bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of DME as an EOR Agent: Experimental and Modeling Study to Capture Interactions of DME, Brine and Crudes at Reservoir Conditions
Authors: Ratnakar R. R. , Dindoruk B. , Wilson L. 
Published: September 2016

Abstract
Dimethyl ether (DME) is a small, slightly polar component, non-toxic that exhibits nearly ideal behavior with known liquid-state hydrocarbons, and is partially miscible with water/brine. In a multicomponent brine/DME/oil system, it partitions preferentially into the hydrocarbon phase. This unique characteristic of DME makes it a suitable candidate for enhanced waterflood while in essence water can act as the carrier fluid - it has the potential to unlock remaining oil from fields in a mature waterflood state. When DME mixed with brine is injected into the reservoir, it partitions preferentially into the oil phase (hydrocarbon phase) upon contact. As a result, the residual oil swells and its viscosity is reduced.
The amount of swelling and reduction in viscosity depend on how much DME partitions from brine into the oil and as well as the compositional characteristics of the oil. In addition, swelling and property changes are function of pressure-temperature conditions, DME concentration in oil as well as the salinity of the aqueous phase. Therefore, the estimation of the partitioning coefficient is very crucial to evaluate and understand the performance of DME enhanced waterflood (DEW) at reservoir or lab/pilot scale, as it controls the mass transfer from aqueous phase to hydrocarbon (oil) phase. In earlier studies, we presented the Equation of State (EOS) modelling and workflows to characterize the phase behavior of DME/brine/hydrocarbon mixtures that is encountered in reservoir processes, to estimate the partitioning coefficient, and calibrated and compared against the in-house experimental measurements. In this study, we extend the earlier work and perform extensive analysis on sensitivity of DME-partitioning coefficients with respect to pressure, temperature and salinities. In particular, we Present the comparison of predicting capability of the PVT models based on the two EOS: cubic plus association (CPA) [1] and Peng-Robinson (PR78) with Huron-Vidal (HV) mixing rules [2] against experimental data from literature or in-house measurements.Show that the model predictions are in agreement with the experimental observations.Present the extensive sensitivity analysis of DME-partitioning coefficient between oil and aqueous phases with respect to molecular weight of oil, temperature, pressure, salinities and DME concentration in oil phase, that can be utilize in quality check of the new data and preliminary screening criteria.Most importantly, develop an observation-based correlation to estimate partitioning coefficient for DME in brine and hydrocarbons, and to generalize the results for future screening studies where none or very limited PVT measurements with DME are available.
A New Model to Evaluate Two Leak Points in a Gas Pipeline
Authors: Guoqing Han , Zhenhua Rui , He Zhang , Kegang Ling 
Published: September 2016

Abstract
Natural gas is a clean fossil energy and an important sector in the energy consumption chart. Due to the increasingly environmental protection concern and natural gas's efficiency and reliability, the demand for natural gas increases steadily. To accommodate the ever rising in natural gas production and transportation, more gas pipelines are being constructed. Meanwhile, the existing gas pipelines are aging inevitably. One of the critical needs in flow assurance is detecting and locating pipeline leak in a timely manner. A reliable and timely detection of the leakage of gas pipeline can not only reduce the loss of hydrocarbon, but also limit the damage to facilities, possible loss of life, and the extent of environmental pollution. Two or more leakage points in a pipeline were observed in the field. Physical methods were employed to detect these leakages. However, literature review indicates that no mathematical model has been developed to detect multiple leaks in the same pipeline. This study is focused on the detection of two leak points in the same pipeline. Multi-flowrate tests are proposed to evaluate the locations and sizes of leakages in two leak points. This mathematical model is crucial when no physical inspection is available. The proposed model can be used to monitor possible leak in real-time because flowrate and pressure that are utilized to estimate multiple leaks are monitored in real-time and are available almost simultaneously. Therefore, the new method provides a practical, quick, and low computational cost approach to detect multiple leakages. The proposed method is important because existing mathematical models assumed single leak in a pipeline, which limits their applications because the detection will be misleading if there are more than one leakage in the same pipeline. The proposed model can differentiate single-leakage scenario from multi-leakage scenario based on multi-flowrate tests. The identification is critical because it guides the leakage detection to the right direction.
An Innovative Partnership to Develop an Oman Based Pressure Pumping Company
Authors: Hogan M. R. , Willis R. B. 
Published: September 2016

Abstract
In 2011, a subsidiary of the Oman Oil Company embarked on an effort to develop an Oman-based pressure pumping capability. What developed was an innovative partnership between a US-based service company and the Omani company. Technology transfer and training for Omani management and personnel was carried out in a hands-on and interactive fashion in the United States.
Throughout the process, the goal was to utilize Omani personnel as fully as possible. A well-defined list of equipment, technologies, and required materials were procured along with the training of key personnel. The plan had to be efficient in training and transferring the necessary skill sets to all phases of the human complement necessary to design, operate and maintain the highly technical equipment required in today's pressure pumping industry. HSE concerns were a cornerstone of every facet of the project. The paper will walk through the project and demonstrate the cooperation and structure that resulted in a successful business introduction to the Sultanate of Oman.
The final result was a successful launch of a fully functioning Omani-owned pressure pumping company in the Sultanate of Oman during the summer of 2013. This paper will outline the many varied disciplines, technologies, and hurdles that were worked through during the process. The planning required the development of a variety of interrelated schedules so that the equipment design, procurement, and delivery schedule meshed with the necessary personnel development needs.
With the expanding need for unconventional resource development, many countries are excited about the prospect of developing their own indigenous pressure pumping capabilities. The paper describes in detail how proper in-depth scoping and planning can result in a viable and successful indigenous new business start-up where none had previously existed.
Current State and Future Trends in the Use of Downhole Fluid Analysis for Improved Reservoir Evaluation
Authors: Elshahawi H. , Dong C. L. , Ramaswami S. R. , Cornelisse P. W. 
Published: September 2016

Abstract
The introduction of downhole fluid analysis (DFA) two decades ago was a major addition to the wireline formation testing suite of measurements previously available in the industry, both in to optimize the sampling operations real-time and to provide additional fluid measurements as an integral component of integrated fluid property interpretations. The progression from basic measurements such as fluid resistivity to advanced optical analysis has paved the way for much improved definition of reservoir fluids, including the variation of fluids within reservoirs.
Downhole Fluid Analysis is a continuously evolving field, so we will begin this paper by looking back at the history and evolution of various types of sensors for operational real-time decision making as well as post-operational fluid evaluation. Our emphasis will be to catalogue the strengths and limitations of each method and highlight the importance of integration. We will then highlight current capability gaps, focusing on the need for improved real-time contamination monitoring in some environments of interest and our desire to measure additional fluid properties and specific species concentrations.
Oil Industry First Interwell Trial of Reservoir Nanoagent Tracers
Authors: Kosynkin Dmitry , Alaskar Mohammed 
Published: September 2016

Abstract
This manuscript reports the industry's first proven reservoir nanoagents' design and describes a successful multi-well field trial using these inexpensive and environmentally friendly nanoparticles that offer an important advantage of fast and cheap fluorometric detection. Our fundamental nanoparticle tracer template, A-Dots or Arab-D dots, is intentionally geared towards the harsh but prolific Arab-D carbonate reservoir environment of 100°C temperature, 150,000 ppm salinity, and an abundant presence of divalent ions in the connate water. The A-Dots were manufactured on a scale of one metric ton from affordable and easily available commodity chemicals. They were injected into a watered-out part of the field and monitored at four nearby producer wells for two years. Monitoring of four neighbouring producer wells over a period of 26 months confirmed nanoparticles' breakthrough at a single producer nearly 500 m from the injector at the reservoir level, thus, proving the nanoparticles' mobility and transport capability. The maximum concentration of the nanoagent in produced water was observed about 10 months after the injection matching the behavior of conventional small-molecule tracers used in the same pair of wells previously. The rate of A-Dots production correlated with the rate of water injection at the original injector well and followed it closely with a 10-month delay.
This test bolstered our previous observations of satisfactory recovery of A-Dots in a single-well test by confirming their reservoir stability on industry relevant time scales and demonstrating the feasibility of their industrial production. The importance of this accomplishment is not in how sophisticated the sensing functionality of the tracer design is but rather in the nanoparticle stability, mobility, scalability, and field application potentials. Our findings render the concept of having active, reactive, and even communicative, in-situ reservoir nanoagents for underground sensing and intervention a well anticipated near-future reality.
Successful Identification of Cold Oil Steamflood Development Projects
Authors: Popa Andrei , Woolford Jeff , Cassidy Steve 
Published: September 2016

Abstract
Although the hottest topic today is unlocking unconventional resources, the established heavy oil reservoirs continue to offer a great opportunity for growth given the relative low cost of development. The mature heavy oil reservoirs generate high returns given the existing infrastructure in terms of facilities, pipeline, generators, knowledge of the steam distribution, and the continuing technology advancements in subsurface understanding and modeling
In this study we introduce a novel approach for the successful identification of remaining cold oil steamflood opportunities in a mature field through the use of heat management knowledge, large data utilization, ArcGIS and mapping artificial intelligence technologies. The methodology exploits the log data and existing full-field earth model and automates the screening and ranking of development patterns of a large heavy oil field. The workflow proposed replaces the manual engineering approach which uses hard cut-offs applied on key petro-physical properties to find promising areas for development.
The combination of the knowledge acquired during 30 plus years of operations, integrated with intelligent data driven technologies generate tremendous business value to smart operators who pursue these opportunities and continue to embrace these types of resources.
Analytical Study of Flowing and In-Situ Compositions in Unconventional Liquid-Rich Gas Plays
Authors: Zhang Miao , Ayala Luis F. 
Published: September 2016

Abstract
Liquid-rich gases in unconventional reservoir environments can exhibit complex phase and flow behavior due to gas condensation and re-vaporization and differences in phase mobilities that results in compositional variations inside the system. To date, the analysis of in situ and flowing composition variation in unconventional liquid-rich wells has been largely limited to numerical modeling. This work uses an analytical approach to study the in situ and flowing fluid composition of gas condensate wells producing under infinite-acting linear flow—a commonly observed flow regime in hydraulically-fractured horizontal wells in unconventional formations. We propose a semi-analytical solution to the governing partial differential equations (PDEs) written in terms a compositional fluid formulation. The proposed solution is developed using Boltzmann's transformation and is validated by both analytical development and numerical simulation data. Results corroborate that when hydraulically-fractured horizontal wells are producing against a constant bottomhole pressure (BHP) constraint, the producing wellbore fluid composition remains constant as long as the system remains infinite acting, leading to a constant producing gas-oil ratio (GOR). This constant wellstream composition is shown to be very different from in situ composition, which varies according to pressure and production condition inside the reservoir.
Development of a Reactive Transport Simulator for Carbonates Acid Stimulation
Authors: Maheshwari P. , Gharbi O. , Thirion A. , Ali N. S. , Peyrony V. , Aubry E. , Poitrenaud H. M. , Benquet J. C. 
Published: September 2016

Abstract
An accurate description of reactive transport phenomenon in porous media has major applications for many processes such as, contamination in groundwater resources, carbon capture and storage, enhanced oil recovery, and acid stimulation. These processes, involve surface reaction coupled with flow that result in dynamic alteration of the porous media structure. More particularly, in well acidizing, an accurate understanding and control of the stimulation operations outcomes still represents a major challenge in heterogeneous carbonates. The objective of this paper is to describe how an integrated experimental and numerical approach is adopted to develop a core-scale reactive transport simulator that could be used to investigate acidizing efficiency in carbonates.
A series of core flooding experiments were performed on Richemont carbonate blocks from queries at reservoir temperature. A back pressure valve system is used to eliminate the effect of free gaseous CO2 on the flow dynamics of acid. Moreover, mathematically, a continuum-scale model was used to describe the reactive transport phenomenon. This model consists of fluid transport, continuity, species balance, and porosity evolution equations at a continuum scale. The porous media characteristics such as permeability and pore radius are obtained as a function of local porosity using closure relations. The rock properties required as input to the model come from numerous experimental techniques such as computed tomography (CT), Mercury injection capillary pressure (MICP), and X-ray diffraction (XRD)
The numerical results obtained using the model, show a close match with the experimental observations, in terms of pore volume to breakthrough (PVBT). Additionally, the developed model was able to reproduce the different dissolution regimes along with the transient pressure response, as observed experimentally.
The Role of E-Well Books in Conducting Integrated Well Reviews and Identification of Production Optimization Opportunities, A Case Study from Iraq
Authors: AlSaad Radhwan , Subramanian Sundararaman , Al Jumah Ali , Kumar Randhir , Alharthy Said 
Published: September 2016

Abstract
Data integration helps in arriving at informed decisions and to manage assets efficiently. During the entire lifecycle of operations, starting from drilling to production operations, various disciplines that cover Subsurface (Geology, Reservoir Engineering and Geophysics), Well Engineering, Production Technology, and Asset Maintenance are involved. Each of these domains generates its own specialized sets of data which are maintained in various databases and applications. These disciplines wise fragmented data items can be linked under a hierarchy with either a Well/Reservoir at the top level. Managing key information across the entire lifecycle of a Well/Reservoir then requires combining data from diverse sources and bringing them in one unified view. Electronic Well Book is a key solution that translates this requirement, of having one view from diverse data elements covering various disciplines. Like a physical book, the Electronic Well Book is designed with each well as a chapter and the data elements that capture key events, data gathered, data analyzed and live data are represented as individual pages. The Electronic Well book is a tool that provides one source of data, faster data access, better defined quality checks, and integrates work flows, making collaboration easier. The well book method of information representation ultimately contributes significantly in identifying production enhancement opportunities, which when matured and executed leads to production gains. In addition, the live feed data facilitates monitoring rates/pressures and identifying deviations from the trends, reporting them accordingly in the same chapter, upon which actions to be taken.
E-wellbooks fulfill the objective of having only one source of truth, one integrated database, where every team member will find any piece of information with minimum effort, shorter period of time and more efficient manner. The case study presented herewith, demonstrates the pragmatic approach followed in well reviews and the value generated utilizing this novel methodology.
Ultra-high Temperature Rated Elastic Carbon Composite Packer for Reliable Downhole Zone Isolation
Authors: Xu Zhiyue , Zhao Lei , Prieto Carlos A. 
Published: September 2016

Abstract
This paper presents the oil industry’s first ultra-high temperature elastic seal element that is made from a novel elastic carbon composite (ECC). The discussion centers on the ECC composite design, superior material properties compared to elastomeric seal materials, and the reliable performance of an ECC packer element under extreme thermal conditions such as a steam injection well.
Exploration and production activity increasingly involves operations in extremely high temperature/ high pressure (HP/HT) and corrosive sour environments. These conditions create a great challenge to downhole sealing components that rely on elastomers or plastics as these materials are prone to degradation when temperatures reach 500°F (260°C) or even lower in fluids. Metal-to-metal seals may have the temperature tolerance, but lack enough elasticity and malleability to provide a reliable downhole seal. The novel alternative discussed in this paper is to fully utilize the high thermal and chemical stability and elasticity of a carbon material, and combine it with nano-reinforcements to enhance the interlayer strength of a carbon matrix. This combination results in an elastic carbon composite and thermal packer that is strong, elastic, and resistant to extrusion, downhole high temperature, thermal cycles and corrosion.
Tests show that the ECC composite has excellent thermal stability up to 1000°F and strong corrosion resistance to most downhole fluids, including hydrocarbons, brines, acids, etc. More importantly, ECC has displayed improved mechanical strength – up to 15,000 psi (1034 bar) – and elasticity (&gt;6%). When compared to elastomers, ECC generates much higher sealing and anti-extrusion forces, and shows significantly less or no stress relaxation at high temperatures. In addition, the low density and self-lubricating property observed from the ECC materials (0.07 coefficient of friction) make it an attractive alternative for dynamic seal products. Seal failure of packer elements at high temperatures and under large well temperature fluctuations is a common and costly problem to the oil industry. The ECC seal elements delivered superior sealing performance in packer tests at high differential pressures above 600°F (315°C) and withstood repeated fluctuations in temperature of 525 Δ°F [273 ΔC].
The novel ECC composite and unique packer elements provide reliable solutions to HPHT sealing challenges in the oil and gas industry.
Rospo Mare Integrated Reservoir Study Italy, Adriatic Sea: An Innovative Approach of Karst System Modeling and History Match
Authors: Bellentani G. , Godi A. , Siliprandi F. , Terdich P. , Famy C. , Fournier F. , Jumeaucourt C. , Leandri P. , Le Maux T. 
Published: September 2016

Abstract
Rospo Mare is a heavy oil fractured karstic carbonate reservoir producing since the 80's. Reservoir pressure is constant due to a strong aquifer tilted toward north east. The producing wells are systematically operated at critical rate to prevent water production (no water treatment installation). The paper is focused on the modeling of the fractures and the karst system in conjunction with an innovative history match approach used to match the forced anhydrous oil production and to represent the complex water position and behavior through time.
As the main fracturing phase of Rospo Mare reservoir occurred before the karstification phase, the dissolution of the carbonates was guided by the existing fracture network. The karst system and the fracture network were modeled together thanks to a fracture model that includes several enlarged fracture sets and lineaments. The fracture modeling was also guided by the relative compactness of the matrix facies distribution. Because of limited data for fracture characterization, the dynamic characteristics of fractures, particularly the aperture of enlarged fractures, were fully considered as history match parameters. The history match approach consisted in using both the historical oil production and the prediction period to make sure that the wells were producing at their critical rate and ensure a realistic displacement of water at both field and well levels. This unusual strategy was necessary because of lack of data to constrain history match (no water and gas production, no pressure variation).
Therefore the history match was performed by taking into account the prediction period through a do nothing case scenario. Based on the assumption of critical rate, a decline of the oil production rate is expected during the prediction period. This allowed assessing the vicinity of water at wells: both the rise of the water table and the coning effect at wells. The matched model successfully honors the water displacement and position at key wells including the last two side tracks drilled in 2012. The model allows a good representation of the reservoir physical behavior and provides a useful tool for piloting the field and assisting future decisions.