bluuebunny/crossref_metadata_2025_split huggingface dataset:
No Reservoir Model? No Problem. Unconventional Well Spacing Optimization With Simple Tools
Authors: Miller Patrick , Redpath Darcy , Dauncey Keane 
Published: March 2022

Abstract
Optimizing economics for unconventional resource development is a delicate balance among four main factors: reservoir deliverability, commodity price, completion design, and well spacing. For a certain reservoir, commodity price, and completion design, there is a well spacing that will optimize field development net present value (NPV). However, if we consider a different part of the reservoir (area or landing zone), commodity price, or completion design, that optimal well spacing changes. Given that this problem is fraught with uncertainty (in price, reservoir deliverability, and the impact on production of changing completion design or well spacing), we need simple, flexible tools to make better decisions about unconventional pad design.
From a technical perspective, teams of subsurface professionals strive to understand the relationship between well productivity and well spacing for a given completion design (or vice versa). If the well spacing is too tight relative to the size of fracture stimulation, the recovery factor will be high, but the development plan will be over-capitalized. If the well spacing is too wide relative to the fracture stimulation, the per-well recovery will be high, but too much resource will be left in the ground and the NPV of the development plan will be low. To search for the optimal pad design, operators often invest in integrated technical workflows with multi-well fracture modeling and reservoir simulation; although useful, these workflows are not practical to apply for every asset in a portfolio because they simply take too long. As an alternative approach, this paper builds on existing tools in the literature to quantify the impact of changing well spacing on well productivity for a given completion design, using a new, simple, intuitive empirical equation.
Using real data from the Permian basin, this paper applies the empirical equation to model the relationship between well performance and well spacing, and quantify uncertainty in that relationship. By linking this equation with a simple economic model, the paper shows how to make appropriate well spacing decisions under uncertainty, and how those decisions would change due to changes in reservoir deliverability or commodity price.
Compared to similar methods in the literature, this approach better captures the physics associated with overlap in drainage areas for adjacent unconventional wells, while maintaining simplicity and ease of implementation. The paper also discusses how to integrate various diagnostics that give information about fracture geometry, to help guide the bounds of uncertainty in the well performance relationship. Even with limited data, this approach can be applied to yield useful information for decision makers about how to adjust unconventional pad design to improve development plan economics.
Statistical and Machine-Learning Methods Automate Multi-Segment Arps Decline Model Workflow to Forecast Production in Unconventional Reservoirs
Authors: Jha Himanshu Shekhar , Khanal Aaditya , Lee John 
Published: March 2022

Abstract
This paper provides a workflow to automate the application of multi-segment Arps decline model to forecast production in unconventional reservoirs. Due to significant activity in the shale plays, a single reservoir engineer may be tasked with managing hundreds of wells. In such cases, production forecasting using a multi-segment Arps model for all individual wells can be a challenging and time-consuming process. Although popular industry software provide some relief, each approach has its individual limitations. We present a workflow to automate the application of multi-segmented Arps decline model for easier and more accurate production forecasting using suitable statistical and machine learning methods.
We start by removing outliers from our rate normalized pressure (RNP) data using angle-based outlier detection (ABOD) technique. This technique helps us clean our production data objectively to improve production forecasting and rate transient analysis (RTA). Next, we correct the non-monotonic behavior of material balance time (MBT) and smooth the RNP data using a constrained generalized additive model. We follow it by using the Ramer–Douglas–Peucker (RDP) algorithm as a change-point detection technique to automate the flow regime identification process. Finally, we calculate a b-value for each identified flow regime and forecast future production. We demonstrate the complete workflow using a field example from shale play.
The presented workflow effectively and efficiently automates the rate transient analysis work and production forecasting using multi-segment Arps decline model. This results in more accurate production forecasts and greatly enhanced work productivity.
The workflow presented, based on selected algorithms from statistics and machine-learning, automates multi-segment Arp’s decline curve analysis, and it can be used to forecast production for a large number of unconventional wells in a simple and time efficient manner.
Machine Learning Enhanced Upscaling of Anisotropic Shear Strength for Heterogeneous Oil Sands
Authors: Zhang Bo , Ma Zhiwei , Zheng Dongming , Chalaturnyk Rick , Boisvert Jeff 
Published: March 2022

AbstractWeak shale beddings are widely distributed in the overburden and reservoir of oil sand deposits and lead to reduced anisotropic shear strength. Understanding the shear strength of the overburden and the reservoir is important in risk assessment of slope stability in open-pit mining and caprock integrity of in-situ thermal recovery of oil sands while optimizing the production of bitumen.Due to the restrictions of computational efficiency, cells used for simulation cannot be smaller enough to capture the details of heterogeneity in the reservoir. Therefore, a robust and efficient upscaling technique is important for modeling the impact of heterogeneity on the deformation and failure of oil sands during mining and in-situ recovery. However, current analytical and numerical upscaling techniques cannot provide computationally efficient geomechanical models that consider the impact of inclined shale beddings on shear strength. Therefore, we propose a machine learning enhanced upscaling (MLEU) technique that leverages the accuracy of local numerical upscaling and the efficiency of machine learning techniques. MLEU generates a fast and accurate machine learning-based proxy model using an artificial neural network (ANN) to predict the anisotropic shear strength of heterogeneous oil sands embedded with shale beddings. The trained model improves accuracy by 12%-76% compared to traditional methods such as response surface methodology (RSM). MLEU provides a reasonable estimate of anisotropic shear strength while considering uncertainties caused by different configurations of shale beddings. With the increasing demand for regional scale modeling of geotechnical problems, the proposed MLEU technique can be extended to other geological settings where weak beddings play a significant role and the impact of heterogeneity on shear strength is important.
A Novel Approach to Post-Combustion Carbon Capture Processes in Natural Gas Plants By Reduction of Solvent Regeneration Time
Authors: Ekpotu Wilson , Nwabueze Queen , Akintola Joseph , Obialor Martins , Ansa Idongesit 
Published: March 2022

Abstract

Objectives/Scope
Carbon Capture processes have been utilized in various sectors, but limitations in its large parasitic load have been observed in its use in Natural Gas Process Plants, and that is mostly associated with the energy penalty incurred during its processes. The energy penalty is mainly caused by the solvent regeneration in the stripper column, the CO2 compression process, and the low amount of CO2 levels in the combustion flue gas, which is usually less than 15% (7-14 % for coal-fired and as low as 3% for gas-fired). This research work, therefore, has the objective of solving the challenges of solvent regeneration time in the stripper column, as the packing arrangement, corrugation angle, and crimp height can influence the capture efficiency through the solvent.

Methods, procedures, process
Aspen HYSYS was adopted for modeling the absorption rate through the stripper column in order to understand the hydrodynamic phenomenon in absorbers using solid absorbents under plug flow and well-mixed flow conditions. The rate fraction was analyzed at various process configurations and staged regeneration simulation processes in a packed column considering enthalpy changes at both gas and liquid phases.

Results, Observations, Conclusions
The results showed a 20% reduction in the solvent regeneration time, as against existing processes & technologies. It was observed that operating at a lower circulating rate results in a lower utility requirement on the reboiler hence increasing the circulation flow rate, which has little to no effect on the condenser utility. And this additionally led to a reduction in the energy penalty, as low-pressure steam was used as the energy input for the solvent regeneration process, thus posing a significant efficiency penalty. In conclusion, the modeling by the process optimization and modification of the post-combustion carbon capture plant reduced the regeneration energy requirements. Novel/Additive Infirmation: The solvent solution flowrate in the absorber was optimally considered with various lean CO2 solvent loadings in order to achieve higher CO2 capture and removal efficiency.
Carbon, Capture, Utilization and Storage CCUS: How to Commercialize a Business with No Revenue
Authors: Terdal Rohit Madhva , Steeghs Nathan , Walter Craig 
Published: March 2022

Abstract
Canada has joined the growing list of countries committed to achieving net zero emissions by 2050. This will require a rapid transition to carbon-free energy systems over the next three decades, with Carbon Capture, Utilization, and Storage (CCUS) a core component of unlocking Canada's decarbonization objectives.
It is estimated that Canada will need to capture upwards of 100 million metric tonnes of CO2e per year through CCUS to achieve net zero by 2050. However, Canadian CCUS projects currently face a plethora of commercial hurdles, ranging from capital intensive technology, long investment time horizons, lack of clarity of government incentives and policies, and disjointed carbon markets.
Carbon pricing policies are one lever to drive industry adoption of CCUS, but a cohesive industry and government collaboration is required to establish the national infrastructure needed to scale and support the development of CCUS in Canada.
The recent announcement of the Oil Sands Pathways to Net Zero comprises of six oilsands producers, representing 90 percent of oilsands production, and signals a willingness of industry to come together with government to tackle these issues and support the oil sands industry which is projected to add $3 trillion to GDP by 2050. The central pillar of their vision is the use shared transportation infrastructure and storage hubs. This model will require significant government support but what is the right model to secure Canada's future while de-risking public funding.
Policy development is still required by government bodies to encourage the investment in, and the implementation of these multibillion-dollar, long term projects. The announcement of a Canadian federal investment tax incentive and enforcement of the incoming clean fuel standard may further drive organizations to incorporate CCUS into their decarbonization plans. To proceed, industry will require further clarification to determine the effects of policy decisions and potential government partnerships will have on the cost structure and commercial viability of CCUS projects.
This paper will outline some of the current commercial barriers that industry faces with the adoption of CCUS. It will provide a roadmap on how to mobilize and partner to scale CCUS in Canada.
Assessment of Oil Recovery Methods for Reservoirs in the Flemish Pass Basin
Authors: LaFitte C. , James L. A. 
Published: March 2022

Summary
In recent years, the Flemish Pass Basin has been gaining momentum as an area of potential high-volume resources on the frontier of remote, deep-water offshore oil development. This simulation study utilizes three sector models representing regional, discovered reservoirs, and two tuned fluid models representing oil sampled from wells in the Flemish Pass Basin. Generally speaking, WAG is considered a late-life enhanced oil recovery (EOR) technique, while implementing WAG immediately upon first oil for secondary recovery is less common; however, may be equally or more valuable.
This study aims to evaluate three secondary oil recovery methods, water flooding, gas flooding, and water-alternating-gas (WAG) flooding. Each recovery method is simulated with Schlumberger’s ECLIPSE reservoir simulator and uses a combination of three distinct reservoir geo-models and two fluid models. This study is a sensitivity analysis using geo-models that represent three discovered regions and two sampled fluids from the Flemish Pass Basin. The study is aimed at evaluating the effects of the various recovery methods over a duration of either five- or twenty-year forecast periods.
Results from this study capture an inherent uncertainty by drawing from eighteen simulation cases to quantify the relative benefit of each recovery method. These results indicate that using WAG as a secondary recovery method can yield a 4% to 10% increase in recovery over water or gas flood, and that secondary WAG can extend a well pair’s production plateau by up to 80% in specific circumstances.
Further observations indicate that secondary WAG in light oil reservoirs yield a ∼10% increase in recovery over secondary water or gas flooding. Using WAG in a medium oil reservoir yields a 4% to 9% increase in recovery over water flood, and a 2% to 16% increase in recovery over gas flood. In terms of geology, WAG is observed to be most valuable in ultra-high-quality reservoirs. The better the reservoir quality, the more recovery improvement. In terms of fluids, the medium oil responds best to the gas injection phase of WAG while the light oil appears to respond well to both phases. During development optimization, these trends can be accounted for in the injection cycle timing and duration for each phase.
In terms of using WAG as a tertiary recovery method after a period of water or gas flooding, tertiary WAG is observed to be most beneficial in the low to medium quality reservoirs. Tertiary WAG extends the production duration and results in a ∼4% increase in recovery beyond water flooding. Study results go on to quantify the differences in water and gas breakthrough as a factor of pore volume injected (PVI) and conclusions further indicate which reservoirs are best suited for each recovery method.
Evaluating the Prospect of Oil Production in Tight Winterhouse Formation Rocks in Western Newfoundland
Authors: Hawco Jessica , Burden Elliott , Sripal Edison , James Lesley 
Published: March 2022

Abstract
The Winterhouse Formation (Port au Port Peninsula, western Newfoundland, Canada) is a lateral equivalent to the Utica and Macasty formations farther west. With hydrocarbon stains and odours as a guide towards a common and regional upper Ordovician hydrocarbon system, Winterhouse rocks may yet contain their own suite of source reservoir and seal strata, with coarser, sandier beds perhaps playing host to other varieties of conventional and unconventional hydrocarbon traps. Hence, addressing basic properties of fluid transmission is an important and unknown variable that needs to be addressed for this formation. In this pilot study, Mercury Intrusion Porosimetry (MIP) is applied to measure the petrophysical properties of a single tight (low porosity, low permeability) quartz-carbonate sandstone sample from a Winterhouse outcrop. As a tool, Mercury Intrusion Porosimetry is strongly dependent on conformity of sample size and shape as a determinant of pore accessibility. Hence two sample types (i) plugs and (ii) cuttings (both real and artificial) are analyzed to explore aspects of core and cuttings preparation and data reduction work flow measurements of storage and transport properties. For artificial "cuttings" a horizontal 2.5 cm core plug and rock fragments are crushed and sieved to replicate fine and coarse fractions. For porosimetry, a Micromeretrics AutoPore IV porosimeter with a maximum pressure of 33,000 psi is used to determine the porosity, pore size distribution, surface area, and bulk density of all samples. Additionally, the FEI Quanta 650 Field Emission Gun (FEG) SEM is used to take images of the pore structure. Mineralogy is determined from the GXMAP measurement mode within FEI Mineral Liberation AnalyzerTM software. A comprehensive analysis corroborating results from MIP and SEM indicates that for these tight rocks, and namely, outcrop plugs, artificial cuttings, and real drill cuttings from a nearby well, all show a similar spectrum of results, but smaller coarse fragments are recommended for reliability. In terms of the Winterhouse strata, it is clear that some of this rock is very tight and highly cemented, but that it also possesses fractures and high permeability values which may make it a good unconventional reservoir. These porosity-permeability results are simply a beginning in a search to understand the petrophysical properties of the strata on the western coast of Newfoundland. The western part of Newfoundland has seen extensive oil exploration efforts in the last few decades, these efforts have resulted in little success. A large degree of this is due to the complex geological history and overall lack of knowledge concerning the structure and diagenesis of these rocks (Cooper et al, 2001). This study will support the new sampling programs in the hope of gaining new insights into potential oil exploitation.
Performance Analysis of Autonomous Inflow Control Valve in a SAGD Late Life Process with Non-Condensable Gases
Authors: Taghavi Soheila , Aakre Haavard , Moldestad Britt M. E. 
Published: March 2022

Abstract
The performance of an autonomous inflow control valve (AICV), used to restrict the inflow of unwanted fluids like gas and/or steam was simulated using an industrial reservoir simulator. The simulation results were used to determine how AICVs can improve the oil recovery in steam assisted gravity drainage (SAGD) operations. Utilizing inflow or flow control devices (ICDs/FCDs) in SAGD wells is a method with promising results. FCDs delay steam breakthrough and increase the oil recovery. The recently developed technology, AICV, further improves the oil recovery from SAGD operations. This paper provides a summary of the test data acquired from the full-scale flow loop testing that replicates the downhole operating conditions. Single and multiphase flow performance of an orifice type ICD and AICV is presented and compared. The results confirm the ability of the AICV to restrict the production of gas and/or steam. A performance analysis based on the results from the experiments and well case simulations is presented. The paper also presents an innovative approach on analyzing the well conditions which brings an insight into SAGD production wells completed with AICVs.
Simulations are performed in different scenarios of a SAGD late life process with non-condensable gases (NCGs), and these results confirmed a significant reduction in the gas liquid ratio (GLR), and an increased oil production when using AICV compared to the open hole case. Simulation results demonstrated that utilizing AICV in the SAGD production wells will reduce the gas and steam production by 64%. The reduction of steam production from the breakthrough zones allows a lower bottom hole pressure. This gives a higher sandface drawdown in the zones with less mobile oil, and thus a higher production from these zones. Further, this forces the steam chamber to be more evenly distributed along the different zones, resulting in increased oil recovery.
Considering the environmental aspect, AICV can contribute to a considerable reduction in the steam use which will consequently reduce the energy and water usage for steam generation. As a result, utilizing AICV in SAGD operations will improve the economics of SAGD projects.
Assess the Impact of Shallow Water Flow Geohazard on Drilling Operations in the Riserless Sections of Deepwater Well Construction
Authors: Kulkarni Nitin , Heinze Lloyd 
Published: March 2022

Abstract
Riserless drilling of the upper intervals of subsea wells has been standard practice in deepwater well construction, while taking mud returns to the sea floor. It has dramatically increased the safety of drilling shallow sections of subsea wells by reducing the hazard of handling gas at the rig, should shallow gas zones be encountered. It has also been very beneficial in controlling shallow water flows in deepwater areas of the Gulf of Mexico (GOM).
The shallow water flow (SWF) is a typical offshore drilling hazard, defined as the phenomenon involving the flow of water from the surrounding region of a casing up to the ocean floor together with formation sands and sometimes free gas. The flowing water is driven by a pressure difference that occurs when the drill bit has encountered the unconsolidated but over-pressured sand sections.
In the past 40 years of drilling practices, the SWF hazard has been experienced in several deep-water basins around the world, especially in the deep-water area where the water depth ranges from 1300 to 8200 ft and the formation depth ranges from 300 to 4000 ft below mud line (BML).
Shallow water flows from overpressure aquifers have been a serious concern in the deepwater Gulf of Mexico for drilling and production operations. They can create significant financial and operational risks for exploration and development projects. In the GOM, SWF intervals typically occur between 300 and 2,500 ft BML and in water depths greater than 1,500 ft. If left unchecked, the disturbance from the water flow can cause loss of soil strength surrounding the wellbore, thereby compromising the structural integrity of the well. In extreme cases, SWFs have led to collapsed casing and/or total loss of wellbores.
The paper aims to present the origin of shallow water flows in a deepwater environment and mitigation strategies adopted by industry to carry out the operations safely.