bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Unconventional Gas Evaluation Workflow: from Anisotropic Geomechanical Modelling to Completion Design
Authors: De Gennaro V.. , Amri R.. , Brignoli M.. , Kallel N.. , Wielemaker E.. , El Ayeb S.. 
Published: June 2014

Abstract
Emerging unconventional exploration targets in North Africa are gaining increasing attention. Experience gained over the past two decades on unconventional gas reservoirs (e.g., tight sands, gas shales) has demonstrated that viable economics for unconventional resource plays can only be met if reserves are proved (reservoir quality) and producible (completion quality). With the reservoir quality identified, improved productivity in ultra-low-permeability unconventional reservoirs requires extensive hydraulic fracturing treatment to maximize contact area and unlock resources.
North Africa geological settings represent a challenging environment for effective hydraulic fracturing design. Deep reservoir targets, active tectonics and simultaneous occurrence of heterogeneous rock properties (including isotropic and anisotropic behavior) constitute a unique endeavor for a correct geomechanical modeling and a reliable assessment of closure pressures and fracture containment as input for hydraulic fracturing design.
This paper describes the implementation of an integrated unconventional evaluation workflow adopted for the completion design and hydraulic fracturing of a vertical well in tight sands and gas shales. A data acquisition program for tight formations was implemented to ensure full integration of logs data and core data from laboratory testing. Anisotropic measurements from an advanced borehole sonic logging tool and laboratory geomechanical tests were used to characterize the mechanical behavior of the reservoir lithological units, showing high degree of mechanical anisotropy in Silurian shales and Ordovician clayey horizons. Since isotropic assumptions predict inaccurate stress magnitudes and lead to significant error in stress contrast, the use of anisotropic-based geomechanical modeling is emphasized with regard to wellbore stability analysis and completion design. The integrated workflow involving anisotropic stress modeling allowed addressing and solving open issues related to wellbore failure prediction and estimation of hydraulic fracture containment.
For completion design purpose a comparison between different assumptions in terms of geomechanical input and hydraulic fracturing stimulation outputs is presented. The influence of the two different stress models (i.e. isotropic and anisotropic) is discussed. The effect on fracture geometry of the anisotropic clay layers, commonly treated as purely isotropic, is emphasized. It is shown that the hydraulic fracture in tight sands stays more contained in the reservoir target providing a better reservoir contact and optimum completion due to the higher minimum horizontal stress predicted by the anisotropic model in the clayey intervals.
Adaptation of Successful Tight-oil Stimulation Technique in Unconventional Resource Play in Western Siberia
Authors: Kaluder Zdenko , Nikolaev Maxim , Davidenko Igor , Leskin Fedor , Martynov Mikhail , Chong K. K. , Prokhorov Alexey , Shnitko Andrey , Fedorenko Evgeny 
Published: June 2014

Abstract
Application of horizontal multiple-stage fracturing is becoming the standard completion technique for oil and gas developments both in shale and tight sands. This technology has proven to be a game-changer within the US oil and gas industry to the point of creating an oversupply of gas in the US. Predictions indicate that the supply of oil related to this technology could allow the US to become self-sufficient within the decade. Globally, shale and tight-sand exploration activities are also increasing. This concept was successfully suited for and applied within a Russian tight-oil play in the Em-Egovskoe license area in western Siberia.
This paper provides the case history of how a horizontal multiple-fracturing completion methodology helped unlock the potential reserves in the western Siberian Em-Egovskoe tight oil field. This very heterogeneous and lenticular sand oil play was known for years for its complexity and arduous nature. The completion technique employed a proven North America multiple-stage fracturing technique using a combination of swellable packers and sliding-sleeve frac ports. The fracturing design for the Em-Egovskoe field is discussed. This design is an adaptation of an alternating hybrid fluid system composed of proppant slugs during the pad stage and a high-concentration proppant ramp in the main frac stage.
The well is currently flowing at commercial rates synonymous with early production in a typical North American oil shale well. The various monitoring techniques for measuring fracturing efficiency are also discussed. A production curve fit analysis using early production data allowed the operator to evaluate how the project was being commercially realized. Results and recommendations are presented.
Rigless Operation to Restore Wellbore Integrity using Synthetic-based Resin Sealants
Authors: Jones P. J. , Karcher J. D. , Ruch A.. , Beamer A.. , Smit P.. , Hines S.. , Olson M. R. , Day D.. 
Published: June 2014

Abstract
Sound wellbore construction and maintenance are essential to the successful development and production of hydrocarbons from unconventional resources. During the development of a Polish shale play near the Ukrainian border, the integrity of a well under construction became compromised resulting from a breach in an external casing packer on the production string. Successful completion of this well could require fracture-stimulation operations at pressures up to 9,000 psi, which would be impossible, unless the breach could be repaired. A cementing valve just above the breached packer had already reduced the inside diameter (ID) of the 4 1/2-in. production string to 3.827 in. The difficulty of running a casing patch in this restricted environment and the further diameter reductions eliminated this option from being a preferred solution. In addition, the high pressures associated with fracturing operations warranted an innovative solution, rather than a conventional approach. Recently commercialized resins have displayed the ability to withstand stresses higher than 10,000 psi and compressive strains greater than 40% without failure. However, case histories on field deployment of these materials, their ability to be drilled, and performance after hydraulic fracturing were essentially non-existent. This paper presents a case history on the laboratory development of a customized resin solution, the rigless operation using coiled tubing (CT) to place the materials and repair the breached packer, and the drillout after placement. Effectiveness of the remedial operation was determined by subsequent pressure testing. After restoring wellbore integrity, hydraulic fracturing operations were completed and successful production from this well began.
Case Study—Investigating Probable Root Causes Behind Consistent Higher Water Cut in a Mother CBM Well than its Deviated Wells: Well Spacing, Well Stimulation, and Overlying Strata Viewpoints and Recommendations
Authors: Chandra Sreerama , Adil Faraaz 
Published: June 2014

Abstract
Production from coalbed methane (CBM) reservoirs can often be challenging, particularly related to the dewatering process. Improper positioning and completion of wells can lead to increased complications during the production phase. Additionally, consistently high water levels (undeclined static reservoir pressure) can impede gas production. This paper describes well and production information from the Raniganj coal block.
The pad completion discussed has a mother vertical well (V-well) in which three main coal seams were completed (of the total five main seams with interspersed local seams), and dewatering commenced in 2009. At the end of 2011, encircling the V-well, four deviated wells (D-wells) at different azimuths were positioned at horizontal closures of 263 to 364 m from the bottom seam of the V-Well, wherein five main coal seams, along with interspersed local seams, were completed and scheduled for dewatering in mid-2012. Despite consistent high water production rates from the V-Well, the water levels in the V-Well stood consistently higher (rising upward) than the water levels in the D-wells, unlike nearby V and D-well pads. Well spacing information, well stimulation plots, perforation plans, and overlying strata for all five wells on this pad were studied and conclusions were drawn. This paper discusses such conclusions as well as the analyses performed to understand these issues. An attempt has also been made to best optimize hydraulic fracturing (HF) treatment designs to obtain the maximum benefits from stimulation operations.
The results reported in this paper will influence the operator's cost optimization, which could be a major positive influence on the low-cost CBM market in addition to increasing efficiency of the entire operation.
Effect of Salt Concentration on Base-gel Viscosity of Different Polymers used in Stimulation Fluid Systems
Authors: Das Prasanta , Konale Sumit , Kothamasu Ramya 
Published: June 2014

Abstract
Most conventional and unconventional reservoirs use viscous fluid systems for hydraulic fracturing for various reasons, such as good proppant transport, less fluid loss, less pumping friction pressure, etc. Salt is often introduced as part of the fluid system for clay protection as well as to increase hydrostatic pressure, resulting in reduced surface pressure. This paper investigates the effect of salt concentration on reduced viscosity for different types of polymers used in fracturing fluids.
Different polymers, such as guar, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), carboxymethyl cellulose (CMC) and other biopolymers, are used for preparation of fracturing fluids. Aqueous solutions of these polymers become viscous gel on hydration. KCl salts at different concentrations were mixed with the different polymer gels at room temperature and the viscosity change was observed at a shear rate of 511sec-1. The effect of salt on the hydration rate was also observed at room temperature for the different polymers. A hydration time of up to 60 min was maintained. Plots with different polymers were compared at fixed salt concentrations to identify which polymers experienced more severe effects. It was observed that the CMC category fluids experienced a high reduction to viscosity with the salt content than other fluids. A chemical explanation is given to understand salt effects on different polymer structures.
Many offshore wells use seawater for preparation of fracturing fluids, which is known to contain high salt concentrations. Even drilling fluids use different polymers at various salt concentrations to increase cutting stability as well as mud weight. Formation water can also contain high salt content. When drilling or stimulation fluids mix with formation brine, a high reduction to viscosity can occur, resulting in poor proppant or cuttings transport. This study should aid the decision-making process when choosing polymers and adjusting viscosities considering salt effects.
Liquid-Rich Shale Versus Conventional Depletion Performance
Authors: Lei Guowen , Cheng Nan 
Published: June 2014

Abstract
This paper evaluates fundamental differences in depletion performance of wells producing from ultra-low permeability1 ("shale") reservoirs and wells producing from conventional reservoirs, with the ultimate goal of defining what differentiates "conventional" from "shale" performance. It attempts to answer the question – what permeability range defines "ultra-low" depletion performance and what permeability range defines "conventional" depletion performance – with the intermediate permeability range being a transition from ultra-low to conventional behavior. We "map" the transition from conventional depletion performance to "shale" depletion performance in terms of formation permeability.
In this study we compare depletion performance for reservoir permeabilities ranging from 10 nD to 100 md, with PVT, relative permeability functions, and other rock properties being the same for all simulation cases. Four reservoir fluid systems, ranging from rich gas condensate, near-critical oil to light oil, were used in this study. A one-section drainage area was used even though we are aware that shale resources are often developed with smaller well spacing (typically 80- or 160-acre strips, ~ one mile long).
Depletion performance of conventional gas condensate and oil reservoirs - where oil recovery and producing gas-oil ratio (GOR) are independent of permeability and flowing BHP, is valid for k &gt; 0.1 md. At permeability levels of ~ 0.001 md (1000 nD) or less, the depletion performance of shale and ultra-tight reservoirs is characterized by that producing GOR is a strong function of flowing bottomhole pressure (BHP) and degree of undersaturation (Whitson and Sunjerga, 2012).
Our results from this study show that conventional reservoir performance, depending somewhat on the reservoir fluid system, is observed for k &gt; 0.5 md, while ultra-tight "shale" performance is found for k &lt; 1000 nD (0.001 md), with a gradual transition between these permeability values and shale-like depletion performance appearing already at 0.01md.
Unconventional Gas Water Management: What can be applied from Decades of Experience with Conventional Oil Produced Water Management?
Authors: Evans Robin 
Published: June 2014

Abstract
Shale gas wells can each require between 8,000 m3 and 16,000 m3 of frac water, with up to 25% of that water being returned to the surface during production. Effective asset life cycle water management is key to the technical and economic success of both unconventional gas and conventional oil developments. Unconventional gas resource development in densely populated Europe presents different frac water management challenges to those in sparsely populated areas of the USA.
How can decades of worldwide experience of onshore conventional oil produced water management be applied to improve water management for unconventional gas wells in the areas of: Sourcing frac water suppliesObtaining permits for water abstraction and disposalResolving stake holder environmental concernsInvestigating frac water related formation damageUnderstanding returned frac water compositionTreating and recycling frac waterMinimizing frac water requirements
Onshore water management for unconventional gas and conventional oil production are compared and contrasted with the objective of optimizing frac water life cycle management for unconventional gas resources in Europe.
Are Egos A Main Obstacle To Intelligent Energy Implementation - And Can We Get Around It?
Authors: Jeffery Karl 
Published: June 2014

Abstract
Most of the information in this paper is wrong.
I don’t plan to waste your time - I believe that I have useful ideas here which could make a big contribution to offshore safety.
But when the CEO of a Norwegian oilfield services company once said to me last year that ‘most people are wrong most of the time' – I thought, well he’s right in the sense that I can’t think of anyone who is right most of the time - and so that probably goes for me, too.
And I also want to make the point that, as reflective individuals, we do have the capacity to train our egos - and if we believe that egos are the source of many obstacles to achieving safety, perhaps we can solve the problem at source.
To start explaining what I mean, I would like to tell you about some talks which were presented at a breakfast forum at Offshore Europe in September 2013, about 2 weeks after the Sumburgh helicopter disaster in Scotland when 4 people lost their lives.
The speakers included Martin Rune Pedersen, MD, Maersk Oil UK; Judith Hackitt CBE, Chair of the UK's Health and Safety Executive; Ian Sharp, Chief Operating Officer, Fairfield Energy.
Mr Pedersen of Maersk explained that every time a new drilling rig is brought to Maersk, the company organises two day workshops with with the drilling company staff, including with team building exercises and technical discussions. Maersk values ‘humbleness’, which it says is "about listening and learning and giving space to others." It also values what it calls ‘uprightness’ – where people stick to their word.
Judith Hackitt advocated a mindset of ‘constant unease’, which "means never thinking the problem is fixed," she said. "Constant unease means never being complacent, being prepared to ask hard questions, and not seeking reassurance from what you know is right."
Meanwhile Ian Sharp, Chief Operating Officer, Fairfield Energy, presented a result of a survey into worker engagement in the North Sea -which showed expected results on first glance, but when you look at it more deeply some questions emerge- for example, why do site leaders feel less personally engaged in the site’s safety culture than workers do?
I am trying to pull out a common thread between all of these points - that all speakers were actually focussing on ego - a main threat to safety - and how to stop it causing problems and help us work more intelligently.
The ego which tells us that everything is fine when it isn’t, the ego which stops us questioning too hard, and the ego which arises in difficult personal discussions when we get defensive talking to people we don’t know very well.
Reducing Unplanned Loss Through Multifield Operations
Authors: Kjellsen Kristine 
Published: June 2014

Abstract
Unplanned loss is reduced on the Norwegian continental shelf (NCS) through using Multifield Operations. Multifield Operations entail an overall responsibility for maintaining the integrity of certain equipment through condition and project based maintenance. Tasks, responsibility and professional resources are organized in one unit for multiple installations. This allows for synergies and a unique experience transfer and establishment of best practice. Engineers, executing personnel, planners, condition monitoring, and follow up is gathered in one unit.
Through monitoring, they detect negative trends and errors in an early phase and maintenance carried out with resources that hold operational expertise in the certain discipline in a project based model. Work is planned and implemented in close collaboration with the installations, operations groups, other internal specialist groups and vendors in a proactive, planned and controlled manner. They manage both planned and unplanned work on the systems and equipment in a standardized way.
Most of the pre- and post-operational work is done onshore. Planning is essential to managing resources and prioritizing between tasks based on HSE and production criticality. Quality assurance and risk management is integrated in the planning process.
The paper will address how Multifield Operations are managed through principles of collaboration technology and understanding human factors. The paper has been developed through field analyses. The Multifield Operations model has been applied to rotating machinery, fiscal metering, telecommunication as well as safety and automation systems on more than 29 installations. The model is of great use both to other operators as well as a multitude of related stakeholders and disciplines.
Multifield Operations contribute to a substantial reduction in unplanned production loss. The Multifield Operations model allows the company to plan approximately 1000 maintenance and improvement campaigns across 29 installations yearly, 80% as delivered on plan, with a serious incident frequency (SIF) of zero and they receive positive "client" feedback on their customer satisfaction survey. In addition they complete more work with less resources by gathering and using them across installations.
Multifield Operations may be the best sustainable option in a market where resources are getting scarcer and production moves deeper and colder by the year. It requires smarter and increasingly automated ways of operating. Multifield Operations contribution is a holistic approach to condition and project based maintenance.
Optimal Well Work-over Scheduling: Application of Intelligent Well Control Optimisation Technology to Conventional Wells
Authors: Zarei Faraj , Muradov Khafiz , Davies David 
Published: June 2014

Abstract
The installation of intelligent well completions is often justified by the technology’s ability to manage zonal inflow remotely with the consequent reduction in the well intervention frequency. A range of well and field production optimisation techniques that screen all possible zonal flow-management actions have been developed to control and optimise such intelligent wells and fields. This paper sets out to explore whether such techniques can be extended to provide an optimised work-over schedule for an oil field developed with conventional wells.
Published work-over schedule methods typically rely on well screening and ranking algorithms that are based on the current production performance of the well(s) being considered. This approach, which reacts to the current production situation, may lead to sub-optimal solutions due to the omission of work-overs which may not be the highest ranked at the time of implementation, but could prove to be more profitable in the longer term.
This study develops a workflow to design a proactive, work-over optimisation workflow using Genetic Algorithms (GA). It is based on an integrated, economic simulation model of the field which includes both the direct and the indirect costs associated with well interventions. The paper explores whether a "steered" GA created by the addition of screening and advanced sampling methods to a "pure" GA provides sufficient simplification of the problem to make it suitable for routine use in the field. Problem formulation and variable definition is discussed, allowing the inclusion of field knowledge to reduce the search space and steer the optimiser. The advantages of this modified GA are quantified by comparing it with the performance of the "pure" GA optimisation approach to the problem.
A significant added field value was achieved by the "steered" GA when compared with the "pure" GA.