bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Inflow Well Tracers for Permanent Reservoir Monitoring in North Amethyst Subsea Tieback ICD wells in Canada
Authors: Montes Andrew , Nyhavn Fridtjof , Oftedal Gaute , Fævelen Erlend , Andresen Christian , Leung Edmund , Wikmark Vidar 
Published: June 2014

AbstractNorth Amethyst is the first subsea tieback field development for Husky Energy’s White Rose project, located off the East Coast of Newfoundland and Labrador, Canada. The geographical location presents some of the harshest weather conditions in the world due to the elevated sea states and ice conditions. The North Amethyst field achieved first oil in 2010 and at the end of December 2011, had three production wells and three water injectors. Further wells are planned as part of the development.To counter imbalance in the horizontal flow profile that can lead to early water or gas breakthrough, the field development strategy employed Inflow Control Device (ICD) technology. The ICD technology application was the first offshore on the East Coast of Canada.A method of proving effective horizontal clean-out and flow distribution for the ICD technology was necessary. However, due to the subsea configuration complexity, semi-submersible rig costs and delays due to unfavorable weather conditions, the prospect of production logging the horizontal wells was deemed a high risk and expensive operation.To overcome these hurdles, unique inflow tracer technology was used in tandem with the ICDs to provide validation of clean-out and horizontal flow distribution. The North Amethyst producers were equipped with unique oil and water soluble tracers placed along the horizontal, embedded in the ICD screens. The tracer technology’s objectives were to monitor the zonal contributions during clean-out and during the production phase. Water tracers were to monitor and identify the location of zonal water breakthrough.Topside fluid samples were analyzed, and tracer concentrations provided the basis for extracting well inflow information. The utilization of inflow tracer systems in collaboration with other reservoir engineering tools has provided validation of horizontal contribution and feedback about individual ICD nozzle placement. This paper will document the design, execution, and analysis of the tracer results in two initial North Amethyst ICD producers.
WellPlanET — Smart & Efficient Drilling Well Program by Saudi Aramco
Authors: Radhwi A. O , Amer M. M. , Idrees H.. , Fakhruddin A.. , Hazzazi M. A. 
Published: June 2014

Abstract
Drilling and Workover activities generate a lot of information that can be further used to improve the optimization of future activities and reduce: costs, drilling time and the time drilling engineers require to prepare a drilling program. To address this concern, Saudi Aramco developed the Well Planning Engineering Integrated Tools (WellPlanET). The well planning process is the most critical activity during drilling and completion. It starts by capturing the requirements from Exploration & Reservoir Engineering, and ends with a drilling program outlining the drilling execution plan. Supplements and revisions of the original plan may occur during the execution. This planning process involves consideration of many data types, including: formation pressures, offset well data, reservoir location, time, cost, etc. Overlooking any single data aspect could lead to severe drilling problems and time losses, especially for an Oil & Gas Operator like Saudi Aramco, where the Drilling & Workover agenda includes a large number of wells, of different types, and the operational involvement of many stakeholders.
For that reason, Saudi Aramco has recently commissioned a new Well Planning Engineering Integrated Tools (WellPlanET) environment as a one box solution for drilling engineers to facilitate, plan, manage and streamline the well design in a simple, yet smart way. This involves a new re-engineering D&WO Planning Systems environment and workflows from desktop- based to a more integrated web-based environment that employs Aramco data repositories (structured, unstructured, file systems, etc.), application portfolio (in-house, vendor, real-time, historical, Drilling, Exploration, PE, etc.) and workflows to deliver users requirements and address the Drilling & Workover strategic goals and plans. It also provides a systematic way of generating, validating, simulating and optimizing the Drilling Program during both pre-drilling, execution and post-drilling phases.
WellPlanET is a comprehensive integrated knowledgebase that ultimately facilitates well planning engineering, and advanced well design optimization. The system automates capturing all Drilling Program planning data (over 14 different data types such as Trajectory, Mud designs, Wellhead designs, etc.) in a structured manner to establish a complete integrated well planning repository to enable many advanced engineering modules such as Prediction, Simulation and Artificial Intelligence analysis features, using historical and planning data with full integration with key industry standards systems such as Geo- Pressure & Geomechanics analysis tools, Drilling Fluids and Well Hydraulics optimization tools, BHA/Wellhead/CrossSection designing tools to optimize the overall drilling program.
This paper shares Saudi Aramco’s experience in building and deploying WellPlanET as a smart and efficient way of generating the drilling well program.
Formation-Resistivity Theory: How Archie Equations, Shaly-Reservoir Models, Conductive Rock-Matrix Model, and Dual-Triple-Porosity Models Are Related
Authors: Iheanacho Philip C. 
Published: June 2014

Summary
The estimation of hydrocarbon pore volume (HCPV) from resistivity logs can be quite troublesome in some complex heterogeneous reservoirs. Most water-saturation/formation-resistivity models that work well for some reservoirs give unreliable results for others. No single model works for all types of reservoir scenarios.
This paper presents the theory of formation resistivity in porous media. The paper develops the theory from the parallel-resistivity model and then extends it for the series-resistivity model.
When applied for clean sand, the theory derives Archie equations from the first principle. The derivations show that both porosity exponent and saturation exponent are of the same origin and should have the same name. A better name for both parameters should be the tortuosity exponent of a component with respect to its fraction in a control volume. It is also advantageous to treat as a single parameter rather than two separate parameters.
In addition, this theory derives new shaly-sand models for estimating HCPV. These new shaly-sand models can be used for different types of shale distribution by adjusting the value of a single parameter in the models. The formation-resistivity theory is also used to derive formation-resistivity models for conductive rock-matrix reservoirs and dual-triple-porosity reservoirs. A new equation for calculating the composite-porosity exponent is also developed.
Field data are used to validate this work. The theory, when applied for each scenario, derives formation-resistivity models for estimating the reliable HCPV of different reservoir scenarios and types. Moreover, the strength of this theory is its ability to generate models that closely resemble models that have proved to work well for the reservoir cases for which they were developed. Although this work does not test the theory for the cases of tight-sand, shale-gas, and other unconventional reservoirs because of the unavailability of such data, the author is of the opinion that the theory can easily be extended for such reservoirs if the necessary data are available.
Modeling of Shale-Erosion Behavior in Aqueous Drilling Fluids
Authors: Maghrabi Shadaab , Kulkarni Dhanashree , Teke Kushabhau , Kulkarni Sandeep D. , Jamison Dale 
Published: June 2014

Abstract
Numerous shale-stability issues can occur while drilling with water-based muds (WBMs), including shale sloughing and cutting disintegration. These issues can be detrimental to the formation and pose difficulties with respect to rheology control, possibly reducing the rate of penetration (ROP). A "shale-erosion test" is a well-known laboratory test used to characterize the erosion of cuttings in WBMs.
This paper documents a mathematical modeling tool known as an artificial neural network (ANN) used to model the erosion behavior of shale cutting in WBM. The ANN model establishes complex relationships between a set of inputs and an output based on computational modeling. For ANN modeling of shale-erosion behavior, the shale mineralogy and fluid composition constitute a set of inputs, while experimentally obtained "% erosion or % recovery" of the cuttings from the shale-erosion test represent the output.
Experimental data for building the ANN model was obtained by performing approximately 150 standard shale-erosion tests using five different shales with varying mineralogy and WBMs with varying salt concentrations/types, shale stabilizers, and mud weights. For every test conducted, the input data (shale and fluid characteristics) and the output data (% recovery) was incorporated into the ANN model. The ANN model was then run to establish relationships between inputs and the output, which exhibited excellent correlation with R2 ≈ 0.85–0.90. The ANN model was successfully validated for an independent set of shale-fluid interactions.
With the novel ANN model in place, erosion behavior of cuttings could be predicted in advance, thereby reducing the number of trials necessary in technical service labs. Mud engineers can use this model on a real-time basis as the shale chemistry varies with the depth of the formation drilling. The model could provide convenient measurement of fluid performance, enabling fluid optimization necessary to obtain desired shale behavior in advance, thereby minimizing drilling risks and costs associated with these oftentimes unpredictable shales.
Optimizing Lateral Lengths in Horizontal Wells for a Heterogeneous Shale Play
Authors: Chorn Larry , Stegent Neil , Yarus Jeffrey 
Published: June 2014

Abstract
A successful evaluation and development program in oil- and gas-bearing shales requires considerable analysis and investment, not to mention optimization to help ensure a profitable outcome. Accelerating optimization, reducing capital expenditures, and improving lifecycle net present value (NPV) for the asset are reasonable goals. Seven shale properties are key drivers to help achieve successful play economics. However, the heterogeneity of shales makes well location selection difficult without appraisal well logs and geostatistical mapping of shale property quality. The analysis method allows operators to quickly high-grade areas within a large, heterogeneous shale play using logging suites from a limited number of wellbores in the play. Further, the methodology has been extended to quantify the play's potential reward versus risk distribution for in-fill drilling investments. This study extends the method to optimizing lateral lengths of horizontal wells. Geostatistics provides a means to determine correlation lengths of aggregate shale properties known to be critical to successful economics. The correlation length is used to determine the appropriate length of the horizontal well lateral, restricting it within the highest rock quality for stimulation effectiveness and production rates. Because optimal lateral lengths can be predicted using this approach, it is now possible to pinpoint the best wellhead location, the best landing point for the horizontal portion of the well, and set the optimal length of the lateral. This reduces the drilling of unproductive lateral lengths and targets stimulations. By shortening the "trial-and-error" evaluation lifecycle stage using this methodology, an operator can develop an asset more quickly and at less cost than with previous approaches.
Imbibition and Water Blockage in Unconventional Reservoirs: Well Management Implications During Flowback and Early Production
Authors: Bertoncello A.. , Wallace J.. , Blyton C.. , Honarpour M.. , Kabir C. S. 
Published: June 2014

Abstract
Driven by field logistics in an unconventional setting, a well may undergo weeks to months of shut-in following hydraulic-fracture stimulation. In unconventional reservoirs, field experiences indicate that such shut-in episodes may improve well productivity significantly while reducing water production. Multiphase flow mechanisms were found to explain this behavior. Aided by laboratory relative-permeability, capillary pressure data, and their dependency to stress in a shale-gas reservoir, the flow-simulation model was able to reproduce the suspected water blocking behavior. Results demonstrate that a well resting period improves early productivity while reducing water production. The results also indicate that minimizing water invasion in the formation is crucial to avoid significant water blockage.
Well Design Evolution Towards the First Commercial Unconventional Gas Flowrate in Europe
Authors: Thwaites Nicholas , James Lynne 
Published: June 2014

Abstract
The demand for indigenous supplies of natural gas in the UK and other countries in Europe has driven operations in the unconventional gas arena since the 1990s. In Coal Bed Methane (CBM) there have been attempts in the UK, Belgium, Germany, France and Poland.
Dart Energy and its heritage company, Composite Energy, have been active in CBM in the UK since 2004, drilling 25 CBM wells in the UK, including 10 appraisal and development wells on the Airth field in central Scotland. A further 4 appraisal wells were drilled by the previous operator of the Airth field in the 1990s.
The local Carboniferous coal geology, as with most European coals of Carboniferous age, is characterised by thin, numerous, low permeability, undulating coal seams. A number of different well designs were tried over the 14 Airth wells to meet the challenges of the local geology: initially vertical fracture stimulated wells; moving to geosteered multi-lateral horizontal wells, either intersecting a vertical well at the end of the horizontal section or as ‘updip’ branches off a motherbore without an intersection and finally multilateral geosteered horizontal wells intersecting a vertical well at the start of the horizontal section.
The evolution in well design incorporated learnings from drilling operations, reservoir geology and production operations for each type of well architecture and advances in drilling technology in other CBM provinces around the world, adapting them to answer the particular subsurface problems encountered in the Airth field. Eventually, through this evolutionary learning process, Dart Energy was able to announce a commercial flowrate of 0.7MMscf/d from Airth 12 in January 2013, a multi-lateral horizontal well with a vertical well intersection at the start of the horizontal section.
This paper describes the journey to that success, charting the evolution of CBM production well design on the Airth field, recognising the geological factors that drive well design, an evolution that can be applied to Carboniferous coal systems with thin, numerous and structurally complex coal seams found in other parts of the UK and Northern Europe.
New Sponge Liner Coring System Records Step-Change Improvement in Core Acquisition and Accurate Fluid Recovery
Authors: Shale Les , Radford Steven , Uhlenberg Thomas , Rylance Jon , Kvinnesland Audun , Rengel Carlos 
Published: June 2014

Abstract
New sponge coring service and technology have been introduced to the oil and gas industry. Admittedly sponge coring has been an industry offering in some form for over twenty years but until now it has been plagued by chronic problems. The objective of sponge coring was to determine separate in-situ oil and water saturations of the formation materials. The problem with conventional coring has always been that the fluids would be expelled and lost from the core by the expanding gas while bringing it to the surface. The long-time solution was to surround the core with a special oil-absorptive (oleophilic) sponge material that would capture the expelled oil and hold it in place for laboratory analysis. The challenge was to fit the sponge tightly enough around the core to prevent fluid migration and mud contamination in the sponge-core clearance annulus, and yet avoid core jamming and sponge damage.
This new, more accurate sponge liner coring service is now in place, showing excellent results. A balance seems to have been achieved between smooth core entry and a properly fitting, pre-saturated sponge with virtually no fluid migration. This new service cuts and provides oil-absorptive sponge-encased 3½-in. diameter core in 30 ft lengths with a maximum downhole temperature and pressure of 195°F (90° C) and 15,000 psi (1,034 bar) respectively. Special vacuum pump service equipment and sealing system are utilized to pre-saturate the sponge liner with brine.
In late 2012 a major operator utilized this new and previously unproven system to core nearly 300 ft of sponge core in New Mexico, USA. The coring program used a special low-invasion coring fluid with a low spurt loss and a staged trip-out-of-the-hole schedule to minimize gas expansion/oil movement. The precision core bit that cut a tight-clearance core provided exceptional results with an average rate of penetration (ROP) of 10.4 ft/hr, with 97% core recovery and observable oil saturation in the sponge, indicating the system worked as designed. This case study will be described in detail within this paper.
How to Cope with some of the Challenges Associated with Laboratory Measurements on Gas Shale Core Samples
Authors: Lalanne B.. , Le-Bihan A.. , Elias R.. , Poyol E.. , Martinez L.. 
Published: June 2014

AbstractRoutine lab characterization of conventional cores is often limited to geology, petrophysics, and mineralogy. With gas shale plays, however, geochemistry and rock-mechanic are key parameters to characterize as well. In this paper, we present several innovative techniques which allow coping with challenges associated with lab characterization on gas shale core samples.Such alternative techniques need addressing the following issues: Complex lab measurements, potentially to the threshold of what routine lab devices can characterize.Potentially high vertical variability of mineralogy and organic content.Two innovative and worldwide unique measurement devices have then been developed in-house: A transient permeameter, the Step-Decay device, capable of measuring permeability down to the nanoDarcy, at different levels of confining stress and connate water content.A high-resolution geochemical core logging tool, the LIPS device (Laser Induced Pyrolysis System), designed to measure the organic matter content on a continuous centimeter scale basis.So as to cope with the variability issue, a comprehensive set of high resolution core logs has been systematically run: CT-scan and spectral GR logs for petrophysics, scratch-test log for rock-mechanic, and LIPS log for organic matter quantification; we combine all these techniques together for a better core characterization.We present the analysis workflow applied to a gas shale case-study, insisting on the challenges we faced and the way we coped with them. Benchmarking with alternative techniques and lab results is presented as well.
Numerical Simulation of Low Permeability Unconventional Gas Reservoirs
Authors: Ding Didier Yu , Farah Nicolas , Bourbiaux Bernard , Wu Yu-Shu , Wang Cong 
Published: June 2014

Abstract
Unconventional gas resources from tight sand and shale gas reservoirs have received great attention in the past decade and become the focus of the petroleum industry as well as energy resources worldwide, because of their large reserves as well as technical advances in developing unconventional resources. Compared to conventional reservoirs, gas production in ultra-low-permeability unconventional reservoirs is driven by highly non-linear flow equations and involves many coexisting processes due to the presence of multi-scale fracture networks, and to the heterogeneous nature of a porous/fractured and stress-sensitive rock. Therefore, quantifying flow in unconventional gas reservoirs remains a significant challenge.
In this paper, we discuss a mathematical model and a numerical approach for simulating the production of unconventional gas reservoirs, in order to assess well performance and understand the critical parameters that affect gas recovery. Specifically, we consider the flow behavior in a stimulated reservoir volume (SRV) including a tight matrix and multi-scale fracture networks, namely primary hydraulic fractures, induced secondary fractures and micro-fractures. The feasibility and the limits in the use of single-porosity or dual-porosity reservoir models to simulate gas flow in such a system are discussed, and a multi-porosity approach is evaluated. The impacts of various physics related to unconventional gas reservoirs, such as adsorption/desorption, Klinkenberg and geomechanical effects, are quantified.
This work helps to improve simulation technologies for low-permeability unconventional gas reservoirs. An appropriate modeling approach actually underlies effective simulation tools for quantitative studies of unconventional reservoir dynamics and performance, taking into account multi-scale fracture impacts on gas production, well and stimulation design, and optimal production schedules in field development.
Origins and Integrated Exploration of Sweet Spots in Carbonate and Shale Oil-Gas Bearing Reservoirs of the Timan-Pechora Basin
Authors: Petukhov A. V. , Kuklin A. I. , Petukhov A. A. , Vasquez Cardenas L. C. , Roschin P. V. 
Published: June 2014

Abstract
Hydrocarbon exploration in carbonate and shale deposits seems to be less efficient than exploration of terrigenous reservoirs in the Timan-Pechora Basin. This disparity is due to a number of factors, chief of which are complexity of geological structure in areas of carbonate and shale reservoirs and complexity and unpredictability of porosity and permeability. Therefore, considerable heterogeneity of carbonate and shale reservoirs reduces efficiency of prospecting, exploration and engineering of oil deposits in carbonate reservoirs.
The study of carbonate and shale reservoirs, which formed in different periods in the Timan-Pechora Basin, has highlighted importance of tectonic fractures in the evolution of complex reservoirs. These fractures are formed during local tectonic folding. The pervasive faults and fractures generated during these folding episodes in carbonate and shale rocks promote active filtration and leaching by surface and subsurface waters, containing corrosive components (CO2, H2S, etc.). Highly permeable fracture zones, which are called sweet spots, affect the processes of hydrocarbon migration and oil-gas accumulation. Exploitation experience at Usinsk, Kharyaga, Upper Vozey and other oil fields has shown, that sweet spots influence processes of oil pool formation. It is necessary to take into consideration such sweet spots when the optimal system of reservoir engineering is chosen. An integrated exploration method has been developed for finding and delineation of sweet spots. This method includes analisys of seismic and gravity exploration data, aero-space photo-interpretation, well logging data, results of core and drilling data interpretation.
The use of integrated exploration is proven to be effective in finding sweet spots in carbonate and shale reservoirs. It has also enabled greater understanding of the complexities, geometry, and tectonic relationships of sweet spots formation.