bluuebunny/crossref_metadata_2025_split huggingface dataset:
Anisotropic Nano-Platelets to Develop Gel Strength at High Temperature in Aqueous Fluids
Authors: Patel Hasmukh , Myratgeldiyev Gadam 
Published: September 2021

Abstract
Aqueous fluids also refer as water-based drilling muds (WBMs) have considered as the most favorable WBMs, owing to their inherent advantages such as economically viability and environmentally benign characteristics. The major problems WBMs encountered is thinning of drilling fluids while drilling under high pressure high temperature. The detrimental rheological properties of WBMs under HPHT result into pipe sticking, low rate of penetration of the drill bit and requirement of high torque for drilling operations. The hydrophilic clays have been employed as viscosifiers in WBMs to maintain the rheological properties, albeit, their viscosifying characteristics have hindered in the presence of ionic species in the aqueous system at high temperature. These shortcomings can be tackled by developing an additive that can exhibit neutral surface changes and ability to undergo gelation at higher temperature. We have developed an additive functionalized with polar groups on anisotropic nano-platelets (LMS) through sol-gel technique. Spectroscopic and crystallographic characterization of LMS have proved the formation of layered structures with covalently linked polar functionalities. The viscoelastic studies were conducted on aqueous dispersion of these nano-platelets at different temperature, which revealed an unprecedented phenomenon -increase in gel strength at higher temperature, a key property required for ideal WBMs. LMS nano-platelet has shown formation of network structure in aqueous medium to boost storage modulus of the fluid. This additive can overcome the demerits associated with natural hydrophilic layered silicates and improve the rheological properties under challenging well conditions.
Use of Downhole Oil-Water Separation System in Horizontal Wells
Authors: Alshmakhy Ahmed , Abdelkerim Ali , Braaten Nils 
Published: September 2021

Abstract
This paper will focus on a new system for separation of water in downhole horizontal wells. The advantages with the system are related to the fact that the water produced from the well is not lifted to the surface, but re-injected into suitable parts of the reservoir, either for pressure support or for diposal.
The method of water separation and re-injection has been evaluated for oil producing fields. The paper presents details of the technical solutions and analysis done related to the financial analysis/payback. The mechanical design is basically a main pipe section of a few meters of length, with a special geometry utilizing gravity-based separation.
A technical and economic analysis of a downhole processing plant (DPP) using a horizontally installed water/oil separator has been performed. The Improved Oil Recovery (IOR)part has been analysed with a relevant flow simulation tool. Based on the given reservoir depth/pressure, flow rate, viscosity/density and water cut, the simulations show that a significant improved production rate/income can be achieved by extracting the produced water downhole and performing re-injection into the producing reservoir to maintain reservoir pressure. In addition, the expected lifetime of the well is increased by several years. The conclusion is that the earlier the separator is installed, the greater the total well income. In addition, details regarding not only multi-lateral wells through level 5 junctions but also production string with separator and valve system has been evaluated and is concluded to be feasible for the well in question
The removal of water downhole has several advantages, for example the removal of the water column up to the surface will reduce the reservoir back pressure and will improve recovery /production rates. In addition, not lifting the water will reduce energy consumption/CO2 footprint, and removal of water will reduce surface processing and possible re-injection and chemical treatment cost. In general, water separation downhole is advantageous, due to the higher pressure.
An Improved Methodology for Gridding Fractured Reservoirs for Simulation
Authors: Gorell Sheldon , Browning Jim , Andrews Justin 
Published: September 2021

Abstract
A significant amount of research for gridding of complex reservoirs, including models with fractures, has focused on use of unstructured grids. While models with unstructured grids can be extremely flexible, they can also be expensive, both in configuring, computationally, and visual display. Even with this focus on unstructured grids, most reservoir simulation models are still built on structured grids. Current methods for creating reservoir simulation models with structured grids often involve defining a base grid upfront and then "somehow" inserting one or more Features of Interest (FOI's) into the model. Applied to fractured horizontal wells with many stages it can be extremely difficult to accurately align wells and completions within a pre-existing simulation grid.
This work describes and demonstrates a methodology to resolve such issues. This approach changes the order of model design and creation steps. This paper describes the process where FOI's are identified, a base grid is designed around the FOI's, then local grid refinements (LGR's) are defined as desired. Applied to a horizontal well with fractures, the well and completion locations are defined before the detailed grid definition is created. This process is illustrated for generalized FOI's, and then applied to fractured horizontal wells. Formulas for creation of models for wells with evenly space homogeneous completions are presented. Numerical testing and analyses are presented that show the impact of the gridding parameters and various design parameters on performance of reservoir simulations.
Oil and Gas Drilling Optimization Technologies Applied Successfully to Unconventional Geothermal Well Drilling
Authors: Sugiura Junichi , Lopez Ramon , Borjas Francisco , Jones Steve , McLennan John , Winkler Duane , Stevenson Matt , Self Jordan 
Published: September 2021

Abstract
Geothermal energy is used in more than 20 countries worldwide and is a clean, reliable, and relatively available energy source. Nevertheless, to make geothermal energy available anywhere in the world, technical and economic challenges need to be addressed. Drilling especially is a technical challenge and comprises a significant part of the geothermal development cost.
An enhanced geothermal system (EGS) is a commercially viable thermal reservoir where two wells are interconnected by some form of hydraulic stimulation. In a commercial setting, fluid is injected into this hot rock and passes between wells through a network of natural and induced fractures to transport heat to the surface system for electricity generation. To construct EGS wells, vertical and directional drilling is necessary with purpose-built drilling and steering equipment. This is an application where oil-and-gas drilling tools and techniques can be applied.
A recent well, 16A(78)-32, drilled as part of the US Department of Energy's (DOE's) Utah Frontier Observatory for Research in Geothermal Energy (FORGE) program, highlights some of the technical challenges, which include drilling an accurate vertical section, a curve section, and a 5300-ft 65° tangent section in a hard granitic formation at temperatures up to 450°F (232°C). Extensive downhole temperature simulations were performed to select fit-for-purpose drilling equipment such as purely mechanical vertical drilling tools, instrumented steerable downhole motors, measurement-while-drilling (MWD) tools, and embedded high-frequency drilling dynamics recorders. Downhole and surface drilling dynamics data were used to fine- tune bit design and motor power section selection and continuously improve the durability of equipment, drilling efficiency, and footage drilled.
Drilling optimization techniques used in oil and gas settings were successfully applied to this well, including analysis of data from drilling dynamics sensors embedded in the steerable motors and vertical drilling tools, surface surveillance of mechanical specific energy (MSE), and adopting a drilling parameter roadmap to improve drilling efficiency to minimize drilling dysfunctions and equipment damages. Through drilling optimization practices, the instrumented steerable motors with proper bit selections were able to drill more than 40 ft/hr on average, doubling the rate of penetration (ROP), footage, and run length experienced in previous granite wells. This paper presents a case study in which cutting-edge oil-and-gas drilling technologies were successfully applied to reduce the geothermal well drilling time by approximately half.
Enhanced Geothermal System Model for Flow through a Stimulated Rock Volume
Authors: Zeinali Leila , Ehlig-Economides Christine , Nikolaou Michael 
Published: September 2021

Abstract
An Enhanced Geothermal System (EGS) uses flow through fractures in an effectively impermeable high-temperature rock formation to provide sustainable and affordable heat extraction that can be employed virtually anywhere with no need for a geothermal reservoir. The problem is that there is no commercial application of this technology. The three-well pattern introduced in this paper employs a multiple transverse fractured horizontal well (MTFHW) drilled and fractured in an effectively impermeable high-temperature formation. Two parallel horizontal wells drilled above and below or on opposing sides of the MTFHW have trajectories that intersect its created fractures. Fluid injected in the MTFHW flows through the fractures and horizontal wells, thus extracting heat from the surrounding high-temperature rock. This study aims to find the most cost-effective well and fracture spacing for this pattern to supply hot fluid to a 20-megawatt power plant.
Analytical and numerical models compare heat transfer behavior for a single fracture unit in an MTFHW that is then replicated along with the horizontal well pattern(s). The Computer Modeling Group (CMG) STARS simulator is used to model the circulation of cold water injected into the center of a radial transverse hydraulic fracture and produced from two horizontal wells. Key factors to the design include formation temperature, the flow rate in fractures, the fractured radius, spacing, heat transfer, and pressure loss along the wells. The Aspen HYSYS software is used to model the geothermal power plant, and heat transfer and pressure loss in wells and fractures.
The comparison between analytical and numerical models showed the simplified analytical model provides overly optimistic results and indicates the need for a numerical model. Sensitivity studies using the numerical model vary the key design factors and reveal how many fractures the plant requires. The economic performance of several scenarios was investigated to minimize well drilling and completion pattern costs.
This study illustrates the viability of applying known and widely used well technologies in an enhanced geothermal system.
The New Flow Control Devices Autonomously Controlling the Performance of Matrix Acid Stimulation Operations in Carbonate Reservoirs
Authors: Moradi Mojtaba , R Konopczynski Michael 
Published: September 2021

Abstract
Matrix acidizing is a common but complex stimulation treatment that could significantly improve production/injection rate, particularly in carbonate reservoirs. However, the desired improvement in all zones of the well by such operation may not be achieved due to existing and/or developing reservoir heterogeneity. This paper describes how a new flow control device (FCD) previously used to control water injection in long horizontal wells can also be used to improve the conformance of acid stimulation in carbonate reservoirs.
Acid stimulation of a carbonate reservoir is a positive feedback process. Acid preferentially takes the least resistant path, an area with higher permeability or low skin. Once acid reacts with the formation, the injectivity in that zone increases, resulting in further preferential injection in the stimulated zone. Over-treating a high permeability zone results in poor distribution of acid to low permeability zones. Mechanical, chemical or foam diversions have been used to improve stimulation conformance along the wellbore, however, they may fail in carbonate reservoirs with natural fractures where fracture injectivity dominates the stimulation process. A new FCD has been developed to autonomously control flow and provide mechanical diversion during matrix stimulation. Once a predefined upper limit flowrate is reached at a zone, the valve autonomously closes. This eliminates the impact of thief zone on acid injection conformance and maintains a prescribed acid distribution. Like other FCDs, this device is installed in several compartments in the wells. The device has two operating conditions, one, as a passive outflow control valve, and two, as a barrier when the flow rate through the valve exceeds a designed limit, analogous to an electrical circuit breaker. Once a zone has been sufficiently stimulated by the acid and the injection rate in that zone exceeds the device trip point, the device in that zone closes and restricts further stimulation. Acid can then flow to and stimulate other zones This process can be repeated later in well life to re-stimulate zones.
This performance enables the operators to minimise the impacts of high permeability zones on the acid conformance and to autonomously react to a dynamic change in reservoirs properties, specifically the growth of wormholes. The device can be installed as part of lower completions in both injection and production wells. It can be retrofitted in existing completions or be used in a retrievable completion.
This technology allows repeat stimulation of carbonate reservoirs, providing mechanical diversion without the need for coiled tubing or other complex intervention. This paper will briefly present an overview of the device performance, flow loop testing and some results from numerical modelling. The paper also discusses the completion design workflow in carbonates reservoirs.
Improving the Local Research Capacity through the Industry-Academia Collaboration in Kazakhstan
Authors: Syzdykov Murat , Dairov Zhassulan , Miskimins Jennifer 
Published: September 2021

Abstract
Kazakhstan has set a lofty goal of becoming one of the world's top 30 developed countries by 2050. This can be accomplished by growing up well-versed, competent, and forward-thinking human capital. We previously discussed curriculum, courses, internships, and student development as part of the World Economic Forum (WEF) pilot project supported by Chevron, Eni, and Shell (Sponsors) to strengthen oil and gas human capital in Kazakhstan (SPE-195903 and SPE-201272). During regular visits, the WEF sponsors and Colorado School of Mines (Mines) could assess the Satbayev University (SU) PE department and underlined the importance of faculty growth. Academic workshops on topics such as course and syllabus design, student assessment, and ABET accreditation standards have been held both offline and online. Meanwhile, to advance the PE program, faculty research capacity must be globally competitive.
To begin, the Kazakhstani government distributed visiting scholarship awards on behalf of the supporting World Bank in 2018. Shell Kazakhstan took the initiative and co-funded two PhD candidates so they could perform their research experiments at Pennsylvania State University (PennState). In addition, Mines has gone above and beyond the WEF scope by offering two fully-funded PhD scholarships to exceptional SU faculty. Through the newly constituted Industry-Advisory Board (IAB), the WEF Sponsors emphasized strong contact with the industry, which assisted in identifying a few research topics. These discussions resulted in formulation of four research proposals that were submitted to the Ministry of Education and Science Grants in 2020 and are being co-funded by Sponsors. This collaboration has yielded the approval of two projects by the State. Finally, under the auspices of the IAB meetings, the PE department has been offered opportunity to collaborate with the national KazMunayGas on the company-related project.
While academic cooperation is well-known, research and its outcomes are even more critical in today's fast-changing environment. Universities must quickly adapt to industry best practices while remaining committed to their global mission of contributing to national growth and human potential. This paper discusses effective approaches for industry-academia collaboration.
Using Managed Pressure Drilling Equipment to Troubleshoot Well Control Issues with Total Lost Circulation and Ballooning on A Semisubmersible Rig
Authors: Dalgit Singh Harpreet Kaur , Ching Shearn Ho , Ta Quoc Bao , Nguyen Van Dien 
Published: September 2021

Abstract
When drilling from a deepwater semisubmersible rig, the operator encountered wells problems, including lost circulation, influxes, and ballooning, in the 14 3/4-in. hole section. Managed Pressure Drilling (MPD) equipment that helped to mitigate these issues specifically, when stripping in the hole with the bottom hole assembly through the Rotating Control Device (RCD) bearing assembly while managing surge and swab pressures, monitoring the well while displacing heavy mud into the open hole, conditioning the contaminated mud, removing gas from the well, and fingerprinting the flow back to verify ballooning against influxes, and finally stripping out of the hole.
The operator experienced a total loss of circulation at the 16-in. liner shoe at 1,633m while drilling the 14 3/4-in. hole section. Several lost-circulation material (LCM) pills of different weights were pumped to cure the losses without success. Then the well was flow-checked, the gain was noted, and the well shut-in. Having the MPD chokes and the Coriolis flowmeter in place made it possible to adjust the surface back pressure (SBP) accordingly within a small operating window. As a result, the operator could achieve the key objectives of stripping the drillstring in the hole, stripping out of the hole, and rolling over to spot 1.88SG heavy mud on the bottom using the pump and pull method. After LCM was pumped and a hesitation squeeze performed, well operations were stabilized, and the casing was run to a 2,111m measured depth.
Advanced flow monitoring enabled the MPD to determine the required SBP for balancing the well. MPD applied 60psi of SBP and noted a gain of 8.3bbl/hr from the flowmeter. Next, MPD applied 65psi SBP and the well was static. Then, MPD applied 70psi SBP, and the well took losses at a rate of 19bbl/hr. MPD allowed to successfully strip the BHA in the hole through the RCD bearing assembly to the shoe. Correct string displacement observed via the MPD Virtual Trip Tank, achieved by adjusting the SBP from 62psi to 125psi. The closed-loop circulating system enabled safely circulating and conditioning contaminated gas-cut mud in the hole back to homogeneous mud. MPD reduced SBP incrementally and fingerprinted flow back at every step to give assurance that well ballooning, and not influxes, caused the flow back. Dynamically adjusting SBP, coupled with advanced monitoring of the returns flow using the Coriolis flowmeter, enabled balancing the well despite the challenges of a mixed mud gradient in the annulus and a narrow operational window.
The MPD riser consisted of an RCD below-tension-ring (BTR)-s, flow spool, and top and bottom crossovers. Rig modifications involved fabricating the fixed piping to allow integrating MPD equipment with the rig system.
A Machine Learning Methodology for Rock-Typing Using Relative Permeability Curves
Authors: Alfonso Carlos Esteban , Fournier Frédérique , Alcobia Victor 
Published: September 2021

Abstract
The determination of the petrophysical rock-types often lacks the inclusion of measured multiphase flow properties as the relative permeability curves. This is either the consequence of a limited number of SCAL relative permeability experiments, or due to the difficulty of linking the relative permeability characteristics to standard rock-types stemming from porosity, permeability and capillary pressure. However, as soon as the number of relative permeability curves is significant, they can be processed under the machine learning methodology stated by this paper. The process leads to an automatic definition of relative permeability based rock-types, from a precise and objective characterization of the curve shapes, which would not be achieved with a manual process. It improves the characterization of petrophysical rock-types, prior to their use in static and dynamic modeling.
The machine learning approach analyzes the shapes of curves for their automatic classification. It develops a pattern recognition process combining the use of principal component analysis with a non-supervised clustering scheme. Before this, the set of relative permeability curves are pre-processed (normalization with the integration of irreducible water and residual oil saturations for the SCAL relative permeability samples from an imbibition experiment) and integrated under fractional flow curves. Fractional flow curves proved to be an effective way to unify the relative permeability of the two fluid phases, in a unique curve that characterizes the specific poral efficiency displacement of this rock sample.
The methodology has been tested in a real data set from a carbonate reservoir having a significant number of relative permeability curves available for the study, in addition to capillary pressure, porosity and permeability data. The results evidenced the successful grouping of the relative permeability samples, according to their fractional flow curves, which allowed the classification of the rocks from poor to best displacement efficiency. This demonstrates the feasibility of the machine learning process for defining automatically rock-types from relative permeability data. The fractional flow rock-types were compared to rock-types obtained from capillary pressure analysis. The results indicated a lack of correspondence between the two series of rock-types, which testifies the additional information brought by the relative permeability data in a rock-typing study. Our results also expose the importance of having good quality SCAL experiments, with an accurate characterization of the saturation end-points, which are used for the normalization of the curves, and a consistent sampling for both capillary pressure and relative permeability measurements.