bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated 3D Static Modeling of a Complex Carbonate Upper Shuaiba Reservoir, Block 9, Oman North
Authors: Al Hadhrami Fahad , Maili Eduard , Al Araimi Ahmed 
Published: November 2018

Abstract
The field was discovered in 1992. It produces oil and associated gas from two reservoir sub units of the Upper Shuaiba USh3F1 and USh3F2, and exhibits both structural and startighraphical traps. The reservoir units are compartmentalized by NW-trending normal faults into five fault blocks within the same field towards the North East. They are vertically separated by non-reservoir low permeability mudstone facies. US3F2 is setting above Orbitolina shale. The objective is to build a new geological model in a very complex carbonate reservoir, to allow for better reservoir development, and adding new field opportunities using state of art seismic data.
Lower unit (US3F2) consists of an aggradational sequence skeletal peloid-foram packstone/wackestone, and in-situ rudist-algal boundstone/packstone build-ups, which is localized to the NE-trending axis of the field. These sequences are deposited in a low to moderate energy environment. US3F2 reaches a maximum thickness of 50 ft in the rudist build-ups, but the width of the rudist-algal boundstone facies parallel to depositional dip (SE) is only 0.5–0.7 km. Cores exhibit abundant secondary porosity with an average of 30% and permeability up to 700 mD suggesting early subaerial exposure and leaching.
Upper unit (US3F1) is either absent or very thin across the crest and thickens to over 20 ft basinward; downdip, it is separated from US3F2 by a shale unit. US3F1 consists of an upward-shallowing deposits of Orbitolina mudstone, reworked stromatoporoid-rudist floatstone, small rudist floatstone, and fine skeletal grain-dominated packstone with rudist fragments.
3D model was generated covering large area of about 15x9km of the field. The new seismic horizon and faults interpretation were used in the 3D structural modeling. Cores descriptions and photos were used to define core facies, depositional environments and vuggy intervals. Rudist buildups direction of progradation was also defined based on BHI.
Reservoir rock Fabric number (RFN) was defined based on Lucia method and populated using veriogram per zone for the vertical wells using moving average method followed by Gaussian Random simulation, co-kriged with the moving average properties as a trend, for both vertical and horizontal wells. Porosity was populated with the same method. Water saturation and permeability were calculated using Lucia height function method.
Understanding of the reservoir heterogeneity, architecture and 3D modeling using RFN based on Lucia method allowed a better distribution of reservoir properties to be used in dynamic simulation for better history match, predict waterflood performance and adding new development areas.
Benchmarking Recovery Factors for Carbonate Reservoirs: Key Challenges and Main Findings from Middle Eastern Fields
Authors: Gomes Jorge , Narayanan Ram , Parra Humberto , Saputelli Luigi , Bansal Yogesh 
Published: November 2018

Abstract
The objective of this paper is to discuss the process of reservoir/field data aggregation, verification and validation process, to extract some key determinant reservoir parameters to be used in recovery factor (RF) benchmarking against global analogs. The subsequent step is to perform the benchmark of the reservoir performance against fields with similar reservoir characteristics and field development plans (FDPs), using digital databases and analytic tools. The use of data mining and analytics is also attempted to estimate RFs for undeveloped reservoirs.
RF improvement is the ultimate goal of any field development project being managed by National Oil Companies (NOC) or International Oil Companies (IOC). The extent to which the recovery of hydrocarbon resources is achieved, depends on our knowledge of the reservoir complexity (rock and fluid system), the field development strategy and the economic parameters. Each reservoir is unique in its characteristics and thus the need for the implementation of an appropriate field development scheme to maximize the recovery. One of the main objectives of this work was to identify a process that can assess the RF from a given reservoir while comparing it against a mature analogue across the globe, and then identify development opportunites that can further improve RF. To do this we need to 1)-classify ADNOC’s reservoirs in a systematic and consistent manner, 2)-extract key determinant parameters that contribute to RF and 3)-compare them with performance of similar fields extracted from worldwide databases. Once this is done and, with the assistance of digital databases and analytical tools, the benchmark can be performed.
This paper addresses all the challenges involved in the database preparation, data verification and validation process and presents a summary of the main findings in establishing the key determinant parameters used for the final reservoir classification (reservoir complexity index), which is used to select similar reservoirs for the recovery factor benchmark process. The paper exhibits also examples of RFs benchmarks for different carbonate reservoir complexities and architectures including but not limited to: 1)-reservoirs in transition zones, 2)-reservoirs affected by karstification and fracturation. 3)-reservoirs formed in complex clinoform (prograding) systems, 4)-reservoirs formed in aggradational layer-cake systems and 5)-reservoirs from sub-tidal sabkha environments with inter-bedded anhydritic layers.
The novelty of this work is the judicious integration of all static and dynamic data, the proper parameterization of key determinant reservoir parameters, statistics extracted from 3D geostatistical models, the use of predictive analytic tools including self-clustering and classification and dimensionality reduction to estimate RFs for undeveloped reservoirs with similar reservoir complexity.
Permian Basin’s Evolution of Hydraulic Fracturing Techniques Over the Last Decade: Vertical to Horizontal Wells
Authors: Uddin Saif , Cox Jim , Uddin Nasir , Uddin Raheel 
Published: November 2018

Abstract
Hydraulic fracturing has evolved at a rapid pace over the last decade, Permian Basin being the center of all the evolution. In 2011, vertical wells were completed on a day-time operations model with 10 to 13 different frac stages with different volumes of proppants and complex fluid systems. The same engineering & consulting teams in 2013 were challenged with horizontal wells to be completed using cost effective slickwater designs with high volumes of water and proppant on a 24-hour operations model. Finally, in 2018, Operational excellence with engineering accuracy has been possible due to lot of tweaking. This paper would present the successful completion strategies that have been put together from the lessons learnt over 5000 frac stages done in the field.
The difference between success and failure is often times determined in the way we rig-up even before the well head is open. Customer’s desire in total clean fluid pumped per stage or total proppant placement efficiency or both. Moving between fluids, slick water systems to linear and cross link fluids is very important to our success. Higher rates with slick water frac-jobs giving us high penetration using low viscosity fluids and the "sand banks" formed in the lower parts of the zone are swept using linear or dirty gel sweeps. Towards the end when there is no width available for the fractures we switch to cross-link fluids that provide more near wellbore conductivity with less penetration and, using high viscosity fluids and resulted in a perfect support system. Application of both the frac-theories on real-time changes was possible with the Men & Machine integration in the Permian basin.
The key characteristics of the Hybrid frac-jobs are:Usage of 100 or 40/70 mesh sand helped in fluid loss that also acts as a micro fracture proppant;Spear-heading with 2 batches of acids helped in breaking the zone and cleaning the perforationsDual Slickwater Pads with a pro-slug helped to get the penetration that we needed and also helps in determining the concentrations of the proppant behind the pad. This reduces our chances of screening out.Transition from 30/50 proppant to 20/40 proppant concentration based on the way the zone reacts to the proppant.Use of linear gel spacers allowed for higher sand concentrations in the Slickwater section of the frac-job. This provided us the width necessary.Tail ending with a 20/40 proppant using cross-linked fluids gave us a higher near wellbore conductivity
This paper gives a complete outlook to field application of Hydraulic fracturing and the special use of diverters from the lessons learnt in the Permian basin.
Flow Assurance and Improved Pipeline Efficiency Through Use of Low Surface Roughness Treatment
Authors: Nakatsuka Matthew , Veedu Vinod , Brown Erika , Thapa Sumil , Arumugam Ganesh 
Published: November 2018

Abstract
It is well understood that deposits such as corrosion and scale can greatly reduce the flow efficiency and throughput of a transport pipeline system. Regular intervention activities to promote flow assurance such as frequent mechanical pigging, introduction of chemical corrosion inhibitors, and introduction of drag reducing agents all require consistent operational expense, or significant pipeline downtime. Use of interior pipeline coatings and liners are potential long-term solutions which would represent a way to provide long-term refurbishment benefits.
This work describes a novel material designed to interact specifically with highly corroded and weathered pipe, enabling in-place application and refurbishment. The material is applied extremely thinly on the pipeline interior, such that it might be considered a surface treatment, yet it is designed for permanence and for strong adhesion to even severely corroded surfaces. This water-and-oil compatible, chemically resistant material shows extreme resistance to corrosion, particle abrasion and delamination under operational conditions, and is specifically designed to reduce surface roughness by several orders of magnitude. By reducing surface roughness, losses due to frictional drag can be minimized, together with the chance of forming deposits of iron scale and black powder that can constrict pipeline flow and overall production.
A case study is presented in this work which describes application of the coating to a fluid transport system, including a variety of different "challenge" features including: 90° 1.5D bends, valves, weld seams, flanged connections, and heavily corroded surfaces. The pipeline systems were all treated via an in-situ methodology and evaluated for flow performance both through modeling and experimental observation. The study of the practical effects of utilizing a low surface energy, low surface roughness coating that can be effectively applied to severely corroded pipelines with a minimum of surface preparation demonstrates how new material breakthroughs can allow for revitalization of previously mature intervention techniques.
Newly Designed Flow Activated Pulsation Tool for Coiled Tubing Deployed Matrix Acidizing Stimulation Applications in Extended Reach Carbonate Reservoirs
Authors: Saiood Hussain , Duthie Laurie , Shaheen Saud , Albaqshi Ahmed , Ali Moumien 
Published: November 2018

Abstract
Matrix acid stimulation throughout a well’s life cycle is a common technique applied to wells with impaired productivity. Coiled tubing is often chosen as the conveyance means for delivering the acid treatment in horizontal wells to the damaged zones and in applying effective chemical divergent for highly permeable zones. Due to the nature of helical buckling, weight stacking, and wellbore geometry, the coiled tubing operation is often limited in its ability to reach total depth (TD).
In short horizontal wells with slight reservoir contact, conventional methods are used to overcome the effect of drag and friction on the CT; such methods include pumping lubricant fluid. In more challenging applications and extended reach wells (ERW’s), a downhole pulsation tool is placed in the bottomhole assembly to add some axial vibration to the string and exert a pulling force to delay the onset of CT helical buckling, which, in turn, increases the reach of the coil. The significant reduction in friction is caused by the Flow Activated Pulsation Tool (FAPT), which allows the CT to increase its coverage and reach the desired target depth.
A new FAPT generation was developed by designing a new valve section to meet the objective of extending the CT reach in highly restricted (2.44") ERW’s. The development of the new valve section was completed after series of testing different valve sections to determine the optimum generated pulses that would increase the overall pull force at the lowest activation flow rate. The newly developed tool offers a stronger and higher performing pulses at lower activation flow rate, allowing it to operate effectively in more challenging ERW’s.
The FAPT development and the results of using the new tool after the first two global trial runs. The two wells were drilled as oil producing horizontal wells with +18,000 feet to TD. The wells were completed as open hole with electric submersible pumps (ESP’s) and a 2.44’’ restriction to allow well intervention. In both runs, the goal was achieved by reaching TD of the openhole section with effective placement of the acid treatments.
Reservoir Simulation of Planar and Non-Planar Fractures in Compositional Two-Phase Flow
Authors: Zidane Ali , Firoozabadi Abbas 
Published: November 2018

Abstract
In this work we present a higher-order numerical model for two-phase compositional flow in fractured media in 2D and in 3D unstructured gridding. Both planar and non-planar fractures are accommodated. All commonly used types of finite elements are covered in our model; in particular, quadrangular and triangular elements in 2D, and hexahedra, prisms and tetrahedra elements in 3D.
The fracture cross-flow equilibrium (FCFE) concept is adopted to model flow in the fractures. The hybridized mixed finite element (MFE) and the higher-order discontinuous Galerkin (DG) method are used to solve for the flow and the transport equations respectively. We have developed a computer-aided-design (CAD) interface connected to the mesh generator. Using this interface with the unstructured tetrahedra we can generate the most complicated fracture shapes. The complexity of fractures that we generate/simulate is not reported in the past to the best of our knowledge. Our model can simulate all range of fracture permeability values as opposed to other models where low permeable fractures affect the accuracy of the results. Efficiency and accuracy of our model are demonstrated in different examples in 2D and in 3D.
Well Abandonment Solutions Utilizing Bismuth and Thermite
Authors: Carragher Paul , Fulks Jeff 
Published: November 2018

Abstract
Well abandonment is often not thought of as a crucial part of a well’s life. As such, traditional methods of abandoning a well utilizing cement and bridge plugs are still common practice among most operators throughout the world. Although resins have been utilized by some as an alternative, there have not been anymajor new developments in well abandonment materials for nearly 100 years. Although each of these materials have their benefits, there are also limitations to their sealing capabilities. Bridge plugs lack a high expansion ratio required in some wells and rely on elastomers to seal, limiting their ability to seal in damaged tubing or open hole environments. Cement is porous and lacks the ability to block gasses from migrating through it. Resins must be squeezed into an area and can take days to fully cure before a seal is created. This paper will demonstrate a new way to create gas tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed.
Experimental Investigation for the Effect of the Soaking Process on the Regain Permeability After Hydraulic Fracturing in Tight Sandstone and Shale Formations
Authors: Ibrahim Ahmed Farid , Nasr-El-Din Hisham 
Published: November 2018

Abstract
After hydraulically fracturing of shale gas wells, theoretical and experimental studies showed that over 75% of the injected water-based fracture fluids left unrecovered. The trapped water causes permeability damage and productivity impairment. The flowback water also tends to be highly saline, often with TDS contents of as much as 200,000 ppm. This study aims to investigate the effect of well shut-in before flowback stage (the soaking process) on the production of shale and tight sandstone formations.
Shale and sandstone samples were analyzed by X-ray diffraction (XRD). Marcellus shale and Kentucky sandstone cores were used. A modified core flood setup was used to allow porosity measurements by gas expansion method, then pulse decay permeability measurements, and fluid injection during the leak-off process. Nitrogen was used for gas expansion and permeability measurements, while 5 wt% KCl brine was used as representative of leak-off fracturing fluid. The fracturing fluid was injected under a constant pressure gradient (300 in the case of sandstone cores and 1,500 psi in the case of shale cores. After removing the pressure gradient, gas permeability was measured at different soaking times. Computed tomography (CT) was used to scan the cores during the experiment to observe the propagation of fracturing fluid in the core with time.
The results show increasing the regain permeability for sandstone formation was 60% of its initial value directly after the leak-off stage. Then, the regain permeability decreased with increasing the soaking time 38% of its initial value after the core completely invaded with leak-off fluid. The regain permeability was then increased with longer soaking time, as a result of reducing the chocking effect at the core inlet. The propagation rate of water saturation front from CT-scan data decreased with time until reaching the core outlet. The regain permeability on shale cores was 0.14 of its initial value and decreased with soaking time, due to depressed relative permeability curve on this tight pore-space cores.
This study addresses the mechanism of production enhancement or reduction as a result of the soaking process for shale and tight sandstone formations.
Advanced Reinforced Polymer Composite Coatings Revolutionize Corrosion and Wear Protection, and Offer Energy Savings in the Oil and Gas Industry
Authors: Borisov Rumen , Lenehan Paul , Wilson Nick 
Published: November 2018

Abstract
Corrosion, erosion, abrasion and chemical attack of process equipment is a challenge that costs the Oil and gas industry billions per year. Although corrosion/wear/chemical resistant coatings are commonly in use today, enhanced performance requires improved polymer coating materials and coating methods. In the past 20 years coating technology has come far in terms of material development and also in terms of documenting real results. The objective of this paper is to outline the advances and benefits of composite coatings in the oil and gas industry. Facing the challenge to replace expensive materials and technologies with the use of composites delivers to the Oil&Gas industries savings measured by the duration of the protection, saved time for replacement and use of non expensive materials as a substrate. This can be achieved with the use of technology that provides faster and repairable methods of surface treatment and adding the value of improved equipment efficiency.
Effect of Drilling Muds Wall Slip on Reliable Frictional Pressure Loss Estimations in Offshore Drilling
Authors: Numkam Gilles , Akbari Babak 
Published: November 2018

Abstract
The large variations in temperature and pressure conditions that prevail in deepwater operations have drastic effects on the rheology of drilling fluids used. Under such conditions, rheological properties of oil-based drilling fluids could be detrimentally affected. The main reasons of the aforementioned include; the high sensitivity of its organic phase thermal expansion (compression) coefficient and its large viscosity buildup observed with decreasing temperatures. The consequences on drilling hydraulics may include high surge/swab pressures, poor hole cleaning, and the potential of substantial errors in estimated static and equivalent circulation densities; thereby compromising well integrity.
Rheological models used to fit flow curve data of drilling fluids from commonly used field instruments such as the Fann viscometer, do not capture wall slip phenomenon prevalent in highly concentrated suspensions and emulsions as a result of the no-slip boundary condition in their constitutive equations. This could mean significant errors in the derived drilling hydraulic parameters for fluids displaying wall slip.
In this study, water-based (WBM) and oil-based mud (OBM) samples were prepared using different surfactants and their rheology was characterized using a Fann 35 viscometer and MCR 52 rheometer at temperatures ranging from 10 – 75 °C. This was done to highlight differences in frictional pressure loss estimations between a commonly used field instrument and a higher precision rheometer for muds displaying wall slip behavior. The shearing gaps used in the investigation were 1.17 mm for the Fann 35 viscometer and 0.5 – 2.0 mm for the MCR 52.
Wall slip behavior of the mud samples, as well as discontinuous shear thickening due to jamming of dispersed particles, was found to affect agreement in flow curve measurements between both instruments. For set well depth and environmental conditions, lower frictional pressure losses and cuttings transport efficiency were determined for samples showing high levels of wall slip, particularly at high temperatures. The importance of the outcome is underscored by its importance to the successful and timely completion of the wells, as well as total equipment cost.