bluuebunny/crossref_metadata_2025_split huggingface dataset:
Data-Driven Reservoir Management of a Giant Mature Oilfield in the Middle East
Authors: Mohaghegh S. D. , Gaskari R. , Maysami M. , Khazaeni Y. 
Published: October 2014

Abstract
A novel approach to reservoir management applied to a mature giant oilfield in the Middle East is presented. This is a prolific brown field producing from multiple horizons with production data going back to mid-1970s. Periphery water injection in this filed started in mid-1980s. The field includes more than 400 producers and injectors. The production wells are deviated (slanted) or horizontal and have been completed in multiple formations.
An empirical, full field reservoir management technology, based on a data-driven reservoir model was used for this study. The model was conditioned to all available types of field data (measurements) such as production and injection history, well configurations, well-head pressure, completion details, well logs, core analysis, time-lapse saturation logs, and well tests. The well tests were used to estimates the static reservoir pressure as a function of space and time. Time-lapse saturation (Pulse-Neutron) logs were available for a large number of wells indicating the state of water saturation in multiple locations in the reservoir at different times.
The data-driven, full field model was trained and history matched using machine learning technology based on data from all wells between 1975 and 2001. The history matched model was deployed in predictive mode to generate (forecast) production from 2002 to 2010 and the results was compared with historical production (Blind History Match). Finally future production from the field (2011 to 2014) was forecasted. The main challenge in this study was to simultaneously history match static reservoir pressure, water saturation and production rates (constraining well-head pressure) for all the wells in the field.
History matches on a well-by-well basis and for the entire asset is presented. The quality of the matches clearly demonstrates the value that can be added to any given asset using pattern recognition technologies to build empirical reservoir management tools. This model was used to identify infill locations and water injection schedule in this field.
A Statistical Evaluation of Cement Placement Techniques by use of Cement Bond Index
Authors: Pallapothu Surya , Bogaerts Martijn , DeBruijn Gunnar , Peyle Sebastien , Rashid Faisal 
Published: October 2014

Abstract
Cement placement plays an important role in the primary cementing process. There are several best practices in place which are believed to have significant impact on the quality of the overall cement job. Previous investigations suggest that a combination of multiple placement techniques, such as density and rheology gradient coupled with proper displacement rates, pipe rotation or reciprocation, conditioning of drilling fluid prior to cement job, pipe centralization, and bottom plugs, improves the chances of a successful cement job. However, there is little quantitative analysis available to demonstrate the importance of each technique independently in the field.
In the past 15 years, operations in offshore Atlantic Canada have cemented 140-mm and 178-mm liners in 216-mm openhole sections in two different reservoirs. The cementing designs for the liners are similar, especially in terms of flow rate, centralization (type or placement), and spacer train, but differ in pipe rotation, mud conditioning, and bottom plugs. Once the cementation process is executed, it is evaluated by an ultrasonic imaging tool, which measures the acoustic impedance to calculate the cement bond index. The average of the cement bond index for the entire liner is then used to quantify the quality of the cement job for each well.
The average cement bond index obtained from 53 wells was used to evaluate various cement placement techniques. The average cement bond index is proportional to the amount of cement bonded to the pipe and is inferred to be proportional to factors related to mud removal and cement placement. Factors that affect mud removal, such as mud conditioning, annular velocity, pipe movement, wellbore characteristics, and the presence of a bottom plug, are investigated. Statistical analysis of the cement bond index indicates that some of these cement placement techniques affect mud removal significantly more than others. A comprehensive analysis of these results and an assessment of potential benefits are presented in this study. The results of the study were used to improve the cement job design.
Vapor-Liquid and Liquid-Liquid Interfacial Tension of Water and Hydrocarbon Systems at Representative Reservoir Conditions: Experimental and Modelling Results
Authors: Pereira Luis M. , Chapoy Antonin , Tohidi Bahman 
Published: October 2014

Abstract
In this paper, interfacial tension (IFT) of two ternary water-rich hydrocarbon systems were investigated at a representative reservoir temperature of 150 °C and equilibrium pressures up to 140 MPa. Two-phase and three-phase IFT measurements of water-methane-hexadecane and water-methane-toluene mixtures were carried out in our previously validated Pendant Drop facility and the equilibrium phase densities, required to determine pertinent IFT values, were determined by measuring the volume and mass of samples separately. The results showed a high pressure dependency of IFT values below the hydrocarbon dew point (i.e., three-phase region) whereas a slight increase on the interfacial tension was observed in the two-phase region.
Aiming at developing a general model for describing this property in multiphase systems, the generated and literature IFT data were used to develop and validate our model based on the Linear Gradient Theory (LGT). The LGT has been proven capable of describing vapor-liquid and liquid-liquid interfaces in systems containing polar and non-polar compounds when coupled with an appropriate thermodynamic model. In this work the LGT was coupled with the Cubic-Plus-Association equation of state (CPA EoS) for a correct description of the equilibrium properties of the phases involved. The modelling results confirmed the superiority of the LGT over classical models in that one single model can be used for describing the IFT of multiphase systems with greater accuracy.
Securely Managing Video-Rich Data in Control Rooms and Real-Time Operating Centers with Fiber Optic Systems
Authors: Fanguy Darrel , Wachter Larry 
Published: October 2014

Abstract
The oil and gas industry faces a multitude of complex business challenges. Asset Integrity Management (AIM) is an overarching approach designed to address the challenges by getting people, processes and technology working together to improve productivity, safety and security, while also protecting the environment.
The AIM objectives of improved asset productivity, process safety and protecting the environment are closely intertwined and often at odds. For instance, in drilling operations, new technologies are continuously improving the speed of drilling. But that speed can add to wellbore instability and increase the chance of a serious process safety and environmentally dangerous event. Ironically, such an event might eliminate all efficiencies gained from the new technology and more. 1 The underlying signal extension and switching systems required for distributing and improving staff collaboration, enhancing the quality of decision-making, maintaining safety, and meeting the core objectives of AIM.
In support of AIM, the nature of what was previously known as a "Control Room" has changed dramatically. In today's digital oilfield, the traditional control room has evolved to a multi-faceted facility more commonly known as a "Real-Time Operating Centre" or RTOC. A RTOC is exponentially more data rich, evolving to include high-resolution video and audio surveillance.
This paper explores key issues in the design of secure, high performance KVM (keyboard, video and mouse) signal extension and switching systems for the distribution and management of video rich data in control rooms and real-time operating centres. It describes system alternatives from several perspectives, including: the diversity and distance of sources and destinations of information, performance requirements, physical security of the system and the information, management of user access, system reliability and redundancy, flexibility and scalability, and ultimately control room and real time operating centre productivity.
Using Distributed Acoustic Sensors to Optimize Production in Intelligent Wells
Authors: Bukhamsin Ahmed , Horne Roland 
Published: October 2014

Abstract
As many fields around the world are reaching maturity, several drilling and completion technologies have been developed to boost production from these fields. Smart completions and distributed measurements are two of the most important tools in this category. This study examined a new smart completion tool, Distributed Acoustic Sensor (DAS) in terms of its utility for inflow monitoring and optimization in smart wells.
We began by evaluating the performance of DAS as a tool for measuring downhole multiphase flowrate. A description of the methodology to calculate individual phase flowrates from acoustic signals, caused by pressure fluctuations in the flow, is presented. As DAS provides continuous flow of data from the wellbore, another opportunity emerges to optimize the flow from these smart wells. A methodology to use calculated downhole flowrates to update existing simulation models and perform, near real-time optimization is suggested for wells installed with DAS. As opposed to conventional optimization methods that rely only on reservoir simulation models, this procedure also makes use of real-time flow measurements. The methodology was tested on a synthetic model with encouraging results, where the optimum solutions obtained were in close agreement to the true optimum.
The flow profiling procedure was applied to several actual wells. The first well was a single-phase oil producer. This process yielded speed of sound results that matched the fluid properties obtained in the lab. Flowrates from different segments of the well were calculated and results were in close agreement with a surface flowmeter for most sections of the well. More examples were conducted in two-phase flow wells with results being more qualitative and less conclusive. When the optimization procedure was applied for synthetic cases that have wells with similar completions to the tested ones, results showed that significant value could be realized by incorporating real-time measurements in the optimization process.
Several advantages could be realized with the application of these methods. First, continuous downhole flow monitoring provides asset managers with more accurate allocation of their wells. Second, more accurate modeling for wellbore flow is possible by using in-situ phase flows to calibrate existing models. With more accurate models, evaluating different flow scenarios is possible before applying them on the field. Finally, quick decisions to change the controls of the well are easier with the described optimization method. By comparison, full reservoir simulation model optimization takes a very long time to make their use practical in everyday applications.
Effect of Confinement on PVT Properties of Hydrocarbons in Shale Reservoirs
Authors: Pitakbunkate T. , Balbuena P. B. , Moridis G. J. , Blasingame T. A. 
Published: October 2014

Abstract
Shale reservoirs play an important role as a future energy resource of the United States. Numerous studies have been performed to describe the storage and transport of hydrocarbons through ultra-small pores in the shale reservoirs. Most of these studies were developed by modifying techniques used for conventional reservoirs. The common pore size distribution of the shale reservoirs is approximately 1-20 nm and in such confined spaces the interactions between the wall of the container (i.e., the shale and kerogen) and the contained fluids (i.e., the hydrocarbon fluids and water) may exert significant influence on the localized phase behavior. We believe this is due to the fact that the orientation and distribution of fluid molecules in the confined space are different from those of the bulk fluid; causing changes in the localized thermodynamic properties.
This study provides a detailed account of the changes of PVT properties and phase behavior (specifically, the phase diagrams) in a synthetic shale reservoir for pure hydrocarbons (methane and ethane) and a simple methane-ethane (binary) mixture. Grand Canonical Monte Carlo (GCMC) simulations are performed to study the effect of confinement on the fluid properties. A graphite slab made of two layers is used to represent kerogen in the shale reservoirs. The separation between the two layers, representing a kerogen pore, is varied from 1 nm to 10 nm to observe the changes of the hydrocarbon fluid properties. In this paper, the critical properties of methane and ethane as well as the methane-ethane mixture phase diagrams in different pore sizes are derived from the GCMC simulations. In addition, the GCMC simulations are used to investigate the deviations of the fluid densities in the confined space from those of the bulk fluids at reservoirs conditions. While not investigated in this work, such deviations may indicate that significant errors for production forecasting and reserve estimation in shale reservoirs may occur if the (typical) bulk densities are used in reservoir engineering calculations.
Upstream Offshore Facility Weight Growth Study
Authors: Rui Ray (Zhenhua) , Walker Jason 
Published: October 2014

Abstract
Offshore facility weight is significantly related to the cost, schedule, and complexity of offshore facility projects. Therefore, controlling offshore facilities weight growth is important to project success. This paper sought to understand weight growth among different project phases and its causes. Using Independent Project Analysis, Inc.'s (IPA's) detailed database of oil and gas projects, we conducted a rigorous statistical analysis of offshore weight growth to identify the root cause(s). This paper evaluates the offshore facilities weight growth for 153 global offshore projects at the end of the concept selection and authorization gates. The study results show that industry weight growth is much higher than expected. Although Industry typically allocates 13 percent of dry weight for weight contingency at the end of Front-End Loading (FEL) 2 and 6 percent of dry weight at authorization to account for unexpected weight growth, half of the topsides had more than 10 percent weight growth, and more than one in three substructures had more than 10 percent weight growth from authorization to completion. There is a large gap between the estimated weight contingency and the actual amount spent for these projects. This analysis shows that most offshore facilities weight growth is caused by poor engineering status for the facilities at authorization. The analysis also shows that setting aggressive schedule targets erodes the benefits of good engineering definition. In general, projects with good engineering and aggressive schedule targets have an extra 9 percent weight growth compared to projects with good engineering and non-aggressive schedule targets. Offshore facilities weight growth was found across many different offshore facility concepts (e.g., fixed platforms, spars, tension-leg platforms, etc.). This research provides an understanding of industry offshore facilities weight performance and the main causes of weight growth, and offers recommendations for improving weight predictability.
Simulation of Asphaltene Precipitation during Gas Injection Using PC-SAFT EOS
Authors: Mohebbinia Saeedeh , Sepehrnoori Kamy , Korrani Aboulghasem Kazemi , Johns Russell T. 
Published: October 2014

Abstract
Oilfield problems owing to asphaltene precipitation are well known. Asphaltenes can block pore throats or change the formation wettability and thereby reduce the hydrocarbon mobility. Simulation of asphaltene precipitation during gas injection requires a comprehensive thermodynamic model, which accounts for the complex phase behavior of asphaltenes. In this paper, PC-SAFT EOS is implemented for the first time in a compositional reservoir simulator to model asphaltene precipitation. The additional computational time of PC-SAFT compared to the cubic equations-of-state such as Pen-Robinson (PR EOS) is decreased by improving its root finding algorithm. A deposition and wettability alteration model is then integrated with the thermodynamic model to simulate the dynamics of precipitated asphaltenes. Different gas injection scenarios are modeled to show the effect of gas injection on apshaltene precipitation and deposition.
Simulation results show that the profile of the damaged area by asphaltene deposition is governed by the shape of the asphaltene precipitation envelope for the reservoir fluid. The damage caused by asphaltene deposition, through plugging and wettability alteration, was revealed as a decline in productivity index curves. Results indicate that a reservoir fluid can have precipitation risk during gas injection even if it does not exhibit precipitation in the primary recovery life of a field. The computational time of the simulations using PC-SAFT EOS were compared to those using PR EOS for different number of components. Results of these comparisons show the feasibility of using PC-SAFT in compositional simulations.
Continuous High-Frequency Measurements of the Drilling Process Provide New Insights into Drilling System Response and Transitions between Vibration Modes
Authors: Bowler Adam , Logesparan Lojini , Sugiura Junichi , Jeffryes Ben , Harmer Richard , Ignova Maja 
Published: October 2014

Abstract
The oil and gas industry has become increasingly interested in drilling dynamics and vibration as causes of drilling inefficiency and reduced drilling performance. Generally, drillstring vibration is measured with shock-and-vibration sensors installed in measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, and rotary steerable systems (RSS). Although these tools provide valuable real-time and recorded-mode information on the dynamic conditions, they are not generally designed to capture continuous high-frequency mechanics and dynamics data, and burst data may miss important information about the evolution of the system response and state.
A downhole mechanics measurement tool has been developed that makes a comprehensive suite of measurements of the drilling process, including forces, accelerations, rotational speed, pressures, and temperatures. In addition to providing information in real-time, the tool has the capability to capture long durations of continuous data at frequencies between 50 and 2,000 Hz. The recorded-mode information obtained has provided significant insight into the response of the drilling system to initiating rotation; drilling procedures and parameter modifications; and exposure to excitation from sources including, but not limited to, rig heave, bottomhole assembly (BHA) component imbalance, and bit-rock interaction. A wide range of occurrences has been captured in which the drilling system switches from a dominant vibration mode, typically torsional (downhole rotation-velocity oscillations or stick/slip) into a different mode, such as axial (bit bounce) or lateral (whirl). Transitions between different types of whirl have also been recorded.
Several cases were studied to investigate the evolution and response of drilling system behavior based on the in-depth interpretation of relatively long durations (minutes to hours) of high-frequency data sets in the operational context. The findings verify the value of using continuous high-frequency vibration data to understand the drilling system and increase drilling performance.
CO2 Foam Pilot in Salt Creek Field, Natrona County, WY: Phase II: Diagnostic Testing and Initial Results
Authors: Norris S. O. , Scherlin J. M. , Mukherjee J. , Vanderwal P. G. , Abbas S. , Nguyen Q. P. 
Published: October 2014

Abstract
In a previous paper we described the laboratory work, reservoir simulation, and initial design of a CO2 Foam Pilot in the Salt Creek Field, Natrona County, WY. In this paper, we review the diagnostic testing and initial results from the pilot including: injection rate profile, production data analysis, injection and production logging, chemical tracers, streamline analysis, and reservoir simulation.
Although the CO2 flood has been very successful at Salt Creek, it is recognized that certain isolated patterns have exhibited high CO2 production and inefficient CO2 utilization, most likely due to the channeling of fluids through high permeability, low volume zones (fractures, thief zones, etc.) and the gravity over-ride of the injected fluids. Accordingly, a foam pilot was initiated to test the ability of CO2 to remediate these conditions.
A change in the injection well rate (at constant surface injection pressure) was the first indicator to be observed; the injection rate decreased by approximately 40%, indicating a strong mobility reduction of the CO2 in the reservoir. Production and injection profile logs were run before and after surfactant injection, and a change in profile was observed in one producer. Chemical tracers were injected in both the gas and water phases before and after surfactant injection; results indicate that CO2 was diverted from high permeability, low volume conduits, such as fractures. An analysis of the production data for the four offset producers show a definite increase in liquid production and a corresponding decrease in GLR (gas-liquid-ratio.) Streamline analysis suggest areal diversion of CO2 over time. Finally, reservoir simulation prediction cases are given and discussed.
CO2 flooding has become a standard EOR technique for many water-flooded fields. Methods for increasing the efficiency of these floods, such as the use of CO2 foam, can add great value.
Early Kick Detection Methods and Technologies
Authors: Fraser D. , Lindley R. , Moore D. , Vander Staak M. 
Published: October 2014

Abstract
Early Kick Detection (EKD) is one of the most important areas for improvement in well control safety. The need for earlier, more accurate, more reliable kick detection across a wide range of drilling operations has become increasingly important as more operations are being conducted in deep water with increasingly tight pressure margins. In order to accomplish this, it is important to start measuring the indicators that have the greatest impact. This paper identifies and proposes two risk based Key Performance Indicators (KPIs) related to kicks: how long it takes to positively identify a kick, and how long it takes to respond to a kick once the identification is made. These KPIs are the Kick Detection Volume (KDV) and the Kick Response Time (KRT) respectively. They provide the ability to directly measure kick detection and management approaches. A third metric, the Drilling Mode Kick Frequency (DMKF), while not a performance indicator, is critical to help determine the point at which drilling operation kicks are most likely to occur and thereby to aid in the evaluation of kick detection methodologies. This paper discusses and compares technical approaches to early kick detection including how they relate to safety, efficiency, and reliability over a range of common deep water operations. By identifying "actionable" indications of a kick, a general approach is suggested to help focus on technologies leading to the most likely improvements for EKD. Irrespective of the EKD optimization path chosen however, the proposed KPIs can be used to quantitatively evaluate and compare the performance of different technologies and operational strategies.