bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Paradigm for Automatic Well Path Generation Using Multidisciplinary Constraints
Authors: Cayeux E. , Pelfrene G. , Mihai R. , Dvergsnes E. , Tjøstheim B. P. , Baume A. , Khosravanian R. , Kristiansen T. G. 
Published: October 2023

Abstract
The well planning process involves many disciplines. Due to the multidisciplinary nature of the process, many iterations are necessary to generate a well path. This is a time-consuming process that finally leads to chosen planned trajectories that may be sub-optimal. It is proposed to radically revise the well path generation process to reach the vision of planning a well in one day with high quality.
Departing from the traditional incremental approach to well path generation, the proposed method relies on the collection of experienced-based constraints from each discipline to generate possible alternatives to the well path. A fundamental difference with the classical well path generation process, which works with one or a handful of planned trajectories, is that an ensemble of possible well paths is generated through the proposed method. If the constraints are loose, many planned trajectories might be generated but if the constraints are tight, there may be very few or possibly no solutions. As a result of this new work process, the multidisciplinary team can focus on the relevance of the constraints rather than on the details of the planned trajectory. Capturing these constraints is the fundamental result of the well planning process; the ensemble of possible well paths being only a byproduct of it.
The novel method comes with a set of concepts that provide subject matter experts with greater leeway for defining the well path generation problem in a generic way. These concepts have been designed to seamlessly allow for any subsequent updates of the well plan, whether for the target or group of targets and their associated wellbores, the wellbore architecture and its relation to geo-pressure margins, or the surveying program with regards to wellbore position uncertainty. Whenever possible, characteristics attached to these concepts are described implicitly to cope with mutual interactions between constraints. An extensible classification of the constraints is provided and illustrated with examples commonly used to define drilling programs. As a result of the propagation of user-chosen constraints, complex problems such as finding well paths that respect anti-collision criteria, avoid faults or cross them with a high incidence angle if unavoidable, and satisfy inclination limits to cross certain formation layers are solved completely automatically.
Innovation does not come for free: the new paradigm presented in this paper induces a significant transformation of the well planning process. However, the versatility of the approach should largely compensate for the expected change in end-users’ habits both by a faster delivery time of every well plan (or even large-scale field development) and by allowing a seamless update of the latter when drilling operations demand it.
Polymer-Assisted-Water-Alternating-Gas for Improving the CO2 Flow Properties in Porous Media
Authors: Yegane Mohsen Mirzaie , van Wieren Thijs , Fadili Ali , van Batenburg Diederik , Leblanc Thierry , Zitha Pacelli 
Published: October 2023

Abstract
CO2 flow in porous media is vital for both enhanced oil recovery and underground carbon storage. For improving CO2 mobility control and thus improved reservoir sweep efficiency, Water-Alternating-Gas (WAG) injection has often been applied. The effectiveness of WAG diminishes, however, due to the presence of micro-scale reservoir heterogeneity which results in an early breakthrough of gas. We propose Polymer-assisted WAG (PA-WAG) as an alternative method to reduce gas mobility, while also reducing the mobility of the aqueous phase, and consequently improving the performance of WAG. In this method, high molecular weight water-soluble polymers are added to the water slug.
The goal of this work was to investigate the feasibility of PA-WAG and study the transport processes in porous media. An ATBS-based polymer (SAV 10 XV) was chosen as polymer and CO2 at immiscible conditions as gas. The objective of the experiments was to compare the performance of CO2, WAG, and PA-WAG injection schemes by conducting a series of X-ray computed tomography (CT)-aided core-flood experiments in Bentheimer cores.
Core-flood results clearly demonstrated the beneficial effects of PA-WAG over WAG and continuous CO2 injection. Continuous injection of CO2 led to the recovery factor (RF) of only 39.0 ± 0.5% of the original oil in place (OOIP). In-situ visualization of CO2 displacement showed strong gravity segregation and viscous fingering because of the contrast in the viscosities and densities of CO2 and oil. The injection of WAG almost doubled the oil recovery (i.e., RF=76.0 ± 0.5%); however, the water and gas breakthroughs still occurred in the early stage of the injection (0.22 PV for water and 0.27 PV for CO2). The addition of the polymer to the aqueous phase delayed both the water and CO2 breakthrough (0.51 PV for water and 0.35 PV for CO2). This resulted in an additional 10% in the recovery factor. Using a single injection method, polymer adsorption was found to be 79.0 ± 0.5 μg polymer/g rock. The polymer adsorption can reduce the micro-scale permeability and as a result, mitigates the gas channeling. This in turn leads to the delay in CO2 breakthrough during PA-WAG injection as was evident from in-situ visualization.
This experimental study demonstrated a positive response of PA-WAG compared to WAG and paves the way for its implementation in field applications.
Successful Deepwater MPD Application in Drilling and Cementing Through Depleted Formation with Wellbore Instability and Loss Circulation Challenge Offshore of Sabah
Authors: Benny B. , Tan J. , See J. , Foo J. , Othman F. , Mathew M. 
Published: October 2023

Abstract
Managed Pressure Drilling (MPD) has become the essential drilling technique to drill problematic zones in these past decades due to its ability to precisely manipulate downhole equivalent mud weight (EMW). This ability empowers the operator to save time and cost when drilling through loss zone with lower drilling fluid and at the same time, able to retain EMW above the wellbore instability or, if required, pore pressure gradient.
This paper describes the crucial role of MPD in a drilling operation on a horizontal deep water oil producer well in Sabah region, offshore of East Malaysia, to help the Operator recover from Wellbore Instability and Loss Circulation issues and successfully drill and cement the problematic section. The main challenge of the well is the tight drilling window between depleted sand formation and the interlayered shale formation. Therefore, the MPD Integrated Riser Joint (IRJ) was deployed along with the riser string prior drilling 12.25 in hole section. Initially, the section was drilled conventionally with wellbore strengthening techniques, only to encounter unmanageable static losses. After multiple unsuccessful attempts to cure losses, the section was cement plugged to sidetrack the well.
Considering the substantial challenges encountered, the well was sidetracked with lighter drilling fluid and applied surface back pressure (SBP) to maintain its bottom hole pressure above the wellbore instability gradient and below the fracture gradient. After the well had reached target depth, the drilling assembly was pulled out of hole in MPD mode without having to displace the well to heavier tripping mud and, once it was above the Subsea Blowout Preventor (SSBOP), the well was then isolated with blind shear rams (BSR). To continue maintaining SBP below the BSR, the MPD system was lined up on a surface loop circulation in such a way that the SBP was applied to the well via kill line. With the casing string delivered to the bottom, Managed Pressure Cementing (MPC) was utilized to cement the casing by having a schedule of SBP against pumped strokes that was formulated by software simulation to give a minimum pressure surge when the cement slurry entered the open hole.
In addition, the paper also describes the equipment setup required onboard a drillship for drilling with MPD in a deep-water setting. The MPD setup enables the application of advanced flow detection system and riser gas handling which are critical in drilling deep water wells. With all these features, MPD Deepwater application has successfully delivered the well to target depth which once was undrillable.
Pressure- and Rate-Transient Model for an Array of Interfering Fractured Horizontal Wells in Unconventional Reservoirs
Authors: Ozkan E. 
Published: October 2023

Abstract
An analytical solution is presented for pressure- and rate-transient behavior of an array of, parallel, fractured horizontal wells in an unconventional reservoir. Wells are of equal length but otherwise of unidentical properties. Each well has an arbitrary number of uniformly spaced identical, finite-conductivity fractures and is surrounded by a stimulated reservoir volume. Properties of hydraulic fractures and stimulated reservoir volumes may vary from well to well. Different properties may also be assigned to unstimulated reservoir section between wells. Natural fractures in the stimulated and unstimulated reservoir volumes are accounted for by the transient dual-porosity idealization. Flow domain is divided into blocks of one-dimensional flow under the trilinear flow assumption. Analytical solution for each block is obtained by the appropriate Green's function and coupled with the neighboring blocks by the continuity of pressure and flux at the block interfaces. Superposition principle is applied to consider variable production conditions as well as nonsynchronous production and shut-in schedules of wells. The final solution is in the form of a matrix-vector equation in the Laplace transform domain and inverted into time-domain numerically. Results are robust and reasonably accurate for most practical applications of single-phase oil and gas production from multiple wells in an unconventional reservoir. The solution provides an efficient tool to assess well interference effects for different well completion designs and varying reservoir characteristics. The speed of calculations is convenient for pressure-transient and production-data analysis, as well as for the initial calibration and verification of more complex numerical models. The closed analytical form of the solution enables assessment of flow regime diagnostics under well-interference.
Flow-Geomechanics-Geochemistry Simulation of CO2 Injection into Fractured Sandstones and Carbonates
Authors: Mura Miki , Sharma Mukul M. 
Published: October 2023

Abstract
CO2 storage in reservoirs with natural and/or induced fractures is an efficient method to sequester CO2 because of their high and sustained injectivity. Past work has focused on storage of CO2 in the pore space and in the dissolved state within the brine. This research shows that geochemical reactions involving the CO2 interacting with reservoir minerals (in different lithologies) can also play a very important role in sequestering the CO2. A fully integrated 3-D reservoir simulator that includes single-phase flow, geomechanics, and geochemistry is introduced. The geochemical capability in the simulator predicts flow and geomechanical behavior due to geochemical reactions triggered by CO2 injection. The simulation models a reservoir with an induced planar fracture. The amount of CO2 that is sequestered and the extent of mineral dissolution and precipitation are computed. To demonstrate the impact of rock lithology, the model is used to simulate CO2 injection into a sandstone, a limestone, and a dolomite reservoir. The paper also investigates two different CO2 rich brines to investigate the impact of the brine composition. It is shown that the portion of the CO2 injected that reacts with the minerals and is then converted into other mineral precipitates depends largely on the mineralogy of the reservoir and the composition of the injection fluid. Limestone and dolomite reservoirs are much more susceptible to mineral dissolution and precipitation resulting in more CO2 sequestration and larger changes in injectivity over time when injection fluid is compatible with the host rock. It is shown that the fracture geometry determines the location of mineral dissolution and precipitation. This alteration of the mechanical and flow properties of the reservoir rock and fractures resulting from mineral alteration can also change the mechanical properties of the rock and result in more fracture growth and enhance or impede propagation of CO2 plume or CO2 charged water. Results showing the pros and cons of injecting CO2 into fractured wells in sandstone and carbonate reservoirs are presented considering the brine types to charge CO2. Our results show, for the first time, the clear differences that arise when sequestering CO2 in limestone, dolomite and sandstone reservoirs. The impact of geochemical reactions in realistic injection well scenarios is quantified. Results are also presented to show the pros and cons of using hydraulically fractured wells for CO2 injection in both lithologies.
Novel Ways of Optimizing Production of Gas Wells Suffering from Downhole Salt Deposition
Authors: Janzen M. R. , Hornstra E. , Doldersum B. 
Published: October 2023

Abstract
Downhole salt precipitation is an increasing problem in the mature gas fields of the North Sea. With depletion and relatively high drawdowns, excessive evaporation of production water leads to salinities exceeding the solubility limits and thus salt deposition. This leads to significant losses of production and reserves, and increased costs as wells are traditionally shut-in, waterwashed regularly and/or choked back heavily.
Two novel solutions have been conceptualized and applied, the first being installation of velocity strings. Besides increasing gas velocities to eliminate liquid loading, a smaller tubing has a downhole choking effect and as such strongly increases flowing pressures. A case study is presented wherein four velocity strings were set, leading to a strong increase in platform flowrate and extension of asset life. The major advantage of this solution is that it is relatively simple, extremely robust and does not involve any increased OPEX. As it involves increased flowing pressures, it is best applied to lower quality producers. Due to their steep inflow performance relation, there is only a very limited decrease in flowrate upon installation of the smaller tubing.
For good to excellent quality reservoirs, the choking effect by a velocity string causes a flowrate decrease of often 40 to 50% - too significant to yield attractive economics. As such, it is a better option to compensate for the evaporation rate by external supply of freshwater. Proof of concept has been delivered for 1) using recycled low salinity/oxygen process water for water washing and 2) continuous downhole freshwater injection by a successful three-week pilot test. During the latter, injection rates of approximately 1 m3/d have been achieved, which is shown to effectively eliminate downhole salt deposition for the presented case.
Modeling and Optimization of Mud Cap Drilling for Undrillable Wells Due to Loss of Circulation
Authors: Saihood T. , Al-Safran E. , Nguyen T. 
Published: October 2023

Abstract
Mud Cap Drilling (MCD) is a technique from Managed Pressure Drilling (MPD), which is used when all conventional attempts fail to solve the loss of circulation. MCD places a very high drilling fluid density, called Mud Cap (MC), in the annulus above the lost zone to prevent the mud from returning to the surface. A sacrificial fluid instead of drilling mud is used to clean the hole and transport the cuttings into the loss formation. This study presents a detailed step-by-step model and design for a well in the Middle East. New equations were developed to calculate the MC height, MC density, and the position of the interface between the MC and the sacrificial fluid. The present model also depicts pump rate optimization and hole cleaning to reach an efficient drilling program. The case study presented within this paper encountered a complete lost zone and was considered as an un-drillable well. The pore and fracture pressures were calculated using drilling data from the offset well. A sensitivity analysis was performed to obtain optimal MC height and density. A complete optimal MCD design and optimal MCD operation for this well is conducted in detail. The results of this study have proved that the proposed model can be utilized as a tool to design and optimize an MCD program.
Case Study of Successful Pilot Polymer Flooding to Improve the Recovery of Lloydminster Heavy Oil Reservoir- West Central Saskatchewan
Authors: Ulovich Ivan , Imqam Abdulmohsin , Martinez Juan , Aljubori Ahmed , Rathod Rakeshkumar 
Published: October 2023

Abstract
The Lloydminster Heavy Oil Block is the main source of Canada's conventional heavy oil production. The most common methods of recovery in this area are primary production, waterflooding, and chemical-enhanced oil recovery (EOR) such as polymer flooding. Although heavy oil waterfloods could be relatively successful if managed properly, their production and economic efficiencies are often challenging due to quick water breakthrough followed by a steep decline in oil production. Beliveau (2009) showed that over 50% of oil produced from such water flood projects are typically produced at water cuts greater than 90%, which would increase water processing costs. The objective of this study is to outline the implementation of a successful polymer flood project in Lloydminster Heavy Oil Block that includes the production and injection performance of the pilot. It also describes the steps of selecting the appropriate polymer type based on reservoir rock properties, water quality, and other main parameters for the optimal polymer selection. An anionic polymer candidate provided by ZL EOR Chemical Ltd. was selected for the project. The field under study is in the province of Saskatchewan and producing from the Lloydminster sandstone. Initially, the field was produced under a line drive waterflood with horizontal wells. The reservoir has a live oil viscosity of about 2,600 cP at downhole temperature of 21.5°C and the average clean-sand permeability of 1,500 mD. In April 2018, a polymer flood pilot was introduced as a primary recovery method with continuous polymer injection at ~25 cP (~2000 ppm polymer concentration). Injection rates varied from 30 to 50 m3/d/well, based on the target injection volume of 5 to 10% of effective pore volume (PV) per year. As a result, field water cut has decreased and stabilized at ~65%, while oil production rate has remained relatively constant at ~40 m3/d for over five years with no signs of polymer breakthrough. Production performance from the beginning of the polymer flood demonstrates the efficiency of this EOR method, thereby providing valuable insights into the first primary polymer flood project in the Lloydminster Heavy Oil Block.
The Use of Chemical Tracers for Identifying Location of Completion Equipment Failure
Authors: Sennour Bel , Lavoie Scott , Williams Brock 
Published: October 2023

Abstract
This paper reviews the case history of a subsea well in the Gulf of Mexico that was completed with two zones that contained sliding sleeves for the purpose of closing off one zone if early water break-through occurred.
Chemical tracers in solid form were integrated into the sand face completion at both locations. These tracers take the form of rods that can be installed into standard sand screens during manufacturing without modification to the screen. The tracer rods at each location release a unique chemical compound into the oil flowing from the interval. Samples of the produced oil are analyzed to determine the concentration of each unique tracer compounds from each interval.
Upon well startup, the chemical tracers indicated that one sliding sleeve was RIH in the closed position. This insight triggered an intervention to open the sleeve, and the well was restored to expected production rates. The chemical tracers saved the operator from having to intervene into a live well to diagnose below-expectation performance.
The solid chemical tracer technology can be used to monitor any completion component that is designed for separating and sealing off a production interval without incurring the high cost and risk of performing surveys on a flowing well. In addition, this technology can identify locations of water influx, gas influx and inflow distribution through several years of the well’s life.
Autonomous Drilling Fluid Management System - Development of Fluid Advisory System and First Lab Trial
Authors: Ettehadi Reza , Onegova Elizaveta , Fevang Finn Øivind , Knizhnik Alexey , Postovalov Sergey , Brevik Jan Ove , Thompson Jr Charles , Egorenkova Tatyana , Kaageson-Loe Nils 
Published: October 2023

Abstract
This paper details a study to design a Fluid Advisory System which uses various algorithms and methods to calculate an optimal quantity of chemical additives which preserve the desired characteristics of the drilling fluid based on manual and real-time measurements while taking inventory into account. The algorithms and results of the first lab trial are presented for water-based mud.
The Fluid Advisory System methodology consists of a data pipeline for loading historical data into a master table, a training pipeline for creating a fluid property model (digital twin) using Machine Learning (ML); an automated predictive analytics tool for model selection; and incorporating the predictive models into a prescriptive model that determines quantity of additives to use to achieve a desired set of drilling fluid properties. Given the initial product composition, a set of desired and current fluid properties, the prescriptive model suggests necessary modifications in additive concentrations. This is achieved by setting and solving an optimization problem.
First, the Autonomous Fluid Management algorithms have been validated in small-scale lab experiments. Following these successful experiments, a yard-scale trial was conducted at the Equinor Sandsli Automatic Drilling Fluid Laboratory. The yard trial demonstrated how remote control of drilling fluid treatment equipment and the Fluid Advisory System can be employed. The results of the tests reveal that it is now feasible to remotely regulate drilling fluid mixing and apply the ML-based Fluid Advisory System to maintain desired drilling fluid properties for weight, rheology, API fluid loss, pH, hardness, and chlorides.
The Fluid Advisory System was developed to aid in the optimization of the real-time drilling fluids treatment process for usage in an Integrated Operations Level 3 environment (IO level 3) and higher (IO level). This takes a step towards autonomous drilling fluid management that will allow for reduction of personnel needed to monitor and maintain a drilling fluid system; more consistent fluid performance and properties; more efficient rig supply chain; lower NPT; safer operations; lower operational cost; and lower carbon footprint.
To our knowledge, this is the first time that a Fluid Advisory System for maintaining multiple properties of a drilling fluid was developed and validated experimentally in a remote-controlled mixing facility.