bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well-Based Shale Resource Assessment Using High Resolution Basin and Petroleum Systems Modeling
Authors: Neumaier Martin , Vaslin Antoine , Jacolin Jean-Etienne , Kleine Adrian , Palci Francesco , Fraser Al , Parkin Kate , Wilson Thomas 
Published: February 2017

Abstract
We present a resource assessment from the Upper Bowland Shale, East Midlands, onshore UK, based on coupled petrophysical interpretation and high resolution basin and petroleum systems modeling (BPSM). In most past BPSM studies, the source rock was typically treated as a single formation with bulk properties, and intra-formational heterogeneities within the bulk rock were not taken into account. In the presented study, we have used a high resolution stratigraphy and geochemical data for the definition of intra-shale sweetspots and a quantitative volumetric assessment of oil and gas retained within the shale.
Since a large part of the assumed oil and gas kitchen is relatively flat-lying and the vertical heterogeneity is considered more important than the lateral variations in facies, 1D basin and petroleum systems modeling is performed at a representative well location (Scaftworth B2). Petrophysical logs are computed and calibrated to core and cuttings as applicable and used in the modeling. Integrating a 14 component source rock kinetic, processes such as hydrocarbon generation and adsorption, intra-formational migration and expulsion are simulated at a meter scale.
As a result of the modeling, prospective layers can be identified based on modeled free-phase oil and gas saturation and volume, adsorbed amounts, detailed composition as well as fluid properties (e.g., density, viscosity, and oil GOR and API). Such vertical "sweetspot units" can be used to define the intervals prospective for horizontal drilling and hydraulic fracturing.
The Gas Flow in Micro Fractures of Shale Gas Reservoirs
Authors: Li Yudan , Dong Pingchuan , Li Weiran , Mi Lidong , Yang Shu , Cao Nai , Yi Xiaoyan 
Published: February 2017

Abstract
The object of this paper is calculate the apparent permeability of micro fractures for shale gas reservoirs, and investigate the impacts of stress sensitivity and gas slippage on the permeability of micro fractures at different stage of development. An apparent permeability model of micro fractures has been established based on the fractal theory and microscopic gas flow mechanism. The calculated permeability shows a good agreement with current model results. The sensitivity parameters of the model were quantitatively analyzed. The research results show that: With the development of shale gas, the apparent permeability of micro fractures decreases as the pressure decreases. For stress sensitivity analysis, it shows the apparent permeability decreases by increasing the stress sensitivity factor. In addition, the apparent permeability increases as the slippage coefficient increases. By increasing the maximum aperture, the impact of the stress sensitivity on the apparent permeability increases. The gas slippage is obvious in rough micro fractures.
A Novel and Adaptive Mesh Method for Arbitrary Discrete Fracture Networks DFN Simulations
Authors: Mi Lidong , Jiang Hanqiao , Wang Yuhe , Yan Bicheng 
Published: February 2017

Abstract
The computation mesh is one of the important challenges for the simulation of the discrete fracture networks (DFN). In this work, an efficient mesh method is introduced to tackle this problem.
First, convert the map with complexity fracture network into a numerical image comprised Npix−x × Npix−y pixels. Then, calculate the distance of pixel j (j = 1, …, Npix−x × Npix−y) to all pixels on the ith fracture grid and select the shortest one as the effective distance of pixel j to the ith fracture grid. Next, calculate the effective distance of pixel j to all the fracture grids in the domain and assign the pixel j to the fracture grid with the shortest effective distance. Finally, the volume of coarse matrix block assigned to ith fracture grid is the summation of the volume of all pixels associated with the ith fracture grid. Each coarse matrix block is locally associated with a fracture grid, and it is equivalently discretized to logarithmically refined grid blocks. The orthogonal fractures model is used in our house reservoir simulator (EDFN) to benchmark with CMG, this method provides very consistent results and its accuracy is validated.
The results show that this method is appropriate to be applied in reservoirs with different geometry and arbitrary complex fracture networks.
Innovative PDC Cutter with Elongated Ridge Combines Shear and Crush Action to Improve PDC Bit Performance
Authors: Crane Davon , Zhang Youhe , Douglas Charles , Song Huimin , Gan Xiaoge , Lin Zhijun , Mueller Levi , Skoff Greg , Self Jordan , Krough Bradley 
Published: February 2017

Abstract
Most traditional polycrystalline diamond compact (PDC) cutting elements have a flat polycrystalline diamond table at the end of cylindrically shaped tungsten carbide body. During drilling, the flat diamond table engages the formation and shears the rock layer by layer. A new ridge-shaped diamond cutting element (RDE) has a similar cylindrical tungsten carbide base; however, the diamond table is shaped like a saddle with an elongated ridge running through the center of the diamond table and normal to the cutter axis. The intended cutting portion, the "ridge," engages the formation to fracture and shear the rock at the same time. The design intent was to create a unique cutting element that could combine the crush action of a traditional roller cone insert and the shearing action of a conventional PDC cutter. The new cutting elements were tested in the laboratory against standard flat PDC cutters in a rock-cutting evaluation, and later the new elements were applied to PDC bits and run under real drilling conditions.
The laboratory rock-scrape tests indicated that the new cutting element not only enables the cutter to efficiently shear formation in the same way as a conventional PDC cutter, but also delivers a crushing action similar to a roller cone insert. Preliminary results indicated a reduction of roughly 40% in both cutting force and vertical force on the new ridged diamond element cutters (RDE) over a conventional PDC cutter. Similar findings were also observed during the rock-shearing test on a vertical turret lathe (VTL). Subsequent field tests in multiple areas in North America have produced faster rates of penetration (ROP) in most of the cases. The trials indicate that the new cutting element is efficient at removing rock, and a bit equipped with these elements requires less mechanical specific energy (MSE) during drilling than does a bit with a conventional PDC cutter. In addition, the reduced cutting forces reduces bit torque and thus improves the drilling tools’ life and the bit directional performance. Field data has proven this technology improves drilling performance in terms of ROP and footage over the current PDC bits fitted with traditional flat PDC cutters.
High Density Fluids Customization and Field Application in Khursaniyah Challenging Wells
Authors: Gadalla Ahmed , Pino Rafael , Ezi Peter , Zayer Nadeer , Hudaithi Mohammad , Addagalla Ajay , Kosandar Balraj , Jadhav Prakash , Lawal Ishaq , Imran Aqeel , Hassan Omran 
Published: February 2017

Abstract
Drilling high pressure wells in the Khursaniyah field, Saudi Arabia, has become a challenge due to the high pressure flow from Base Jilh Dolomite formations coupled with loss circulation across the depleted Upper Jilh formations in the 8 3/8" section. The variations in formation pressure across these layers have led to issues like well flowing, losses, and stuck pipe causing considerable nonproductive time.
This paper analyzes the historical problems encountered in the offset wells to identify the critical fluids related issues during drilling of this section: Thermal and pressure stability of fluids additives.Downhole pressure management.Differential sticking or induced losses.Low contamination tolerance to formation fluids influx.Barite sagging.Rheology and free-water management.
This paper also discusses laboratory customization of optimized high-density fluid formulations and field handling guidelines to drill this critical 8 3/8" section and minimize fluid associated risks. The fluid was modeled to have as low a rheology and gelation profile as possible while suspending weight material by understanding the pressure envelope, bore-hole strength, torque, and drag constraints in combination with the fluid rheology and density relationship under the influence of anticipated drilling practices.
The field application on this customized formulation with engineering observance was successful to drill this critical section and the case study for such well is presented in the paper.
Integrating Horizontal Wells in Property Modeling with Kernel Declustering
Authors: Márquez David , Daly Colin , Psaila David , Slettemeas Tormod 
Published: February 2017

Abstract
Horizontal and highly deviated well data that target pay intervals are generally clustered, both in a vertical sense, as they target specific stratigraphic levels, and spatially, as they target reservoir facies or fracture corridors. This means that the well data misrepresent the volume of interest, and the estimated facies and petrophysical property distributions are most likely biased. Nonetheless, to build reliable facies and petrophysical property models for petroleum exploration and production, geostatistical simulation methods require debiased input property distributions that are representative of the entire reservoir of interest. In this paper, we propose a new 3D kernel density based declustering algorithm to mitigate the inherent sampling bias in the input spatial distribution model and efficiently integrate horizontal and highly deviated well data as conditioning data in facies and petrophysical modeling workflows.
Well Integrity Improvement: CCA Preventive Actions in HPHT Offshore Gas Wells in the Arabian Gulf
Authors: Alsubhi A. M. , Abduljabbar A. M. , Agazade K. , Alyami A. S. 
Published: February 2017

Abstract
Well integrity is critical in the petroleum industry, and needs to be maintained throughout the entire well's life cycle. Cement is the main element that provides isolation and protection for the well. To provide an additional protection beside the cement, mechanical isolation packers can be utilized to mitigate the chance of having fluid communication to the surface. Pressure buildup prevention in the casing/casing annulus remains a challenge in High pressure, high temperature (HPHT) offshore gas wells in the Arabian Gulf due to the presence of shallow gas, abnormal pressure formations, and highly fractured loss zones, which makes all cement jobs critical to isolate the well properly.
This paper will discuss the preventive methods put in place to avoid casing-casing annulus (CCA) pressure buildup and sustain well integrity. Cementing strategies and mechanical isolation packers were considered to ensure the presence of competent barriers to prevent fluid bypass to surface. With regard to cement strategies, some methods will be discusses such as use of resin-based cement, which enhance the shear bond and mechanical properties to prevent cement cracking. For the mechanical barriers, conventional staging tools in the 9-5/8-in. production casing will be replaced with high differential pressure liner hanger packers and will be tied and cemented to surface to ensure maximum sustainability. In the future, they will be replaced with HPHT cement staging tools with a packer that is gas-tight to decrease the operating time while having the same reliability. In addition, a lab tested casing joint with elastomers that can swell in any fluid medium are considered to provide isolation in case the casing-cement bond failed at a later stage.
Having a locked potential well due to CCA will increase the operation cost by early workover, in addition to losing the production. Enhancing cement strategies and utilizing mechanical isolation packers will help with preventing pressure build-up in the CCA and maintaining well integrity for the entire well life cycle.
Rock Texture Characterization from Automated Petrographic Analysis
Authors: Hussain Maaruf , Minhas Naeem-Ur-Rehman , Saad Bilal , Nair Asok 
Published: February 2017

Abstract
The recent crash in the oil market has allowed the industry to reduce the pace of evaluation and completion decisions in unconventional reservoirs, and turn to a more science-based decision-making process for project execution. The traditional stimulation design based on the geometric spacing of induced fractures is now gradually changing to geological spacing (i.e., a design based on an understanding of the reservoir geology) to enhance hydraulic fracture stimulation effectiveness for drastically reduced cost. A methodical rock texture characterization of core samples and cuttings can provide powerful information that can be used reliably and cost-effectively to optimize fracture stimulation designs by placing frac stages based on rock characteristics. This paper presents a new method to quantify rock texture based on automated petrographic analysis that uses advanced microscopy image analysis from scanning electron microscopy (SEM) and optical microscopy. A procedure called "quantitative evaluation of minerals using a scanning electron microscope" (QEMSCAN) and optical microscopy analyses were used to image rock samples prepared from cores and cuttings. Rock texture parameters were extracted automatically using new digital data processing techniques. The information from automated petrographic analysis was used to determine the spatial distribution of all components including mineral composition, framework grains, matrix, cement, grain size and shape, pore size and shape, modes of contact between grains and the nature of porosity. The results showed that while mineral composition of rock is important, texture characterization is far more significant to understand rock behavior than has been reported in the industry. Our results demonstrate the importance of quantitative microscopy and how it can provide an understanding of the key relationship between rock texture and rock behavior.
A new method was produced to characterize rock texture quantitatively from advanced image analysis with the aid of an automated petrographic system.
Boosting Production from Low Pressure Wells and Reviving Dead Wells Using Surface Mounted Technology and Avoiding Well Intervention
Authors: Peeran S. , Beg N. , Mei Ken , Anazi Rayid 
Published: February 2017

Abstract
Innovative Surface Jet Pump (Velocity SpoolTM) technology combined with novel compact separation was tested at a remote onshore wellhead location to see if it could increase multi-phase production from low pressure oil wells that were already producing and revive wells that were backed out/not flowing. The technology was mounted on the surface, not downhole and avoided well intervention,
The Surface Jet Pump (SJP) is a passive device which utilises often wasted fluid energy (via choke) from a high pressure (HP) well to reduce the back-pressure of a low pressure (LP) well and boost its’ flow to the production manifold. In multi-phase oil applications where there can be significant amount of gas present, a compact in-line separator (called I-Sep) is installed upstream of the SJP to bulk separate the gas and liquid fluids and allow the liquid motive fluid to be directed to the SJP.
For this trial, one of Caltec's patented SJP multiphase skids was installed at an onshore wellhead location and connected to existing HP and LP wells. Production from both wells was diverted to the SJP to test its effectiveness. The trial tests lasted 3 months.
Results from the first set of tests showed that the SJP boosted production from a multiphase LP well that was already flowing by an additional average of 380 bbls/d with a corresponding wellhead pressure reduction of 45 psi. Results from the second set of tests showed that the SJP revived a dead well that had not been flowing since 2004 and made it flow at an average rate of 1092 bbl/d with a backpressure pressure reduction ranging from 54 to 27 psi. Prior to the trial, several attempts had been made to bring this dead well back into production using other methods but these were not successful. The results showed conclusively that the SJP was very effective in boosting production from LP oil wells. The production gain was achieved by lowering the FHWP of the well and the amount of gain was dependent on the productivity index of the well.
The advantages that the SJP offers over any conventional technologies such as Multi-phase pumps and ESPs are several: it is tolerant to variations in flow conditions, gas volume fractions (GVF) and associated slugging (without affecting performance), it is surface mounted (so well intervention is not required), low cost, easy to deploy, has no moving parts, consumes zero fuel gas/electrical power and uses already available surplus energy.
This paper reports the trial results and discusses the use of Surface Jet Pumps as an alternative to other boosting methods for oil production. The design and operational criteria of the SJP are also highlighted.
High Performance Simulation of Large-Scale Red Sea Ocean Bottom Seismic Data on the Supercomputer Shaheen II
Authors: Tonellot Thierry , Etienne Vincent , Gashawbeza Ewenet , Curiel Emesto Sandoval , Khan Azizur , Feki Saber , Kortas Samuel 
Published: February 2017

Abstract
A combination of both shallow and deepwater, plus islands and coral reefs, are some of the main features contributing to the complexity of subsalt seismic exploration in the Red Sea transition zone. These features often result in degrading effects on seismic images. State-of-the-art ocean bottom acquisition technologies are therefore required to record seismic data with optimal fold and offset, as well as advanced processing and imaging techniques. Numerical simulations of such complex seismic data can help improve acquisition design and also help in customizing, validating and benchmarking the processing and imaging workflows that will be applied on the field data. Subsequently, realistic simulation of wave propagation is a computationally intensive process requiring a realistic model and an efficient 3D wave equation solver. Large-scale computing resources are also required to meet turnaround time compatible with a production time frame.
In this work, we present the numerical simulation of an ocean bottom seismic survey to be acquired in the Red Sea transition zone starting in summer 2016. The survey's acquisition geometry comprises nearly 300,000 unique shot locations and 21,000 unique receiver locations, covering about 760 km2. Using well log measurements and legacy 2D seismic lines in this area, a 3D P-wave velocity model was built, with a maximum depth of 7 km. The model was sampled at 10 m in each direction, resulting in more than 5 billion cells. Wave propagation in this model was performed using a 3D finite difference solver in the time domain based on a staggered grid velocity-pressure formulation of acoustodynamics. To ensure that the resulting data could be generated sufficiently fast, the King Abdullah University of Science and Technology (KAUST) supercomputer Shaheen II Cray XC40 was used. A total of 21,000 three-component (pressure and vertical and horizontal velocity) common receiver gathers with a 50 Hz maximum frequency were computed in less than three days. After careful optimization of the finite difference kernel, each gather was computed at 184 gigaflops, on average. Up to 6,103 nodes could be used during the computation, resulting in a peak computation speed greater than 1.11 petaflops. The synthetic seismic data using the planned survey geometry was available one month before the actual acquisition, allowing for early real scale validation of our processing and imaging workflows. Moreover, the availability of a massive supercomputer such as Shaheen II enables fast reverse time migration (RTM) and full waveform inversion, and therefore, a more accurate velocity model estimation for future work.
Understanding Corrosion in Underbalanced Drilling Operations Key to Success
Authors: Saboor Abdul , Ul haq M. Moawwaz , Matin Yasir , Takla Elie 
Published: February 2017

Abstract
Underbalanced drilling technology is widely used to minimize formation damage in the reservoir section and enhance productivity. It involves drilling with a fluid whose hydrostatic pressure is lower than that of the formation being drilled. As a consequence of this lower hydrostatic there is a continuous flow of hydrocarbons to surface which is handled by separation equipment and exported thru pipelines where they exist or burned at the flare if no transportation infrastructure is located near rig-site.
The injection of nitrogen into drill-pipe to lighten the hydrostatic pressure of the drilling fluid introduces significant challenges with regards to corrosion mitigation planning. A very well developed corrosion mitigation plan often exists for single phase drilling fluid but the introduction of a gaseous phase leads to changes that need to be incorporated to prevent against excessive corrosion.
Problems and complications due to corrosion issues were hindering an underbalance drilling operation's progress. This paper examines how, optimizing the corrosion control techniques leads to improved drilling performance in subsequent bit runs. The willingness by the operator to tweak and improve the chemical concentrations and learn and apply those lessons learned immediately in the field pays immediate dividends.
Enhancing Pressure Transient Analysis through the Application of Deconvolution Methods, Case Study
Authors: Osman Yossra , Retnanto Albertus , Samir Magdy , Fraim Michael 
Published: February 2017

Abstract
Well testing is an integral element in reservoir and fluid characterization. It is a continuously developing discipline and has seen steady progress over the years. Interpretation techniques have evolved significantly over time, starting with straight-line analysis, then onto log-log analysis, followed by log-log derivative analysis and finally onto the newest standing technique today, deconvolution. Shutting in wells in producing fields to carry out pressure transient analysis can prove to be difficult and often expensive. Frequent short shut-ins are normally dictated by operational well requirements, however, these shut-ins are normally not long enough for the classical pressure transient analysis to be conducted. In this paper, we show how this issue can be resolved by applying deconvolution methods to aid us with pressure transient analysis for these short build up durations
Deconvolution is fundamentally a mathematical algorithm used to convert variable rate data to constant rate data. In other words, it can be used to convert data into a single drawdown with a constant rate. This conversion yields to simplified analysis by allowing more of the same data to be analyzed. As a result of this approach, attaining definite conclusions about reservoir properties becomes possible. Prior to this, unclear and uncertain conclusions were often made.
The data presented below was first analyzed using standard transient analysis techniques. This resulted in non-unique solutions. The data was later analyzed using the deconvolution algorithm (von Schroeter 2001). It was found that this analysis, using deconvolution, along with an understanding of the geological setting, managed to produce clear and conclusive results about the reservoir.
In this paper, we demonstrate that for a given production scenario, a dedicated well test may not necessarily be required. Instead, deconvolution can be utilized on short build ups, which are often already conducted for well maintenance, leading to both clearer results and significant cost savings.