bluuebunny/crossref_metadata_2025_split huggingface dataset:
CTU Deployed Frac Sleeves Benchmark Horizontal Multi Stage Frac Isolation Performance
Authors: Schmelzl Eric , Schlosser Daniel , Alvarez Domingo , Gulewicz Dale 
Published: June 2014

Abstract
The paper summarizes field results and data which indicate the effectiveness of open hole packers vs. cement in providing competent hydraulic isolation of well segments in horizontal multi-stage completions. The application of multistage fracturing treatments to horizontal wellbores has facilitated unparalleled reservoir access, which is the catalyst for tight-rock exploitation. Whether created utilizing a cemented wellbore or an open-hole (O/H) packer style of completion, the massive surface area of induced and dilated fractures is a key ingredient for the successful completion of low permeability formations. Unfortunately, many of the commonly used completion systems offer little or no indication of the effectiveness of the hydraulic isolation between fracturing stages. In completions employing ball-activated sleeves in combination with O/H liner packers, the only indication of failed hydraulic isolation is masked in the surface treating pressure data collected during the frac. Multiple stages in the tubing at the same time can have the effect of masking the treating pressures as friction and increased hydrostatic pressure of the sand slurry have competing effects. This difficulty in interpreting the surface pressure readings can result in segments of the wellbore being either bypassed or overtreated as a result of the fracture treatments coalescing, potentially preventing the recovery of the targeted reserves. The paper reviews and compares data collected through the application of a combination of Coiled Tubing Unit (CTU) operated frac sleeves with either O/H packers or cemented liners. The use of CTU in the isolation of individual frac stages offers the capability to collect downhole pressure and temperature data of each frac treatment at the frac port, which is typically not available through other methods. Because this data is collected downhole, it can provide clear indications of O/H packer or cement effectiveness in isolating discreet fracture stages, potentially identifying segments of the reservoir which may remain un-stimulated, or possibly over-treated. The downhole data collected through the application of CTU operated frac sleeves may be valuable for operators seeking to maximize the effectiveness of their stimulation programs through optimal packer placement or cementing design, and may potentially help to maximize EUR for multistage completions.
Production Comparison of Hydraulic Fracturing Fluids in the Bakken and Three Forks Formations of North Dakota
Authors: Fry Jessica , Paterniti Melanie 
Published: June 2014

Abstract
There have been extensive efforts to recover oil from the Bakken formation in North Dakota since it was discovered in 1951. However, these efforts were not particularly profitable until the 2000s when horizontal drilling and large, multistage hydraulic fracturing treatment methods were used. The new drilling and completions methods created a substantial increase to production, which escalated throughout recent years and created a demand for better, more efficient completions. One major component of these completions is the base fluid used for hydraulic fracturing treatments. This paper compares hydraulic fracturing treatments of a new, residue-free (res-free) hydraulic fracturing fluid to all other fracturing fluid treatments.
The res-free fluid system was presented in 2012 as a premier fracturing fluid and economic alternative to guar-based systems to increase the resultant fracture conductivity. Since 2012, more than 40 wells have been completed in either the Bakken or Three Forks formations of North Dakota using the res-free fracturing fluid. While initial cost savings were realized, the production results from these wells have not been extensively studied. This paper presents the findings of a study comparing production from wells treated with res-free fracturing fluid to wells treated with other hydraulic fracturing fluids.
Because the wells completed using the res-free system are widespread throughout North Dakota and belong to several different operators, choosing a specific study area was challenging. To overcome this challenge, a spatial sampling technique was used. Spatial sampling is a method for comparing a large group of wells to their direct offsets. For this study, spatial sampling was applied to compare wells completed using the res-free system to wells completed using other fluids. To normalize general completion methods, only wells completed since the beginning of 2012 are included in this study. Offset wells for this study are those within a 1-mile radius from the center well. The production data for all wells was obtained from public sources. The proppant amount and total fluid volumes were normalized per foot of lateral to minimize variables. Other factors, such as drilling placement, type of proppant, type of fluid, or compartmentalization can affect production; however, these effects are not considered during this study.
Experimental Study and Modeling of the Effect of Nanoconfinement on Hydrocarbon Phase Behavior in Unconventional Reservoirs
Authors: Wang Lei , Parsa Elham , Gao Yuefeng , Ok Jeong Tae , Neeves Keith , Yin Xiaolong , Ozkan Erdal 
Published: June 2014

Abstract
The pore sizes of shale and other unconventional plays are of the order of tens of nanometers. Based on the fundamental theory of thermodynamics, several studies have indicated that, in such small pores, phase behavior is affected by the capillary pressure and surface forces and is different from that characterized in PVT cells. No experimental evidence of this phenomenon, however, has been presented in the literature. In this study, we apply nanofluidic devices to visualize phase changes of pure alkane and an alkane mixture under nanoconfinement as a means to approach oil/gas phase behaviors in nanoporous rocks. Pure alkane starts vaporizing in the micro-channels first, and then the meniscus flashes into the nanochannels immediately after the complete vaporization of the liquid in the micro-channels. The vaporization of the ternary hydrocarbon mixture, however, is very different from pure alkane. Although the liquid starts to vaporize in the microchannels first, as expected, the meniscus cannot propagate into the nano-channels in a comparable time scale as the pure alkane. The reason is that the liberation of lighter components from the liquid phase to the gas phase in the micro-channels increases the apparent molecular weight of the liquid in the nano-channels, suppressing the bubble point of the remaining fluid. A modified flash calculation procedure that uses the sizes of micro-channels and nano-channels as the characteristic lengths and assumed contact angle can reproduce the vaporization propagation sequence in the experimental observations. Experiments and modeling presented in this paper provide the proof of the concept and promote the understanding of phase behavior in nanoporous unconventional reservoirs.
A Pattern-Based Approach to Waterflood Performance Prediction Using Knowledge Management Tools and Classical Reservoir Engineering Forecasting Methods
Authors: Artun Emre , Vanderhaeghen Maurice , Murray Paul 
Published: June 2014

Abstract
Estimating future performance of waterflooded reservoirs is a challenging reservoir engineering problem in complex reservoirs that are poorly defined. Flow simulation models characterized by limited spatial data of a key heterogeneity do not always represent the reservoir dynamics for water movement. In this paper, an efficient and rapid workflow is presented to estimate the recovery performance of an existing vertical-well, pattern-based waterflood recovery design using knowledge management and reservoir engineering in a collaborative manner. The knowledge management tool is used to gather production data and calculate pattern-based recoveries and injection volumes by defining pattern boundaries and allocating annual well injection/production volumes in a systematic manner. Classical reservoir engineering forecasting methods, namely, a combination of oil cut versus cumulative recovery performance curves, and decline curve analyses are applied to forecast the performance of the waterflood pattern of interest. The methodology is first applied to a synthetic reservoir model, and then to data from a real field developed by an inverted 9-spot recovery design. Extrapolating established trends of oil cut vs. recovery for each pattern for both the synthetic and real cases quantified future performance assessments. Time can also be attached to the performance by introducing liquid rate constraints. Forecasts based on real data highlighted the optimistic nature of the dated full-field simulation history match and provided a more realistic forecast for business planning. Forecasting using both constant and declining liquid rates differentiated the impact of deteriorating reservoir pressure and oil-cut trends on individual pattern oil rate forecasts thus defining current efficiency of each pattern. The methodology as a result turned into a simple yet powerful forecasting workflow that can be used by any asset team. This study is a very good example of how knowledge management tools can be used to increase the capabilities of classical forecasting methods in reservoir engineering.
Thermodynamically-Consistent Modeling of Adsorption in Liquid-Rich Shales
Authors: Rajput Vaibhav , Ertekin Turgay 
Published: June 2014

Abstract
Reservoir simulation and material balance techniques require accurate estimation of fluid storage and transportation mechanisms. In dry-gas shale reservoirs, it is widely acknowledged that gas adsorption is one of the most important storage mechanisms, and that it accounts for close to 45% of initial gas storage. In case of liquid-rich shales however, typically, adsorption is not considered as a storage mechanism. This paper proposes a method to estimate fluid adsorption from liquid phase in shale reservoirs. The proposed adsorption modeling formalism is based on the thermodynamically-consistent Ideal Adsorbed Solution (IAS) theory. The main development in this work is that adsorption from liquid phase can be calculated from its unsaturated vapor phase at the limiting saturation condition. Once the composition of this unsaturated phase is determined, the use of IAS theory would result in the amount and composition of the adsorbed phase being calculated.
Initial results suggest that, given a liquid phase mixture, typically about 5-13% of the fluid is adsorbed. This indicates that a significant amount of the liquid mixture initially exists in the form of adsorbed phase. However, the amount of each component in the adsorbed form is strongly dependent upon the total adsorption capacity of the particular shale, the amount of adsorbent present, as well as the adsorption affinity exhibited by the shale towards each component. Negligence of accounting for adsorption from liquid phase would result in erroneous calculation of total recoverable reserves from a particular liquid-rich field. This would also affect the enhanced recovery calculations, as thermodynamics would play an important role in the sorption of hydrocarbon components. This paper presents a direct and thermodynamically-consistent method of calculating the amount and composition of the adsorbed phase from liquid-rich shale reservoirs.
A Method for Pinpointing the Location of High Permeability Channels
Authors: Wu Hao , Najem Noha , Ershaghi Iraj 
Published: June 2014

Abstract
Many EOR processes fail because of the existence of unaccounted high permeability channels or fractures. Given a field under waterflood, where downhole pressures in producers can be continuously measured via permanent downhole gauges (PDG), we present a workflow process for pinpointing of high permeability channels without much disturbance of the field operations. The methodology requires a systematic scheduling of variations in the injection levels at selected injectors. The purpose of this study was to investigate the accuracy of estimated heterogeneity trends from processing of downhole response data.
The field setting is first divided into a series of clusters. Ranking of estimated high permeabilities among the clusters is the basis for mapping and pinpointing the location of the high perm channels. We demonstrate how the proposed algorithm can be used to detect sub seismic high permeability channels that negatively affect sweep efficiency. It can further allow an estimation of regional values of effective total compressibilities related to fluid types and areas with limited pressure support. This offers an enabling tool in designing and forecasting of field pilots for processes requiring expensive injected fluid.
Anisotropic Model for Permeability Change in Coalbed Methane Wells
Authors: Moore Robert , Palmer Ian , Higgs Nigel 
Published: June 2014

Abstract
With depletion of coalbed methane (CBM) wells in the San Juan Basin, permeability rises by 10 to 100 times. Similar permeability increases are found in other CBM basins around the world. Models previously advanced to explain this behavior combine a compaction mechanism (which closes cleats) with matrix shrinkage (which opens cleats). In this paper, the original model (Palmer-Mansoori model) is extended to include the transversely isotropic elastic response found in vertically cleated coals. This new version of the model has been calibrated by laboratory measurements on San Juan Basin coal loaded under uniaxial-strain conditions to simulate reservoir depletion. The result is a predictive model characterized by two measured Young's moduli and three measured Poisson's ratios.
To our knowledge, a rigorous geomechanical analysis of anisotropic coal has not before been incorporated into efforts to match large permeability increases observed in the field. We have been able to match the permeability increases in CBM wells using rock and reservoir parameters that are viable and consistent with independent constraints. To illustrate the results, permeability increases with depletion from a few wells in one area of the San Juan basin have been matched by the new model. The new model should allow better forecasting of gas rates by reservoir simulators, as well as improved predictions of gas production in fields yet to be developed.
While there exist many models that seek to explain the huge permeability increases in coalbed methane wells, the significance of this logical extension to the Palmer-Mansoori model (i.e., the addition of coal anisotropy) is that it has the ability to predict permeability increases in wells in the field using measurable rock moduli and other quantities, thus reducing the need for empirically-derived field-matching parameters. Note that this new model confirms an empirical constant that was invoked in a previous version of the Palmer-Mansoori model to account for cleat anisotropy. The rigorous derivation, for anisotropic coal, of permeability increase during depletion provides a missing link (and a significant one) that will save modelers from invoking more esoteric (and unnecessary) factors to try to get a match to field data.
Corrosion Management - it's all gone holistic
Authors: Stokes Pat , Sandana Daniel , Jones Lee 
Published: June 2014

Abstract
To manage the integrity of assets operating beyond their design life proactive corrosion management is essential. Traditionally topsides process plant, subsea pipelines and onshore terminals have been subjected to individual corrosion management schemes. An holistic approach that brings the corrosion management of these individual components into an integrated Corrosion Management System (CMS) has been developed for a variety of ageing offshore assets.
The CMS comprises a Corrosion Control Scheme (CCS), a Topsides Risk Based Inspection (RBI) scheme, a Corrosion Risk Assessment (CRA) and a Pipeline Risk Assessment (PRA).
The objectives of this integrated CMS process are to: Proactively identify all corrosion threats and define related riskDefine mitigation controls as necessary and ensure implementationEnsure mitigation controls are effectiveEstablish and implement corrective action as necessary
The overall corrosion management strategy is implemented by the CCS for a specific production asset which identifies the corrosion threats. It establishes the control and mitigation procedures required to mitigate internal and external corrosion on topsides process plant, subsea pipelines and related subsea components. The degradation mechanisms, controls and mitigation procedures are mirrored in the other CMS components. The future inspection programme for topsides process plant is driven by the RBI, whilst the CRA and PRA drive the future inspection and monitoring regimes for subsea pipelines. Results from these components are fed back into any review and upgrade of the CCS.
A CMS has been developed and implemented that meets the following objectives: A transparent and auditable decision making processProactively identifies corrosion threats and defines related tasksDefines mitigation controls as necessary and manages implementationEnsures mitigation controls are effectiveDefines inspection and monitoring regimes to assess asset conditionEstablishes and implements corrective actions as necessaryAn integrated scheme such that changes in one component are mirrored in the others.
Inching Toward Complete Well Integrity Management
Authors: Kumar Sanjiv , Al-Atwi Mohammed A. , Al-Mulhim Abdulrahman K. , Al-Otaibi Mohammad A. , Al-Mulhim Mohammed S. , Bu Ali Ahmed T. 
Published: June 2014

Abstract
Well integrity management (WIM) is an art of managing the well to reduce risk applying technical, operational and organizational solutions. With maturing fields and the evolution of advanced technologies, the industry has significantly improved in terms of WIM, though the art is still to be mastered. Nevertheless, WIM over the years has evolved and to some extent has become reliable enough to provide high confidence to operators to safely operate and manage matured fields. In spite of all the WIM practices in place, failure does happen. The root cause of the failure is carefully studied and necessary changes in process/technique are incorporated to ensure that such reoccurrences are not repeated.
Well integrity management starts from the stage of designing a well and continues throughout the life cycle of a well. The risk management becomes intense and difficult as the well gets older. Investment in gathering valuable well data remains a key to mitigate from risk and to better anticipate potential failures. Classical approaches to WIM are mainly for detecting a failure. Now, there is a paradigm shift, thanks to advanced technology at our disposal, to go for a predictive approach in forecasting a problem before it happens.
This paper describes the evolution story of proactive WIM at Saudi Aramco with emphasis on the utilization of corrosion monitoring tools as a predictive approach. The results of such a methodology can predict many "to-be" failures and allow for the timely resolution of expected integrity related challenges. The paper also narrates one case study for an oil well-A from Saudi Aramco, which developed a failure. The study of the root cause of the failure and lesson learnt were applied in improving the risk mitigating technique, and so inching toward complete WIM.
Chemical Treatments Practices and Philosophies in Oilfields
Authors: Awan M. A. , Al-Khaledi S. M. 
Published: June 2014

Abstract
Application of chemical treatments has become an essential part of everyday oilfield operations, to achieve specific objectives, minimize production problems, reduce production costs and achieve product specifications. Also, many process equipment performance and reliability problems can be solved economically by proper selection and application of chemical treatment practices. For instance, the corrosion problems that can be solved by changing metallurgy, reducing velocity, changing process conditions, removing corrosives upstream, can credibly be prevented by using corrosion inhibitors.
With increasing oil production, rising water cuts, H2S related issues and increased effluent water injection & disposal, the oilfield operating conditions are becoming more stringent, entailing the projects to be engineered with higher projected life. Also, with growing HSE concerns and compliance with environmental regulations, application of varied chemical treatments have become inevitable. Projects have been undertaken for introducing new chemical treatments, bulk handling of production chemicals, installation of chemical injections and monitoring systems. This necessitates periodic assessment of the chemical treatment practices and philosophies, for selecting and effectively monitoring & controlling performance of the chemical treatments by adopting a systematic approach.
To this effect our Company has deployed a huge network of chemical treatments and management systems all over its fields, for protecting its facilities/equipment, improving their performance, achieving quality, etc., taking into consideration; the process equipment problems, addressing HSE concerns and effectiveness of chemicals, etc. By operating and adopting a systematic & structured approach the chemical treatment practices have demonstrated proven performance. Those practices are not only cost competitive, but often can be implemented on-stream without curtailing unit operations.
New generation of Sour Service Drill Pipe Allows Addressing Highly Sour Field Challenges
Authors: Flores Vincent , Rodrigues Ricardo , Thomazic Aurelie , Thebault Florian 
Published: June 2014

Abstract
With the increasing demand of gas worldwide, some highly sour oil and gas reservoirs have been explored in Russia, Middle East, China and North America. The development of such fields, which contain a high percentage of sour gas, represents significant technical challenges regarding drill pipe integrity and operations safety. Sour service drill pipe have long been used with tool joints and tubes meeting separate criteria for sour service as defined by several industry standards. This solution is still acceptable today for most of the current fields. However, the new challenges associated with the particularly sour fields require new highly engineered drill string solutions in order to increase the safety margin related to Sulfide Stress Cracking (SSC) failure risks, especially in the welded zones.
Drill Pipes are commonly produced by assembling pipe and tool joins through friction welding. The weld, as a result of this process, presents, nevertheless, some challenges for preserving SSC resistance due to some metallurgical factors such as heterogeneous microstructure, different chemical compositions between the tool joint and the pipe body and high hardness values close to the welded line. Hence a new drill pipe configuration has been developed including modified chemical composition and modified manufacturing process. These modifications allow for the improvement of mechanical properties performance and SSC resistance in the welded zone.