bluuebunny/crossref_metadata_2025_split 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

AbstractMiscible 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.