flow-System of Gas and Condensate Kerogen Reservoirs of Najmah Formation, North Kuwait
Authors: Acharya Mihir N. , Al-Awadi Mishari A. , Aziz Rafi M. , Al-Eidan Ahmad J.
Published: June 2009

The Najmah formation of Jurassic age has been tested and found to be a prolific source-rock as well as a producer of gas, condensate and light oil in different wells discovered from various fields of North Kuwait. The challenges of this unconventional reservoir are its dual porosity nature and its relation to the flow controlling system in view of very low porosity and the dependency on natural fracture network system as flowing mechanism.

The drill stem test (DST) results at some wells were quite successful without any stimulation, while at other wells the DSTs were unsuccessful in spite of advanced and repeated stimulations, thus categorizing the Najmah as a geologically-complex, naturally-fractured tight gas and condensate reservoir. Pressure transient analysis and flow regime interpretation of the successfully run Drill Stem Tested (DST) wells confirm the dual porosity flow-system and the fractured nature of the reservoir.

In this paper, the authors will point out the relationship between organic richness (Total Organic Content, TOC) of lower Najmah sub-unit and Productivity Index (PI). The term "matrix-dominated" is used to represent units with some dual-pore systems showing a typical profile with initial fracture flow and stabilized matrix support. The term "fracture-dominated" is used for units flowing through a fracture network but with limited matrix support.

The cross-plot shows that PI increases with higher values of TOC, up to 2.45% which is the upper limit of TOC window, within which Najmah has been successfully tested as dual pore-system, matrix-dominated Kerogen reservoir, while fracture-dominated dual pore-flow system lie as outliers. The authors strongly feel that this finding will tremendously change the current understanding of the prospectivity and predictive estimation of productivity of the Najmah formation in other fields in Kuwait as well as in other regions.
Downhole Gas Compression: World's First Installation of a New Artificial Lifting System for Gas Wells
Authors: Di Tullio M. T. , Fornasari S. , Ravaglia D. , Bernatt N. , Liley J. E. N.
Published: June 2009

Downhole Gas Compression (DGC) is an entirely new powered artificial lift technology designed specifically for natural gas wells and will serve an as yet unrealised opportunity within the Upstream Gas industry. The technology offers the opportunity to increase production by 30-50%, significantly improve reserves and delay the onset of liquid loading. Although it can be applied at any time during a gas asset's life cycle, it will find particular favour during the decline phase. It may also be used to extend the life of a field hence delaying divestiture.

While DGC has clear parallels with Electrical Submersible Pumps (ESPs), its deployment into gas wells presents new challenges due to the incompatibility of current well control methods and the technologies and operational considerations necessary for efficient wellbore turbo-compression. This paper presents these issues and reports on the candidate well selection criteria, the compressor requirements and the well completion design for the world's first DGC installation in a live gas well to be conducted by Eni in an operated mature gas asset located in Southern Italy. The paper offers guidance to other operators on the design, installation and operational considerations for the deployment of this all new Artificial Lifting System for gas wells.
Intermittent Alkali Flooding in Vertical Carbonate Reservoirs
Authors: Bortolotti V. , Gottardi G. , Macini P. , Srisuriyachai F.
Published: June 2009

Intermittent alkali flooding can significantly enhance oil recovery in oil-wet carbonate reservoirs. The method basically acts in two ways, by reducing the interfacial tension between the reservoir fluids and by reversing the wettability to a more favorable condition. However, the reversal of wettability requires aging time to reach the equilibrium. An intermittent or a pausing period is then adopted for the proposed alkali flooding process to let the surface reaching the maximum favorable wettability. As the injected fluid is paused during the flood process, vertical or inclined reservoirs are more suitable for this combination because the water tongue effect does not cause an early breakthrough. Laboratory results show that one-week-intermittent alkali flooding in homogeneous carbonate rock yields greater oil recovery, about 10 percent larger than conventional continuous alkali flooding in a proper range of injected alkali concentration. Low alkali concentration causes quick alkali depletion as time increases, while high alkali concentration causes pore plugging by in-situ precipitation of insoluble soap. The alkalinity of injected fluid should be kept as high as possible. Therefore, a strong alkali such as sodium hydroxide is recommended. High acid concentration in crude drives in-situ saponification frontward; hence, alkali concentration range should be carefully studied. Normally, high initial water saturation prevents the system from alkali accumulation and, as a consequence, insoluble soap precipitation is less concerned. Fractured carbonate reservoirs are probably the most suitable candidates for the application of this technique, since aging time would allow alkali to diffuse to, and reverse the wettability of the inaccessible and unswept zones. The proposed technique seems very effective to increase the ultimate oil recovery in oil-wet carbonate reservoir. The drawbacks seem acceptable and the expected results are promising.
Polymer Flooding in Unconsolidated Sand Formations: Fracturing and Geomechanical Considerations
Authors: Khodaverdian Mohamad , Sorop Tibi , Postif Sophie , van den Hoek Paul
Published: June 2009

A study was carried out to determine the geomechanical effects of polymer flooding in an unconsolidated sand reservoir. The work involved laboratory-scale polymer injections in unconsolidated sand blocks to identify the injectivity mechanisms, numerical analyses for fracture prediction, and geomechanical modeling of the formation to examine the potential of shear failure and containment loss during flooding.

Laboratory tests under polyaxial conditions indicate that near-wellbore fracturing and permeability increase in unconsolidated sands occurs at net injection pressures limited to 2.0 MPa. These findings were applied to fracture modeling. Geomechanical modeling suggests large-scale shear failure in the sand and in the bounding shale during polymer flooding. These are expected to affect both the fracture containment and the vertical-hole integrity. Finally, fracture predictions underscore the importance of the geomechanical considerations on determining the fracture dimensions and containment. Sensitivity analyses also point to the significance of bounding several key parameters for fracture prediction. These include sand-shale stress contrast, fluid quality and TSS content, fluid rheology and effective viscosity in the formation, and the filtercake properties in the presence of polymer.

This paper is intended to provide a geomechanical perspective on the generally complex problem of polymer flooding in unconsolidated formations containing viscous oil. The work also offers some insights into the critical issues that must be examined in such situations to avoid catastrophic failures, and highlights the existing technological gaps in the current predictive capabilities.
Well Test Dynamics in Rich Gas Condensate Reservoirs Under Gas Injection
Authors: Aluko O. A. , Gringarten A. C.
Published: June 2009

This paper investigates the well test behaviour of rich gas condensate reservoirs below the dew point pressure and the impact of re-vaporisation of the condensate bank due to re-pressurisation by gas injection. Results from compositional simulation, verified with field data, suggest that the near-wellbore fluid saturation below the dew point pressure in a build up is different from that at the end of the preceding drawdown, because of significant differences in fluid properties and saturation distributions. A condensate bank is created during drawdowns, which disappears during subsequent build ups. As a result, the corresponding pressure derivatives are different, with the drawdown derivative being the mirror image of the derivative in the subsequent build up. This is different to what happens in lean gas condensate reservoirs and similar to the well test behaviour of volatile oil reservoirs. Drawdowns and build ups in rich gas condensate reservoirs below the dew point pressure exhibit a composite behaviour, which can be analysed to provide the gas mobility in the bank two-phase region. A practical method is proposed to evaluate the bank storativity, which is then used to calculate the bank radius. The study also shows that the loss of productivity due to liquid drop out can be reversed by a properly designed gas injection scheme and that the corresponding changes in saturation distributions can be monitored by well test analysis.

These theoretical investigations are used to explain a series of production tests conducted in a rich gas condensate reservoir in North Africa. A well test analysis methodology is proposed for such systems, which combines conventional well test interpretation methods, deconvolution and verification with both a single phase voranoid grid simulator and a numerical compositional simulator.
Adjoint-Based Well Trajectory Optimization in a Thin Oil Rim
Authors: Vlemmix S. , Joosten G. J. P. , Brouwer D. R. , Jansen J. D.
Published: June 2009

The selection of optimal well locations and trajectories is a challenging and important step in a field development plan. Selecting the optimal trajectory of a deviated well is an arduous task, which is usually done manually. In this study we demonstrate the use of a new technique to assist the determination of the optimal well trajectory with the aid of a gradient-based search method. Our approach is based on surrounding the well trajectory with side tracks to all adjacent grid blocks. These side tracks have such a small perforation and thus production rate that they hardly influence the production through the main well bore. The gradients of the side track contributions to the net present value (NPV) of the well with respect to their positions are approximated using a reservoir simulator equipped with adjoint functionality. Using the approximate gradients of the side track contributions, coordinates for a new trajectory are selected, and with these a new well trajectory is constructed. The curvature of the trajectory is restricted to stay within predefined drillability constraints expressed in terms of dog-leg severity. The process is repeated until a location with a maximum NPV is reached. The reservoir model to demonstrate the optimization technique represents a 3-dimensional heterogeneous reservoir located in a tilted anticline cut off by a fault running through the top of the anticline. It contains a thin oil rim drained by a single deviated well with a given kick-off point and a trajectory that has to be optimized within drillability constraints. The optimization results show a significant improvement in NPV of the well. Depending on the value that is assigned to the reservoir fluids (gas, oil and water) in the cost function, the well will seek a path in the reservoir that leads either away from the gas cap (in case of gas disposal), or towards the gas cap (in case of gas sales).
Azimuthal Wave Resistivity Opens a Window on the Geology Away from the Wellbore Path
Authors: Chemali Roland , Bittar Michael , Calleja Bronwyn , Hawkins Donald , Manrique Carlos
Published: June 2009

Deep azimuthal wave resistivity sensors yield a new type of electrical images. Although traditional micro-electrical images are limited to the surface of the wellbore, the new deep resistivity images span a volume of several cubic feet around the borehole. This new window on the geology helps to geosteer with more confidence than a series of discrete non-azimuthal curves.

Deep azimuthal images feature frowning and smiling patterns similar to their micro-images counterparts, except for two important distinctions. First, they make it possible to recognize approaching boundaries long before they intersect the well path. Because they emanate from several feet away from the wellbore, deep electrical images effectively enable proactive geosteering. They guide proper and timely evasive actions before the well exits the reservoir into shale or an underlying water-bearing interval. Second, the deep propagation images feature a characteristic bright spot that appears when drilling through a reservoir and approaching an exit into a less resistive formation. Various spacings and frequencies generate images with differing depths of field that provide a sense of 3-dimensional view away from the wellbore. This important information is unavailable from micro-images limited to the wellbore surface.

New interpretation methods specific to deep electrical images are illustrated on modeled data and on real logs where the primary objective is often to steer near a boundary, while staying clear of it. To quantify the distance to nearby beds, deep images are supplemented by Geosignal, a new real-time electromagnetic log that is very sensitive to the distance to the nearest boundary. By integrating multiple deep images with multiple depths of field, electrical Geosignals, and quantitative azimuthal resistivity data, a real-time inversion software helps the geosteering engineer to locate the well precisely with respect to the geological layers.
Joint Structural and Petrophysical History Matching Leads to Global Geological Stochastic Reservoir Models
Authors: Schaaf Thomas , Coureaud Bertrand , Labaune François
Published: June 2009

History matching is an integral part of reservoir production forecasting, risk analysis and uncertainties quantification workflows. One has to cope with the non-uniqueness issue as history matching is an ill-posed inverse problem, due to a lack in constraints and data. Dealing with several history matched models is therefore critical and assisted history matching tools are of great interest to speed up the process.

In practise, structural as well as petrophysical, PVT, SCAL, etc. data may be highly uncertain and the history matching process rarely tackles all these parameters in a single step. Classically, some of these parameters are considered as known while others are updated. This constitutes the ‘by default’ approach as all these parameters are interdependent and it may lead to sub-optimal history matched models.

This manuscript presents an original history matching workflow that picks uncertain structural and petrophysical parameters anywhere in the "geomodeling to simulation?? workflow, using a popular geomodeling software. Efficient parameterization technique of the geological model allows both geological and simulation models to be updated at the same time, preserving the consistency between each other. Using a versatile assisted history matching software, any external software such as a geomodeling software, may be automatically launched in batch mode from the constructed workflow. Background scripts then control each building step of the geological and simulation models, possibly capitalizing on an existing geomodel. This joint structural and petrophysical history matching leads to a more robust integrated geological stochastic reservoir model, as all uncertainties are simultaneously tackled and reduced.

The results obtained on a 3D faulted synthetic waterflooding scenario demonstrate that this history matching approach is efficient since horizon depths, throw and transmissivity of faults as well as facies distribution, petrophysical and SCAL properties are simultaneously updated to explain the production history.
Understanding Compositional Grading in Petroleum Reservoirs Thanks to Molecular Simulations
Authors: Galliero G. , Montel F.
Published: June 2009

An accurate knowledge of the initial state of a petroleum reservoir is crucial in order to optimize its development plan. Such knowledge relies on a correct description of the spatial distribution of the fluid components. The compositional variations are mainly due to gravitational segregation and thermo-diffusion phenomena. Usually, a good estimation of the steady state spatial distribution of the components is obtained by thermodynamic modeling based on an Equation of State (EoS). This heuristic approach is unable to yield any knowledge on the time required to establish a segregated profile and it needs correlation for the thermodiffusion coefficients which is not readily available. One way to provide further information, both on the dynamic of the segregation and on the thermodiffusion process is to use Molecular Dynamics (MD) simulations. In this paper, Both EoS and MD simulations were applied for the calculation of the fluid distribution in reservoirs.

MD results provide insights on time evolution/stability of the fluid distribution and the calculated profile were used to tune the parameters of the EoS model for current applications.

On systems, for which an analytical solution of the thermo-gravitational problem exists, it is shown that the molecular simulations results are consistent with expected profiles. The MD simulations confirmed a non negligible impact of thermodiffusion phenomenae on the concentration profiles. In addition, simulations have shown that the transient behavior of both isothermal and non-isothermal segregation follows a diffusion process dynamic based on the mutual diffusion coefficient.

Comparison of MD results and EOS based model were made for various systems to evidence the limitation and the relevance of the thermodynamic approach. Gravity segregation calculations are widely used for the reservoir fluid evaluation and for the initialization of the reservoir model. This paper gives an in depth investigation of the underlying physics and direct validation of EoS modeling through molecular simulations.
Validating Workflows with Pore-Scale Modelling and Fine-Scale Geology for Water Saturation Interpretation
Authors: Berland Håvard , Børset Kari , Nordahl Kjetil , Rennan Lars , Rustad Alf B.
Published: June 2009

Future workflows for water saturation interpretation in heterogeneous intervals, should take the heterogeneity into account in a robust manner. We want fine-scale geology to be modelled realistically, down towards mm-scale when appropriate, and populate these models with properties from pore-scale modelling. The geologically realistic models can then be upscaled for effective properties for different rocktypes. Accordingly, Archie's law can be used for water saturation interpretation without breaking its assumptions. The work presented is a study in which we want to validate such a workflow, and assess the predictivity to be expected. Two core plugs from a heterogeneous reservoir have been studied in a steady-state flow experiment while simultaneously measuring both resistivity and in-situ saturation in 3D by CT-imaging. Resistivity was measured in a 4-electrode set-up connected to a multi frequency impedance meter. The experimental design yielded data where now resistivity, relative permeability and fine-scale saturation are all coupled. 3D digital models of the plugs have subsequentially been constructed from CT porosity and populated with properties from pore-space modelling. This enables us to compare the fine scale saturation modelling, which is a difficult task for this type of sedimentary rocks, to the measured water distribution in the plug. Fine-scale saturation also determines upscaled resistivity, which we can model digitally using pore-space models and compare with the measurements. Our findings indicate that the workflow is viable, and that we are able to obtain predictive power from pore-scale modelling and fine-scale geological modelling.
Integration of Production, Pressure Transient and Borehole Images in Horizontal Wells Drilled in Cambrian Sandstone Reservoirs of Hassi Messaoud Field, Algeria
Authors: Ogunyemi Taofeek , Montaggioni Philippe , Azzouguen Atmane , Kourta Mourad , Kodja Said , Madani Messaoud
Published: June 2009

The economical viability of the Cambrian sandstone reservoirs in the Hassi Messaoud field is closely linked to the presence of fractures. Natural or hydraulically induced fractures control hydrocarbon productivity due to the low porosity, low matrix permeability and heterogeneous sedimentological characteristics of these fluvial deposits.

Fracture corridors and permeable fault zones also represent a major risk of water breakthrough from the underlying aquifer in horizontal wells. The identification and characterization of open fractures and conductive faults is of critical importance for the completion decisions in this field.

Whole cores enable a comprehensive description of fractures (morphology and type) over the cored sections of the reservoir. Meso-scale fractures can also be identified, oriented and characterized (open vs. cemented) on high resolution borehole images over the entire open-hole section. When combined with pressure transient analyses and production data, borehole image logs provide invaluable information on the enhanced fracture conductivity, the completion optimization and the reservoir management for sustaining long term production in these complex reservoirs.

Wells with high fracture density usually correlate with high production rates as long as the dominant fracture strike is close to the direction of the maximum in-situ horizontal stress (σH). Wells with low fracture density or dominant fracture strike oriented oblique or perpendicular to sH generally show poor production rates.

This paper discusses case studies of fracture and fault characterization from a combination of borehole images with production and pressure transient data to provide an explanation for ambiguous production observations and well test data. Examples of completion optimization utilizing this integrated approach are also presented.
Feasibility of Using Wind Energy and CAES Systems in a Variety of Geologic Systems
Authors: Neumiller Jessica , Graves Ramona , Fanchi John
Published: June 2009

Renewable energy sources, such as wind energy, are expected to be sources of sustainable energy as fossil fuels are depleted. Wind energy is a promising, but intermittent energy source. Large scale energy storage such as Compressed Air Energy Storage (CAES) is needed to account for intermittency. CAES is designed to store off-peak energy to make it available for use during peak demand periods. Currently, CAES plants are located in caverns, which are uncommon in occurrence. CAES wind farms can become a more reliable energy source if other geological structures such as depleted hydrocarbon reservoirs are used for storage.

This study used a black oil simulator to model CAES in a typical cavern setting, in a hypothetical reservoir setting, and in a potential CAES wind farm area in the Greater Green River Basin (GGRB) of Wyoming. The cavern setting is modeled after the Huntorf CAES facility in Germany. Wind speed and resulting power data for GGRB models were taken from the Medicine Bow Wind Project in Wyoming. Porosity, permeability, and injectivity information from GGRB was used to construct four models of hybrid systems that combined wind energy and CAES for different geographical locations and geological properties.

The model of a cavern setting validated use of a black oil simulator for CAES applications. The study showed that CAES can be used in a variety of geologic settings, and that the GGRB has good potential for supporting wind energy and CAES systems. This talk will present details of the study and provide suggestions for future work.
Sedimentary Facies Computation and Stratigraphic Analyses Using Well Logs, Borehole Images and Cores in Triassic Fluvial Sandstones of the Algerian Sahara
Authors: Ogunyemi Taofeek , Montaggioni Philippe , Boubakeur Ibtissem , Junguito Mario , Batrina Maria Teresa
Published: June 2009

The Triassic reservoirs of the eastern Sahara province represent one of the main oil and gas accumulations in Algeria. This clastic succession corresponds to fluvial, estuarine and shallow marine deposits characterized by common lateral and vertical facies changes that are responsible for uncertainties in the modeling of the reservoir heterogeneities.

A realistic identification of the depositional environment is critical to the delineation and prediction of the best quality reservoir facies so that optimized exploitation of the reservoir can be achieved. This paper describes a methodology that was used to generate a depositional model in the Lower to Upper Triassic reservoirs of the Rhourde El-Khrouf field based on subsurface data from six wells including well logs, borehole images, cores and the regional knowledge of the basin.

Structural and sedimentary dip analyses were performed both on borehole images and oriented full-bore core photos that provided at least twice as many dips than borehole images. Facies logs were derived from the integration of core calibrated electrical borehole image analysis results with open-hole log data using neural network techniques. Depositional environments were then determined from correlations based on logs stacking patterns, facies associations and dip data.

These results show that the fluvial reservoirs of the Rhourde El-Krouf field are characterized by large variations from laterally extensive bodies with good interconnectedness and high net-to-gross ratios, to multi-storey ribbon bodies with poor interconnectedness and low net-to-gross ratios. This integrated approach using high resolution image logs and full-bore core photos provided a much more robust reservoir model than would be obtained from traditional approach based solely on open-hole logs.
Different Approaches to Understand Mechanism Of Wettability Alteration of Carbonate Reservoirs
Authors: Rezaei Gomari K. A.
Published: June 2009

Wettability is a key parameter when concerned with the flow of fluids in any porous medium. This paper describes the several possible mechanisms of wettability alteration of carbonate rocks using different approaches. The most crucial parameters which have severe impact on wettability alteration such as oleic phase composition, aqueous phase pH, as well as temperature are discussed.

At the oleic/aqueous interface, the interfacial tension and its variation with the structure of active surface species, partitioning of species between phases, and temperature are important signs to track the wettability alteration. The effect of the IFT on wettability alteration is revealed with the contact angle measurements on the carbonate rock surfaces.

On the other hand at rock/fluids interface, the paper presents the variations in surface tension and adsorption isotherms of surface active species on the rock surfaces which imply the strength of wettability alteration. The degree of wettability alteration and its reversibility due to influence of aforementioned parameters are explained based on desorption of active species from surfaces justifying by several thermo-gravimetric measurements.
Hybrid Optimization Coupling EnKF and Evolutionary Algorithms for History Matching: A Case Example
Authors: Schulze-Riegert Ralf , Krosche Markus , Pajonk Oliver
Published: June 2009

This paper discusses a hybrid extension of the Ensemble Kalman Filter (EnKF) with application to History Matching. The new approach combines the Ensemble Kalman Filter (EnKF) and Evolutionary Algorithms (EA). Key characteristics of either approach are used for data assimilation and optimization.

In a previous publication similarities between particle filter techniques (EnKF) and stochastic optimizers (i.e., Evolutionary Algorithm – EA) were analyzed. Both algorithms are population based, they have similar implementation properties but different optimization characteristics. A hybrid optimizer which couples an EnKF approach and the advantages of an Evolutionary Algorithm was introduced and applied to a synthetic test function.

In this paper the hybrid optimization approach is first applied to a history matching process of a synthetic reservoir simulation model. Production data is assimilated via a continuous update of 3D porosity and permeability fields. At the same time, additional parameter uncertainties are included in a parallel parameter estimation process guided by an evolutionary optimization method.

It is shown how an EnKF workflow can be coupled to other stochastic optimization schemes with complimentary optimization features. The EnKF formulation reduces a non-linear optimization problem in a large parameter space to a statistical optimization problem in ensemble space. An evolutionary optimization scheme modifies individual parameters and adds a focus on optimal solutions. The hybrid approach is applied to a history matching problem in reservoir simulation. The application case shows that an EnKF ensemble can be combined with a population of individual realizations from a generational update scheme using an Evolutionary Algorithm.
Roadmap to Monetization of Unconventional Resources
Authors: Vassilellis George D.
Published: June 2009

What has been regarded as unconventional by many has been conventional for the few that have developed viable, and in many cases, very profitable projects that succeeded in extending the envelope of recoverable hydrocarbons.

The range of recoverable hydrocarbons is bounded by physical constraints like reservoir properties, unfavorable hydrocarbon characteristics, or in many cases, hydrocarbons still captured in the formations. The methods of extraction that have been devised to address such challenges frequently combine applications of enhanced recovery, intensive stimulation, or advanced drilling. The distinction between conventional and unconventional can be reasoned not in the context of new versus old, more or less prolific accumulation attributes, or the method of extraction, but in the approach that is followed. A conventional development approach would cover the entire field with increasing intensity; an unconventional approach would pursue intensive development sequentially from the more prolific to the less prolific parts of the field.

Although it is easy to see the technical benefits of unconventional methods, their integration with economic and market parameters is necessary in order to provide a successful implementation. The purpose of this paper is to present a set of features that are found as common denominators in successful developments of such resources. These common features could be viewed as unconventional resource development principals that outline the areas where particular attention is required for their ultimate success. In that context, the influence of market pricing, cost structure and resource evaluation are examined and offer a platform for project implementation that can be viewed as a "road map". The basic premise in this reasoning is that while it is not possible to develop a universal technological solution, careful adaptation of technology to the subsurface and operational realities allow synergies to develop that improve the chance of economic success. The recognition of key risks in unconventional resource development is instrumental in addressing the reasoning in resource classification. In that sense, while geological risks are often viewed as key in conventional resources, unconventional resources carry more risks as more complex extraction methods are implemented. Once development commences, it could maintain a positive outlook with changing market conditions as the associated costs relate to some extent to fuel costs that are in turn dependent on the product prices. The long development cycle of such projects lasting more than 20 years reduces the exposure to fluctuating prices as long as a reasonable average trend is considered at the onset.

With evolving methods of extraction, the oil industry is shifting focus from exploration into intensive exploitation. Inevitably, the terms unconventional resources and a non conventional approach present a new direction for realizing the fuel sources of the future.