bluuebunny/crossref_metadata_2025 huggingface dataset:
Advanced Reservoir Simulation: A Novel Robust Modelling of Nanoparticles for Improved Oil Recovery
Authors: Hendraningrat Luky , Majidaie Saeed , Ketchut Nor Idah , Skoreyko Fraser , MousaviMirkalaei Seyed Mousa
Published: September 2021

The potential of nanoparticles, which are classified as advanced fluid material, have been unlocked for improved oil recovery in recent years such as nanoparticles-assisted waterflood process. However, there is no existing commercial reservoir simulation software that could properly model phase behaviour and transport phenomena of nanoparticles. This paper focuses on the development of a novel robust advanced simulation algorithms for nanoparticles that incorporate all the main mechanisms that have been observed for interpreting and predicting performance.

The general algorithms were developed by incorporating important physico-chemical interactions that exist across nanoparticles along with the porous media and fluid: phase behaviour and flow characteristic of nanoparticles that includes aggregation, splitting and solid phase deposition. A new reaction stoichiometry was introduced to capture the aggregation process. The new algorithm was also incorporated to describe disproportionate permeability alteration and adsorption of nanoparticles, aqueous phase viscosities effect, interfacial tension reduction, and rock wettability alteration. Then, the model was tested and duly validated using several previously published experimental datasets that involved various types of nanoparticles, different chemical additives, hardness of water, wide range of water salinity and rock permeability and oil viscosity from ambient to reservoir temperature.

A novel advanced simulation tool has successfully been developed to model advanced fluid material, particularly nanoparticles for improved/enhanced oil recovery. The main scripting of physics and mechanisms of nanoparticle injection are accomplished in the model and have acceptable match with various type of nanoparticles, concentration, initial wettability, solvent, stabilizer, water hardness and temperature. Reasonable matching for all experimental published data were achieved for pressure and production data. Critical parameters have been observed and should be considered as important input for laboratory experimental design. Sensitivity studies have been conducted on critical parameters and reported in the paper as the most sensitive for obtaining the matches of both pressure and production data.

Observed matching parameters could be used as benchmarks for training and data validation. Prior to using in a 3D field-scale prediction in Malaysian oilfields, upscaling workflows must be established with critical parameters. For instance, some reaction rates at field-scale can be assumed to be instantaneous since the time scale for field-scale models is much larger than these reaction rates in the laboratory.
Quantitative Evaluation of Water Flooding in a Low Resistivity Heavy Oil Reservoir with NMR and Conventional Logs
Authors: Shi Xinlei , Zhang Jiansheng , Lu Yunlong , Han Zhilei , He Yifan
Published: September 2021

The classification of water flooding severity is crucial for planning reservoir production and improving the recovery ratio. In this paper, we study a siliciclastic heavy oil reservoir in Bohai Bay, with resistivity reading close to, or even lower than the wet zone (3~5Ω.m). In this environment, computing original reservoir Sw using Traditional hydrocarbon saturation equation is challenging. As a result, the displacement efficiency of a water drive cannot be accurately determined.

In order to properly evaluate displacement efficiency, we must estimate initial reservoir Sw (Swirr) and the modern day Sw. Sw can typically be estimated from NMR data with a proper T2 time cutoff. However, in heavy oil reservoirs, the relaxation times of oil and capillary bound water overlap, leading to an over-estimation of Sw. We propose to compensate for the heavy oil effect by adjusting the cutoff until NMR Sw matches the Sw from core Mercury Injection for Capillary Pressure (MICP). As oilfield development proceeds, water displaces some oil in the pore space. Since the injected water has higher salinity than reservoir water, formation resistivity (Rw) becomes lower. Based on the material balance theory, the variable multiple water injection material balance equation is established, and the equation set is established by combining the material balance equation with the Simandoux equation and the calculation formula of mixed water resistivity (Rwz). According to the rock electricity experiment under different salinity, the dynamic rock electricity parameters are used in the Simandoux equation, and the mixed water resistivity and modern day Sw after water flooding are solved iteratively under the original SW constraint. The displacement efficiency is calculated as the difference between Sw and modern day Sw.

The proposed method was applied to 10 wells and improved the Sw accuracy by 5%-15%. The continuous solution Rw from our method matches Rw measured in the lab. The calculated displacement efficiency is compared with actual production history and the accuracy improved from 68% to 80%.
How to Block the Water Channels by High-Density Polyethylene Particles Supersaturated Filling Out-of-Screen and Inflow Control Device in Heterogeneous Sandstone Reservoir
Authors: Shi Hongfu , Xu Zhongbo , Cai Hui , Zhang Wenjun , Li Yunting
Published: September 2021

At present, the Bohai Oilfield has entered the late stage of high water cut, with a high degree of flooding and an average water cut of more than 80%. Horizontal wells were widely used in tapping the potentials of high water-cut oilfields with avoiding local water flooding, accurately develop enrichment of remaining oil, and improving initial productivity. Until 2020, there are more than 1,200 horizontal wells in the Bohai Oilfield, with daily production accounting for more than 40% of the entire oilfield. However, mainly continental deposits, strong heterogeneity, heavy oil, relatively large mobility ratio, long-term water flooding, and large liquid production have resulted in the obvious dominant channels in the formation, intensified ineffective water circulation, and low oil recovery. The application of horizontal wells faces huge challenges due to the serious water flooding and the prevalence of thief zones.

Inflow Control Device (ICD) is becoming more and more prevalent in bottom water reservoirs as it can delay the water breakthrough and significantly improve the economic benefit of a project by producing more oil and less water. The strong microscopic heterogeneity along the horizontal water channeling outside the screen or water channeling along the annulus between the screen and ICD tubular is responsible for the short term even ineffective effect of conventional ICD. Based on the review of the conventional ICD application in the Q oilfield, a workflow is present to design and optimize hybrid ICD to increase the success probability of the validity period of water control.
Risk Reduction on the Western Siberia Prospect Using Stochastic Seismic Inversion and Geological Constraints
Authors: Khitrenko Anton , Fedotkin Sergey , Nazaryan Ayk , Zhigulskiy Svetlana , Emelyanov Pavel
Published: September 2021

Seismic data is a main source of information for lateral forecast of lithofacies. No one can deny that seismic data is a useful method to determinate structure of prospects. However, we have to accept to urgent need to implement steps that will make possible to predict distribution of lithofacies. In exploration, the prediction of lithology and fluid properties is a main goal. Popularity and comparative simplicity of inversion, made seismic inversion popular for reservoir characterization. Despite the benefits of method, inability to estimate uncertainty of models, stochastic seismic inversion was inveted. A stochastic seismic inversion combine relationship with varying lithofacies parameters and elastic properties using uncertainty of each data. Additional modification of stochastic seismic inversion is geological constraints allows to exclude not appropriate realization and obtain correct probability model of lithofacies.

Comparison of approaches and results on a real set provided from the Tyumen formation in Western Siberia allows to estimate advantages and disadvantages of modification stochastic Seismic inversion.
Anisotropic Nano-Platelets to Develop Gel Strength at High Temperature in Aqueous Fluids
Authors: Patel Hasmukh , Myratgeldiyev Gadam
Published: September 2021

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

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

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

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

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

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

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

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

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.
Solvent-Loaded Microspheres for Permeability Enhancement in Heavy Crude Oil Reservoirs
Authors: Yegin Cengiz , Temizel Cenk , Akbulut Mustafa
Published: September 2021

With their abundancy and high-quality, it is predicted that fossil fuels will remain as the main resource that will meet the global energy demand in the several upcoming decades. Developments in hydrocarbon recovery technologies, both from conventional and unconventional reservoirs, have substantially contributed to the overall production levels in recent years. However, recovery factors obtained by using the current methods are still considered to be insufficient, and the companies have been looking for new materials and methods to enhance the efficiency and amount of recovery.

One of the major issues related to low recovery factors is low permeability of reservoirs. Existence of blockages in pore throats and high level of heterogeneity lowers the mobility of hydrocarbons. In this study, we discuss development of an innovative material to be used as an additive in reservoir injection fluids to remove pore blockages in order to enhance the recovery levels.

This additive material is made of pressure-sensitive microspheres loaded with solvents, which can (i) easily disperse in the injection fluid and travel to the low-permeability regions, (ii) break under pressure and confinement to release solvents, and (iii) remove blockages by targeting surroundings, especially asphalt-based particles and grains. This approach relies on the breakage of microcapsules in the confined region and release of the solvents to target blockages in porous media. In other words, the developed microspheres improve permeability of reservoirs as a result of pressure- and confinement-dependent breakage and release of solvents. Preparation of these microspheres was achieved by the encapsulation of solvent (toluene) emulsions in silica-based solid shells. Structure and stability of the solvent-loaded microspheres were examined using a variety of analytical techniques including UV-vis spectroscopy, optical microscopy, scanning electron microscope (SEM) and dynamic light scattering (DLS). It was found that the prepared microspheres possessed smooth surfaces with shell thicknesses in the range of 100-150 nm. Additionally, sand column tests were performed to evaluate the recovery potential of injection fluids in presence of solvent-loaded microspheres. It was shown that the use of solvent encapsulated in microspheres doubled the recovery factor of heavy oil compared to that of free solvent dispersed in the injection fluid. Such enhancement in the recovery factor was related to the release of solvents in localized areas, i.e., confined regions, as a consequence of breakage of microspheres. This novel approach of delivering solvents to low-permeability regions provides a significant driving force to eliminate pore blockages to facilitate mobilization of hydrocarbons trapped in confined spaces.
Multizone Openhole Gravel Packing with Enhanced Shunt Screens and Zonal Isolation in High-Rate Gas Wells
Authors: Markham Ross , Michell Alastair , Noblett David , McCartan Bernard , Sugiarto Septiandi , Huynh Tony Trung , Kumar Amrendra , Gadiyar Bala , Gupta Susheel , Rudic Aleksandar
Published: September 2021

A reliable single-trip openhole multizone completion can significantly lower capital expenditure (CAPEX) by reducing rig time and well count. Recent improvements in openhole packers and enhanced shunt screen technology have enabled multizone openhole gravel pack completions with complete zonal isolation. A multizone openhole gravel-pack completion was installed in the Julimar Field with an enhanced shunt screen system, shunted mechnaical packers (SMP) and shunt tube isolation valves (STIV), to provide improved operating pressure envelope and erosion tolerance. Well design was tailored to derisk the installation and optimize performance of the multizone completion. Extensive reliability testing was undertaken on all new technology for this project.

Completions were installed as planned, and the main objectives of sand control integrity, production attainment, and complete zonal isolation with selective production were validated through post-job gravel-pack analysis and subsequent well unloading. The successful implementation of these technologies significantly reduced project CAPEX and enabled access to reserves that would otherwise have been uneconomical to recover.

This paper discusses design, execution, and evaluation of the multizone openhole gravel pack (OHGP) completions installed in the Julimar Field. This includes methodology followed for multizone completion selection, development of a new high-temperature formate-based viscous gravel-pack carrier fluid, detailed completion equipment qualification tests, post-job gravel-pack evaluation, and initial well performance from well unload. It is the industry's first field case study of enhanced shunt screens with novel shunt tube isolation valves and high-temperature xanthan-based gravel-pack carrier fluid.
New Wellbore Proppant Transport Model Improves Prediction of Multiple Fracture Propagation in Horizontal Wells
Authors: Sinkov Konstantin , Shrivastava Kaustubh , Kresse Olga , Abbas Safdar , Knyazev Egor , Spesivtsev Pavel
Published: September 2021

Completion optimization in hydraulic fracturing operations requires understanding the interaction between simultaneously propagating multiple fractures and the distribution of fluid and proppant among the fractures during the treatment. Diagnostic methods often reveal that propagation of fractures within single stage is quite uneven. Nonuniform growth is caused by a complex interplay between fracture mechanics and hydrodynamics of proppant transport in wellbore and perforations. A recently developed numerical model simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling, including bed formation, fluid rheology, perforation erosion, rate- and concentration-dependent pressure drop, and variable efficiency of proppant transport through perforations. The model is numerically coupled to an advanced fracture simulator that models fracture growth, fluid flow, proppant transport inside complex hydraulic fracture networks, and mechanical interaction between adjacent hydraulic fractures. The coupled model enables comprehensive simulations and captures the mutual influence of the transport of proppant in the wellbore and the propagation of fractures. Integration of the model into the proprietary stimulation-to-production workflow allows leveraging available data and applying the model to optimization of completion strategy and design. The coupled model is shown to agree with the results of analytical models in special limiting cases. It also qualitatively reproduces patterns of proppant distribution observed in the field with the help of various fracturing monitoring techniques. Parametric studies demonstrate that the combined influence of proppant inertia causing higher concentration of proppant in toe clusters, erosion of perforations, and transient pressure response of fractures leads to the nonuniform and transient distribution of the injection rate among fractures. Simulation results show that the nonuniform proppant transport efficiency induced by proppant inertia and broad proppant size distribution can be superposed on the stress shadow effect and lead to the uneven growth of fractures within a stage. The integrated model is efficient and allows routine optimization of fracturing treatment designs. An example of the design optimization illustrating wellbore proppant transport effects on treatment dynamics and showing the value of the coupled wellbore-fractures simulations is also provided.
Development and Evaluation of Ultra-High Temperature Resistant Preformed Particle Gels for Conformance Control in North Sea Reservoirs
Authors: Schuman Thomas , Salunkhe Buddhabhushan , Al Brahim Ali , Bai Baojun
Published: September 2021

Preformed particle gels (PPGs), a type of hydrogel, have been widely applied to control the conformance of reservoirs owing to their robust gel chemistries. Traditional PPGs are polyacrylamide-based hydrogel compositions which can withstand neither higher temperatures nor high salinity conditions. There are many deep oilfield reservoirs worldwide which demand PPG products with a long term hydrolytic and thermal stability at the temperatures of higher than 120 °C. Current PPGs neither remain hydrated nor retain polymer integrity at these temperatures. A unique high temperature-resistant hydrogel composition (HT-PPG) was developed with exceptional thermal stability for greater than 18 months in North Sea formation temperature (~130 °C) and formation water environments. HT-PPG described herein can swell up to 30 times its initial volume in brines of different salinity for North Sea. The effects of salinity and temperature on swelling, swelling rate, and rheological behavior was studied. These HT-PPGs exhibit excellent strength with storage modulus (G’) of over 3,000 Pa at the swelling ratio of 10. Thermostability evaluations were performed in North Sea brines with variable salinity at temperatures of 130 °C and 150 °C and found to be stable for 18 months with no loss of molecular integrity at the higher temperature. Laboratory core flooding tests were conducted to test its plugging efficiency to fracture. HT-PPGs showed good plugging efficiency by reducing the permeability of open fracture and did not wash out during waterflooding. Overall, HT-PPG is a novel product with excellent hydrothermal stability that make it an ideal candidate for conformance problems associated with reservoirs of high temperature and salinity conditions.
Innovative Technologies Deliver Operational Objectives in a Multi-Well, Ultra-Deepwater, Managed Pressure Drilling and Completions Campaign
Authors: Fisher Andrew , Kaura Jiten , Kratzer Matthew , Oyler Ken , Reutzel Ron , Teoh Michael , Thomassen Scott , Vives Javier
Published: September 2021

The deepwater development field in the western Gulf of Mexico (GoM) presents an array of complex challenges for ultra-deepwater drilling operations. The four well campaign was particularly challenging due to extreme water depths, remote location, well trajectory and a narrow pressure environment, 350-100 kpa (50-150 psi), for extended reservoir laterals. The authors highlight the use of innovative technology employed to drill and complete wells in the western GoM deployment, coupled with the first-ever use of controlled mud level (CML), managed pressure drilling technology in the Gulf of Mexico. The approach of selecting the fluid systems to achieve the objectives and the use of hydraulics modeling software with CML modeling capability in the design, planning and execution phases of the project allowed for fluid design optimization. The results were a successful drilling and completion campaign managing multiple fluids systems and operations on an ultra-deepwater, dual-activity drill ship in water depths more than 8,500 ft (2,591 m). The authors discuss the initial use of a low equivalent circulating density (ECD), flat-rheology synthetic based fluid (SBF) designed for narrow margin drilling applications and the transition to the deployment of a newly developed high-performance water-based mud (HPWBM) optimizing the operations to drill the intermediate intervals for final two wells. The authors also will discuss use of the reservoir drill-in fluid (RDF) and solids-free screen running fluids (SF-SRF), designed specifically for use in these open holes, gravel pack completions at hole angles upwards of 90°. Operational efficiencies derived from use of these fluids include ECD management, hole cleaning, directional performance, reduction in downhole losses, and the elimination of non-productive time (NPT) in a narrow margin environment with no loss of rate of penetration (ROP). Additional efficiencies include the seamless transition from derived from use of water-based fluids for drilling and completion phases. Use of the CML technology allowed for precise control of the hydrostatic pressure on wells that previously would not have been technically feasible to drill or complete. The novel use of the newly developed HPWBM on this campaign enabled reduced health, safety and environmental (HSE) exposure impact, increased tank and rig cleaning efficiency, and the elimination of a wellbore cleanout run since the entire well was drilled with only water-based fluids. The fluids were successfully employed in the four wells drilled and completed in a managed pressure environment utilizing CML technology.
A New Experimental Method for Measuring Improved Oil Recovery in Shales
Authors: Quintanilla Zach , Russell Rod , Sharma Mukul
Published: September 2021

Improved Oil Recovery, IOR, in shales is a topic of growing interest due to the low oil recovery observed in shales. Evaluating different IOR chemicals at the lab scale has proved difficult and time consuming due to their ultra-low permeability and low porosity. Conventional core procedures (such as core floods) are often not practical to use with such samples since they take too long.

In this study, we introduce a new laboratory method for measuring the oil recovery in a huff-and-puff IOR process in shales. In huff-and-puff IOR, a treatment additive and a gas are typically injected in combination into the reservoir. Oil production is initiated after a shut-in period. Our experimental protocol starts by saturating preserved shales with oil by exposing them to the reservoir oil under pressure for an extended time. To speed up this process the preserved shale sample is crushed and sieved to 5-10 mesh. The pressure vessels are then loaded with these oil-saturated 5-10 mesh shale particles and the desired IOR fluid is injected into the pressure vessel. The vessel is rotated to ensure full contact with the shale. The samples are heated to ensure that the fluid is at reservoir pressure and temperature. Several tests were done to ensure that the fluid temperature and pressure inside the vessels were at the desired conditions throughout the 72-hour test period. T2 NMR scans were carried out before and after treatment to determine the amount of incremental oil recovery from the treatment. In tests where the two fluid phases were indistinguishable, deuterium was used in the treatment fluid in lieu of water. Excellent reproducible results were obtained with this method. This new method has been used to test a number of different treatment fluids, gases and solvents under a variety of conditions. The test can be completed in a matter of a few days as compared to several weeks that would be required for a core flood. Several tests can be run simultaneously, further speeding up the process. The results of the laboratory tests can be scaled to the field by using suitable surface-to-volume ratios in the lab and comparing them to the field.

With this new method we have a fast and robust method for conducting these huff-and-puff experiments in a repeatable, and precise manner. This allows us to quickly evaluate different IOR fluids for a particular shale-fluid system at reservoir conditions.
A Smart Classification Framework for Enhancing Reliability in Downhole Gas Bubble Sensing
Authors: Katterbauer Klemens , Schoepf Virginie , Marsala Alberto , Abbassi Linda
Published: September 2021

Production logging tools (PLTs) and formation testing, even in logging while drilling (LWD) conditions during underbalanced drilling, are key technologies for assessing the productivity potential of a gas well and therefore to maximize recovery. Gas bubble detection sensors are key components in determining the fluid phases in the reservoir and accurately quantify recoverable reserves, optimize well placement, geosteering and to qualify the production ability of the well. We present here a new nonlinear autoregressive - breakdown artificial intelligence (AI) detection framework for PLT gas bubble detection sensors that categorize in real-time whether and which sensors become unreliable or have broken down during the logging measurements. AI tools allow the automatization of this method that is critical during data quality control of post-drilling PLT, but it is essential when the measurements are performed in LWD as data assessment and processing need to occur in real time. This AI framework was validated on both a training and testing dataset, and exhibited strong classification performance. This method enables accurate real-time breakdown detection for gas bubble detection sensors.