bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Production Data for 2007/2008 Mallik Gas Hydrate Production Tests in Canada
Authors: Kurihara Masanori , Sato Akihiko , Funatsu Kunihiro , Ouchi Hisanao , Yamamoto Koji , Numasawa Masaaki , Ebinuma Takao , Narita Hideo , Masuda Yoshihiro , Dallimore Scott R. , Wright Fred , Ashford Douglas 
Published: July 2010

Abstract
The methane hydrate (MH) production tests were conducted using the depressurization method in the JOGMEC/NRCan/Aurora Mallik production program in April 2007 and in March 2008. In addition to attaining the first and the only successful methane gas production to the surface from a MH reservoir by depressurization in the world, various data such as wellhead/bottomhole pressure, temperature, gas and water flow rates and the temperature along the casing measured by Distributed Temperature Sensing (DTS) systems were acquired during these tests. The flow rates of gas and water from the reservoir sand face were then estimated by the comprehensive analysis of these data. This paper clarifies the details of the estimation of gas and water flow rates based on these data, for the first time after the 2008 winter test.
In 2007, a certain amount of gas and water were produced from a 12 m perforation interval in one of the major MH reservoirs at the Mallik site in Canada, by reducing the bottomhole pressure down to about 7 MPa. However, because of the irregular (on-off) pumping operations due probably to the excessive sand production, the produced gas was not directly delivered to the surface via the tubing, but was accumulated at the top of the casing. Hence, the gas production rate was calculated based on the continuously monitored bottomhole and casing head pressure. Since the produced water was injected into the aquifer located below the MH reservoir, it was impossible to directly measure the water pumping rate. The pumping rate and water production rates were accurately estimated by matching the bottomhole temperature through the numerical simulation using a wellbore model.
In 2008, much larger and longer gas production was accomplished with a stepwise reduction of the bottomhole pressure down to about 4.5 MPa, preventing sands from flowing into the wellbore by the screen. In this test, both the gas and water were delivered to the surface, which enables the estimation of the gas and water flow rates from the reservoir sand face as well as liquid level in casing based on the monitored parameters.
Investigating the production performances thus estimated, it was inferred what really happened in the reservoir during the tests. These insights must be beneficial for future exploration and development planning for MH resources.
Modeling Hydraulic Fracturing Induced Fracture Networks in Shale Gas Reservoirs as a Dual Porosity System
Authors: Du Changan M. , Zhang Xu , Zhan Lang , Gu Hongren , Hay Brad , Tushingham Keith , Ma Y. Zee 
Published: July 2010

Abstract
Shale gas production from organic rich shale formations is one of the most rapidly expanding areas in oil and gas exploration and production today. Because of extremely low permeability and low porosity, long horizontal wells in conjunction with multi-staged massive hydraulic fracturing treatments (HFT) are required to bring economic productions from shale gas reservoirs. It has been recognized that extensive fracture networks with massive contact surface areas are necessary to support economic productions from these reservoirs. Existing natural fractures observed from borehole images (mostly mineral-filled) and the low contrast of minimum and maximum horizontal stresses are some of the key factors in creation of the post-HFT network fracture system in many shale gas reservoirs.
Currently, comprehensive design tools for hydraulic fracturing treatments of shale gas reservoirs appear not available. These tools should have the capabilities to incorporate stress field, natural fractures and lithology heterogeneity of the reservoirs and model complicated fracture networks in shale gas reservoirs. However, microseismic mapping has been widely used to monitor hydraulic fracturing job responses, to help control job execution processes, and to evaluate stimulation results. Microseismic responses reflect the collective effects of the reservoir characteristics and hydraulic fracturing treatments, and can be indicative for the productivity of the post-HFT reservoirs.
This study presents a practical methodology to model hydraulic fracturing induced fracture networks in shale gas reservoirs as a dual porosity system. This approach decouples complex reservoir characteristics and geomechanical factors from production response. Microseismic responses are used to delineate stimulated volumes from a HFT. Microseismic events and/or natural fracture intensity, along with HFT data and production history-matching analysis, provide calibration for HFT fracture intensity. The calibrated post-HFT fracture network is crucial for production prediction.
Impact of Oil-Water Relative Permeability Curves on SAGD Behaviour
Authors: Lei Qiaohui , Wang Jacky , Gates Ian D. 
Published: July 2010

Abstract
Today, heavy oil and oil sands are starting to play a more important role. To manage and develop these resources, especially for thermal recovery processes, numerical modeling is often used to design the operating and well placement strategies. Relative permeability curves are one of the most important parameters for modelling these systems. This is especially important in systems where the saturation of each phase changes over a wide range as is the case in steam-based recovery processes such as Steam-Assisted Gravity Drainage (SAGD). Initially, before SAGD, the pore space of the oil sands reservoir is mainly occupied by bitumen with oil saturation typically between 80 and 90%. After steam is injected into the reservoir, the oil is heated and mobilized and drains under gravity and is replaced by first steam condensate and then, as the chamber propagates further into the reservoir, steam and solution gas. This means that the reservoir undergoes a series of large changes in phase saturations as the recovery process evolves in the reservoir. Thus, the interactions of the phases and their flow characteristics, that is, the relative permeability curves, are an essential component of the physics of SAGD. However, for modelling SAGD, due to limited relative permeability curve data, it is often adopted from analogs or previously history-matched curves. Given the heterogeneity of oil sands reservoirs, careless adoption of relative permeability curves will lead to serious risk of unexpected performance. The objective of this study is to investigate the impact of the endpoints of the oil-water relative permeability curves on SAGD performance by using numerical reservoir simulation. The results reveal that SAGD performance is sensitive to the values of the endpoints of the oil-water relative permeability curves. Given the range of variability of the results, it is recommended that relative permeability uncertainty analysis is always done during the simulation assessment of a targeted oil sands resource. Also, it is recommended that curves are obtained from multiple core samples of the target reservoir to reduce uncertainty and to assess the degree of heterogeneity of the endpoints.
Using Drilling and Logging Data for Developing 1D Mechanical Earth Model for a Mature Oil Field to Predict and Mitigate Wellbore Stability Challenges
Authors: Afsari M. , Amani M. , Razmgir S. M. , Karimi H. , Yousefi S. 
Published: July 2010

Abstract
Drilling through subjected mature offshore oil field is made more challenging by problems arising from wellbore instability, mud losses, excessive cutting, tight hole, stuck pipes and kick/flow zones for last few years. These problematic layers have caused quite a significant NPT (non productive time) during drilling.
For better understanding of factors causing wellbore instability problem and to predict mud weight window to be used for future wells, construction of mechanical earth model (MEM) was essential.
Mechanical Earth Model (MEM) is a numerical representation of the state of stress and rock mechanical properties for a specific stratigraphic section in a field or basin2.
In this study main drilling problems for each drilling interval in this field were described afterward different stages for construction an 1D Mechanical Earth Model (MEM) for the field was established. It was then demonstrated that how 1D MEM could be used to predict and prevent the common instability problems encountered during drilling.
For making MEM different sources of data including, drilling data, formation evaluation data, well testing, etc were used.
After making MEM for the field, safe and intact mud weight window was determined and according to that, suggestions for optimum mud weight for stable borehole on each interval was made.
MEM for this field can now be used to predict not only the safe mud weight window and possible drilling hazards, but can also be used for studies like reservoir compaction, sand production, and perforation stability and so on.
Ensuring Production in the Malaysian F6 Field Using Field Monitoring and Geomechanical Forecasting
Authors: Davison J. M. , Ita J. , Hofmann R. A. , Seli P. , Ong P. 
Published: July 2010

AbstractThe F6 field is one of many high porosity carbonate buildups developed in offshore Sarawak, Malaysia. With maximum porosities in excess of 30%, the reservoir experiences pore collapse during depletion. As a result, the predicted reservoir compaction and surface subsidence can be in the order of 25 ft or more. This poses a significant risk in terms of the platform subsiding into the wave-base, requiring shut in of production and prompting costly "jacking up" of the platform. To mitigate the risks it is recommended to build a field-wide 3D geomechanical model, constrained by available compaction and subsidence measurements, which are used to forecast future platform movement to end of field life.The F6 field finite element geomechanical model was constructed from the 3D static structural model and populated with the calculated in-situ stresses and pore pressure distribution in the field from the reservoir simulations. The rock properties assigned in the model were derived from both log data and numerous core tests, which also defined their deformation and failure behaviour.The F6 field has an on-going monitoring program, including compaction logging data in the reservoir, GPS data on the platform (both lateral and vertical movements), and sonar data for the platform height above sea level. Intermittent data gathered includes sonar seabed surveys of the subsidence bowl. This paper describes the data collected and how it is used to constrain the 3D finite-element geomechanical model constructed of the F6 field. The key findings of this study include; firstly, the importance of hard data in terms of reservoir compaction (compaction logging) and how this is translated through the overburden to surface subsidence (GPS measurements). Secondly, the importance of an accurate pre-production baseline for the monitoring program; it is relatively easy to match the rate of subsidence predicted from the model with the monitoring data collected after production start-up, however, the lack of pre-production data can lead to significant differences in the predicted absolute subsidence at end of field life.The results of this study show the importance and value of geomechanical modeling constrained by historical observations from a field monitoring program and the necessity to have it included as part of the field development plan prior to start of production. Use of this data with geomechanical forecasting is now a significant component of production assurance for the asset and has lead to plans to increase coverage and frequency of data gathering over these highly compactable fields.
Building a Precise Mechanical Earth Model and its Application in Drilling Operation Optimization: A Case Study of Asmari Formation in Mansuri Oil Field.
Authors: Perchikolaee Razi S. , Shadizadeh S. R. , Shahryar K. , Kazemzadeh E. 
Published: July 2010

Abstract
Asmari formation in Mansuri oil field is a complex geological environment. Variation in proportion of different lithologies (sandstone, limestone, and dolomite) in this formation poses serious challenges to drilling and production management, and makes it difficult to evaluate lithological and geomechanical characteristics of reservoir formation.
Wellbore instability and formation damage could substantially decrease drilling and production efficiency. Drilling of Asmari formation is almost always accompanied with mud loss causing damage to the reservoir formation. With developing a consistent mechanical earth model, an appropriate mud weight window is suggested based on formation strength and induced stress along the wellbore. Choosing an optimum mud weight would prevent fracturing the reservoir and losing mud into formation. Hence, drilling time and production rate of Asmari formation would improve considerably.
In this paper, laboratory testing on cores such as triaxial compressive test and ultrasonic test under confining pressure of reservoir provides experimental data to establish precise correlation between compressional and shear velocity and calibrate dynamic elastic properties resulting from sonic and density log. In addition, static elastic properties and mud logging data is used to assess induced stresses due to drilling of the formation. As a result, an accurate geomechanical model is constructed in minimum error since a complete set of data required to perform a proper evaluation is available. In addition, numerical modeling as well as analytical one is employed to analyze stresses and strains around the wellbore, especially in complex, heterogeneous areas.
Suggested mechanical earth model helps petroleum engineers evaluate geomechanical characteristics of reservoir formation in spite of its natural heterogeneity, make field development and well construction decisions accurately, and overcome the challenges of this complex area throughout the life of the field.
The Design of Casing Used in Salt Layer in Gulf of Laizhou-China
Authors: Li Zhonghui , Lou Yishan , Zhang Chunyang , Zhu Liang , Xing Xuesong 
Published: July 2010

Abstract
Drilling through salt layer is one of the great technological problems; many operational problems such as stuck pipes and casing collapse have been reported by the industry when drilling through those salt layers owing to the characteristic of salt layers. In Gulf of Laizhou-china, wells have been drilled through thick salt layer in the shahejie formation, the lack of reliable ways to predict salt behavior led to very high costs and even loss of wells.
In this paper we present a methodology for casing evaluation in the salt layers. Based on the experimental results of the multistage loading creep for salt layer, the creep constitutive model and creep parameters is given. Consider the geologic condition of the salt layer, Do the numerical calculation of the creep pressure around the casing by FLAC3D code. And evaluated the casing rationality used in the salt layer according to the time-histories curve of the creep pressure and the steel grade, wall thickness, strength of the casing. The results obtained by numerical simulations were used to select the rational casing used in the salt layer. The conclusion is that under the force of the heterogenetic Earth stress, the strength of the casing used in the salt layer in the shahejie formation should select steel grade is N80, diameter is 244.5mm, and wall thickness is 11.99mm. As a result, casing collapse was avoided and drilling costs reduced.
Static and Dynamic Testing of Silicate Scale Inhibitors
Authors: Arensdorf Joseph , Hoster David , McDougall Don , Yuan Mingdong 
Published: July 2010

Abstract
Alkaline surfactant polymer (ASP) floods in sandstone reservoirs are associated with silicate scaling of production wells. Silicate scaling has been a significant problem in ASP-flooded fields in China (e.g., Daqing field) and Canada. This paper describes the results of both static and dynamic testing that reproduced the field conditions in a typical oil production well in a field under ASP flood. The tests were used to screen chemical inhibitors for the prevention of magnesium silicate scaling. Carbonate and silicate were allowed to scale concurrently in both tests. The static test was used to screen inhibitors, and the best performers were tested dynamically. The static and dynamic tests correlated well in terms of individual inhibitor results. In the static test, silicate slowly forms from the beginning of the test and calcium carbonate forms about two hours into the test. In the dynamic test, calcium carbonate forms very slowly while silicate scale forms more quickly and dominates. It is interesting to note that none of the chemicals tested acted as a threshold inhibitor and prevented scaling at low doses. Rather, the inhibitors tended to delay scaling. Significant delay of scaling required doses of 50 to 100 ppm (as active). This effect was observed both in static tests and dynamic tests. Although none of the products tested acted as threshold inhibitors, the best inhibitors could still be effective in the oilfield if silicate scaling can be delayed long enough so that fluids are moved out of the well before significantly depositing on surfaces downhole.
Coalbed Methane Cementing Best Practices - Indian Case History
Authors: Mohammad Haidher Syed , Shaikh Shahnawaz 
Published: July 2010

Abstract
Cement is placed as a sheath across coal seams in coalbed methane wells primarily for hydraulic isolation and to support the casing. Designing a cement job for coal seam wells requires contemplating factors beyond those considered in cementing conventional oil & gas wells.
Cement invasion into coal seams, losses during jobs, annulus pack off and low fracture gradient are the challenges generally encountered during cementing these wells. The low formation temperature also exacerbates the challenges as the cement must set within drilling schedule time constraints. Predicting the bottom hole circulating temperature during cementation is also a challenge because many such wells are drilled with air. Finally, most coal wells will be fractured and proppant placed for production enhancement. Cement invasion or improper cement sheath will hinder fracture performance.
Based on a seven-year study, pumping lower-density slurries does not completely prevent cement invasion but does affect the cement quality behind the casing. Achieving successful cement jobs in these wells requires special designs and techniques. The requirements include not only extensive testing in the lab, but also special placement techniques and cement systems designed to accommodate a low fracture gradient and to avoid cement invasion into these soft seams.
This paper will share case histories and best practices developed from seven years of experience in designing and placing cement successfully in coalbed methane wells in India. These case histories will include cement design considerations, lab testing procedures, special placement techniques and cement system choices.
Transient Behavior of Horizontal Wells with Inflow Control Devices for Inflow Profile Modification
Authors: Poe B. D. , Erkal A. 
Published: July 2010

Abstract
This paper presents the results of a study of the transient performance of a horizontal well that has been completed using Inflow Control Devices (ICD's) to modify the inflow profile along the wellbore to minimize the risk of premature gas or water breakthrough into the well. A realistic pressure and rate-transient design and interpretation computational model was developed and utilized in this study. The mathematical model has been used to evaluate the transient performance of a horizontal wellbore in single and dual porosity reservoirs.
The horizontal well model utilized in this paper considers the wellbore to be finite-conductivity and assumes that the well has been completed using ICD's to control the inflow rates of fluids along the wellbore. The ICD's may be installed in selectively completed intervals of the wellbore of varying lengths and number, including variation in the number and sizes of nozzles and perforations in each of the completed intervals. A wellbore outflow production systems analysis was also included in the model in order to design or evaluate the performance of a horizontal well using various lengths, grades, and weights of production tubular goods, and for varying surface operating conditions.
A Case Study: Profiling Gas Production in the Tubing/Casing Annulus, Using Noise/Temperature Logging Techniques
Authors: Molenaar M. M. , Cowan B. M. , Fidan E. , Cuthill D. A. 
Published: July 2010

Abstract
To reduce liquid loading on multizone unconventional gas wells, tubing can be run to a depth below the lowest perforation interval. Gas flows down the tubing/casing annulus and flows up the tubing, eliminating liquid buildup. For production surveillance, this wellbore configuration is not conducive to obtaining conventional production logs.
Conventional production profiling techniques involve repositioning the tubing string or removing it altogether. If the tubing remains in place during logging, the costs associated with pulling the tubing are eliminated; production is not suspended; and the risks associated with well control are reduced. Also by not modifying the wellbore configuration, fluid velocities are not affected and the log results more closely represent the actual production profile. Ideally the well should be logged without manipulating the tubing to provide a representative production profile.
Noise/temperature logging has been used for many years to assist in locating sources of fluid flow behind casing. The use of this technique to obtain a pseudo or qualitative production-flow profile in the tubing/casing annulus was explored to enable the tubing to remain in the wellbore and obtain a measurement of the flow behind pipe.
In the 1970s, tests where conducted to quantify wellbore inflow using noise logs. The research was recently used to evaluate numerous wells in western Canada with favorable results. This paper discusses the logging method and presents comparisons to profiling results from conventional production-logging techniques with emphasis on the cost savings to the operator.
Effect of Fracture and Flow Orientation on Two-Phase Flow in an Oil-Wet Fracture: Relative Permeability Curves and Flow Structures
Authors: Shad Saeed , Maini Brij B. , Gates Ian D. 
Published: July 2010

Abstract
Naturally fractured reservoirs contain about 25-30% of the world supply of oil. In these reservoirs, fractures are the dominant flow path. Therefore, a good understanding of transfer parameters such as relative permeability as well as flow regimes occurring in a fracture plays an important role in developing and improving oil production from such complex systems. However, in contrast with gas-liquid flow in a single fracture, the flow of heavy oil and water has received less attention. In this research, a Hele-Shaw apparatus was built to study the flow of water in presence of heavy oil and display different flow patterns under different flow rates and analyze the effect of fracture orientations on relative permeability curves as well as flow regimes. The phase flow rates versus phase saturation results were converted to experimental relative permeability curves. The results of the experiments demonstrate that, depending on fracture and flow orientation, there could be a significant interference between the phases flowing through the fracture. In contrast with other studies, the results also reveal that both phases can flow in both continuous and discontinuous forms. The relative permeability curves show that the oil-water relative permeability not only depends on fluid saturations and flow patterns but also fracture orientation.