bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Two Novel Enhanced Oil Recovery Processes in the Bakken Shale
Authors: Downey Robert , Venepalli Kiran 
Published: May 2023

Abstract
Oil production via horizontal wells with multistage fracture stimulation treatment completions in the Bakken shale of North Dakota and Montana began in 2003. Since then, over 19,000 Bakken shale horizontal wells have been completed and placed into production. Oil production from horizontal Bakken shale oil wells peaked in November 2019 at 1.5 million barrels/day, and is at about 1.2 million barrels/day as of September, 2022 (EIA). There have been several shale oil EOR tests conducted over the last several years, involving the injection of water, CO2 and natural gas.
This paper builds upon shale EOR modeling work described in a 2019 NETL report. In that report, a compositional simulation model of the Bakken was constructed, and a production history match on primary oil, gas and water production from a group of wells was obtained. The match model was then used to evaluate the enhanced oil recovery via cyclic injection of CO2, dry gas, and wet gas. This paper utilizes some data from that report to assess two novel, proprietary shale oil EOR processes in the Bakken, in the same area of the Williston Basin. The paper illustrates how these proprietary shale oil EOR processes may be implemented at lower BHP to mitigate interwell communication, while enabling greater oil recovery than via injection of water, CO2 or natural gas.
Compositional reservoir simulation modeling of the two novel EOR processes in the modeled Bakken shale wells indicates potential incremental oil recoveries of 200% and 300% of primary EUR may be achieved.
The two novel shale oil EOR methods utilize a triplex pump to inject a liquid solvent having a specific composition into the shale oil reservoir, and a method to recover the injectant at the surface, for storage and reinjection. One of the processes enables further enhanced oil recovery via cyclic fracture stimulation at the start of the EOR process. The processes are fully integrated with compositional reservoir simulation to optimize the recovery of residual oil during each injection and production cycle.
The patent pending shale oil EOR processes have numerous advantages over cyclic gas injection - shorter injection time, longer production time, smaller, lower cost injection volumes, no gas containment issue - much lower risk of interwell communication, elimination of the need to buy and sell injectant during each cycle, much better economics, scalability, faster implementation, optimization via integration with compositional reservoir simulation modeling, and lower emissions. If implemented early in the well life, their application may preclude the need for artificial lift, to produce more oil sooner, resulting in a shallower decline rate and higher reserves.
Hydrogen Generation from Heavy Oils via In-situ Combustion Gasification
Authors: Song Ping , Li Yunan , Yin Zhen , Yuan Qingwang 
Published: May 2023

Abstract
In-situ combustion (ISC) is a technology used for enhanced oil recovery for heavy oil reservoirs. In two ISC field pilots conducted in 1970s to 1980s in Canada, 10-20% mole fraction of hydrogen (H2) was produced accidentally. This presents a potential opportunity for petroleum industry to contribute to the energy transition by producing hydrogen directly from petroleum reservoirs. However, most ISC experiments have reported no or negligible hydrogen production, and the reason remains unclear. To address this issue, this study focuses on hydrogen generation from bitumen through in-situ combustion gasification (ISCG) at a laboratory scale. CMG was used to simulate the ISCG process in a combustion tube. Kinetics from previous ISC experiments and reactions for hydrogen generation were incorporated in the models. Heavy oil, oxygen, and water were simultaneously injected into the tube at a certain temperature. The ranges of key parameters were varied and analyzed for their impact on hydrogen generation. The study found that maintaining a temperature above 400 °C is essential for hydrogen generation, with higher temperatures yielding higher hydrogen mole fractions. A maximum of 28% hydrogen mole fraction was obtained at a water-oxygen ratio of 0.0018:0.9882 (volume ratio at ambient conditions) and a temperature about 735 °C. Higher oxygen content was found to be favorable for hydrogen generation by achieving a higher temperature, while increasing nitrogen from 0 to 78% led to a decrease in hydrogen mole fraction from 28% to 0.07%. Hydrogen generation is dominated by coke gasification and water-gas shift reactions at low and high temperatures, respectively. This research provides valuable insights into the key parameters affecting hydrogen generation from bitumen at a lab scale. The potential for petroleum industry to contribute to energy transition through large-scale, low-cost hydrogen production from reservoirs is significant.
Wellbore Leakage and Seismic Risk Assessments for Geological Carbon Dioxide Storage in Saline Formations in Kern County, California
Authors: Kim Tae Wook , Kohli Arjun , Li Yunan , Kovseck Anthony Robert 
Published: May 2023

Abstract
We evaluate the potential for CO2 leakage along pre-existing wells and through the formation caprock as well as the probability of inducing slip on faults during CO2 injection and storage in a saline formation in the Southern San Joaquin Basin. Our model considers 0.6 Mt CO2/y injection for 47 years and monitoring for an additional 100 years.
The prospective CO2 storage site was selected based on previous geospatial and economic analysis of emitters and storage sites in Kern County (Kim et al., 2022). Reservoir simulation was used to calculate the pressure and CO2 saturation. Then, risk assessment tools were used to estimate potential leakage rates through the overlying formations and along vertical wells. The stress state of the storage formation was determined based on regional stress information, earthquake moment tensor inversion, and well log data. Fault slip potential software was used to calculate the probability of inducing slip on faults considering a distribution of geomechanical parameters and fault orientations. We also study the historical seismicity of the area and identify seismological metrics that may help to distinguish natural from induced events.
There was no predicted leakage for CO2 and brine into the USDW with an assumption of wellbore permeability less than 10 mD (a value greater than that of a typical wellbore cement). The worst case for leakage assessment, with less than 1 % probability, assumed that the effective permeability of the existing wellbore is extremely high (30–50 mD). Nevertheless, the ratio of leaked CO2 mass to injected mass is less than 3.8 x10−6 (0.00038%). No impacts on a drinking water aquifer are predicted. The effective wellbore permeability is the most sensitive parameter to assess the leakage rate. The probabilistic fault model indicates that the pressure buildup should be limited to 500 psi (3.45 MPa) within 1 km of the injection site in order to minimize the risk of inducing slip on large faults.
This study provides a standard procedure to evaluate the potential for CO2 leakage and induced fault slip for any candidate CO2 storage site using publicly available data. This type of probabilistic risk assessment is critical in order to encompass the uncertainties in hydrological and geomechanical parameters and any variability in operating conditions.
Improving Economics for Abandoning Orphaned and Idle Oil and Gas Wells by Providing Storage for Pulverized Blades from Wind Turbines
Authors: Ikeocha Elena , Ershaghi Iraj 
Published: May 2023

Abstract
In a rush to install more renewable energy resources, we must carefully consider and mitigate the legacy issues with end of life waster from new solar and wind turbine installations. This paper is about a potential solution for handling legacy assets from wind turbine blades. The paper presents the economic viability to consider well internal capacities as storage sites as well as analyzes the environmental hazards of landfilling the blades. Bisphenol A (BPA) is a chemical used in wind turbine blades. Storage in landfills can put the future health of natural resources and the surrounding areas at risk. BPA can leak out of the dust particles and be hazardous to people and the environment. BPA also degrades in water and sediments under microbial processes. The increased risk of BPA leaching into groundwater resources and the soil from wind turbine blade landfills can damage the food chain and can harm future generations due to exposure to the contaminated resources. The solution discussed here is a potential use of the casing storage of idle wells for housing pulverized blades mixed with Portland cement when the wells are considered for plug and abandonment.
California Outer Continental Shelf Platform Decommissioning Update, Outlook, and Challenges
Authors: Smith John Bridge , Byrd Robert Clark 
Published: May 2023

Abstract
The authors have been working with the challenges related to decommissioning facilities offshore California since 1996. In a 2018 OTC paper (OTC-28844-MS) they reviewed the challenges for offshore facility decommissioning in this region. This paper reviews and updates the oil and gas platform decommissioning projects being conducted on the federal Outer Continental Shelf (OCS) offshore California and the decommissioning outlook for OCS platforms through the end of this decade. There are a total of 23 oil and gas platforms on the federal OCS offshore California which are submerged lands located more than three nautical miles from the coastline. The authors project that one-third of the 23 OCS platforms and one state water platform are likely to be decommissioned by the end of the decade, and at least 50 percent of the OCS platforms are likely to be removed by the middle of the next decade. Three of the eight OCS platforms being decommissioned, if fully removed, would each establish world water depth records for removing conventional steel platform jackets from the seafloor. The paper also describes the major technical, logistical, environmental, and regulatory challenges operators face in planning and conducting decommissioning projects offshore California.
Natural Extracted Waste Materials for Breaking Crude Oil Emulsion
Authors: Adewunmi Ahmad A. , Kamal Muhammad Shahzad , Gbadamosi Afeez , Patil Shirish 
Published: May 2023

Abstract
This study was performed to examine the efficacy of corn husks (CH) fine particles as potential natural demulsifier for breaking crude oil emulsion. Stable emulsions were formed using distilled water/crude oil and oil-water ratio was 4:6. The concentrations of CH particles ranging from 0.25, 0.5, 0.75, and 1% were added into vials containing the prepared emulsions and demulsification test was conducted inside the oven at 75 °C. Rheology was used to illustrate the demulsification mechanism of CH as potential demulsifiers. According to the experimental outcomes, the demulsification activity from the bottle test showed that water removal increased with the increasing CH concentration. The demulsification efficiency (DE) of 0.25, 0.5, 0.75, and 1% CH was 8.33%, 50%, 73.33% and 81.67%, respectively; after 60 minutes of demulsification duration. Rheological characterization showed that the incorporation of CH particles caused the reduction of emulsion viscosity which indicated the breaking of emulsion and separation of oil and water. Optical microscopic analysis revealed the morphologies of emulsion immediately after preparation, as well as oil and water phases after separation.
Beneficial Advantages of Nanoparticle-Enhanced Surfactant-Assisted Low Salinity Waterflooding Process
Authors: Fakir Shasanowar Hussain , Belhaj Ahmed Fatih , Singh Navpreet , Sarma Hemanta Kumar 
Published: May 2023

Abstract
The application of nanoparticles (NPs) to improve oil recovery is gaining wide acceptance in the petroleum industry in recent times. Due to their size and set chemical characteristics, NPs can be used to enhance oil recovery in carbonate reservoirs by altering the rock wettability and reducing oil–brine interfacial tension (IFT). Also, when used with surface-active agents like surfactant (cationic, anionic or non–ionic) in low–salinity waterflooding (LSWF), NPs can enhance the performance of surfactant. This study focuses on the implications of combining green NPs with surfactant and low–salinity water for EOR applications in carbonate reservoirs. A NP was synthesized from a green source, rice husk, and then characterized using XRD, FTIR, TGA and SEM analyses. A cationic surfactant, Aspiro S 6420, was added in the nanoemulsion of silica nanoparticle (SNP) and 1% diluted seawater (dSW). The SNP-Surfactant-1%dSW nanoemulsion was investigated for its beneficial effects for EOR applications. Zeta potential measurements were carried out for various brine dilutions, then for 1% dSW and surfactant, and finally 1%dSW–Surfactant–SNP nanoemulsions. The measurements showed that the zeta potentials are highly positive, confirming the stability of the nanoemulsions and alteration of rock wettability. Interfacial tension (IFT) between oil and brine were measured at a temperature of 86°C. The addition of surfactant (Aspiro S 6420) led to significant drop in IFT between oil and brine. Finally, when SNPs were added to the 1%dSW–Surfactant emulsions, the IFT reduced significantly, confirming that the combination of low salinity brine–cationic surfactant (Aspiro S 6420)–SNP can be used as a promising injection fluid to recover oil from carbonate reservoirs.
Determining the Storage Capacity of a Saltwater Disposal Reservoir in Practice
Authors: Wu Xingru , Childers David R. , Dai Lei , Shaffer Kelly 
Published: May 2023

Abstract
Produced water is commonly co-produced with oil and gas production and requires safe disposal in subsurface reservoirs. Knowing the amount of produced water that can be safely injected into the reservoir is important for disposal operations. While the methods of reservoir hydrocarbon storage are abundant in literature, the granularity of handling water injection capacity is rare, probably due to the misconception that production is similar to injection into a formation. The knowledge of hydrocarbon reservoir petrophysics shines some light on the problem. However, it is far from sufficient to make an economically viable decision as injecting water into the reservoir dramatically differs from producing it.
Many practitioners take for granted that knowing the pore volume of the target formation would be sufficient to determine the storage volume. The actual water injection capacity is the product of the pore volume of the formation, total compressibility of the system, and maximum allowable pressure difference. Since the stress-strain relationship of a porous medium depends on the frequency and magnitude of the loading and unloading process, the total compressibility would be different. The maximum allowable injection pressure and reservoir pressure are functions of in-situ stresses, injection temperature and pressure, and reservoir geomechanical parameters, all of which have significant uncertainty. In practical design, we must consider all parameters and their respective uncertainties. This paper presents a procedure for determining the injection capacity through an in-depth discussion of involved parameters and their associated uncertainties from estimation and measurements. This paper will also demonstrate our practice using a field example as our case study to show our suggested approach.
The Effect of Fracture Surface Roughness on Propped Fracture Conductivity Using 3D-Printed Fracture Surfaces
Authors: Sistrunk Carrie , Brashear Andrew Travis , Hill Dan , Zhu Ding , Tajima Tohoko 
Published: May 2023

Abstract
When rocks are fractured in tension, the fracture surfaces created are rough, with a wide range of surface morphologies possible. In previous studies of propped fracture conductivity using fractured samples, the fracture surface topography was found to have a strong influence on fracture conductivity and stimulation efficiency. Fracture surface patterns (relatively uniform, randomly rough, step changes, ridges and valleys) strongly affect propped fracture conductivity. Different types of surfaces can result in propped fracture conductivities differing by an order of magnitude or more for identical proppant loading conditions. To generate quantitative correlations including surface topographic effects, consistent samples with well-defined surfaces should be used in the experiments. However, when using actual rock samples to create realistic fracture surfaces by fracturing them in tension, the surfaces created are never the same, even using small samples all taken from the same block. This lack of repeatability in fracture surfaces greatly complicates identification of the effects of the rough surfaces on propped fracture conductivity.
To overcome this, we created repeatable rough fracture surfaces using 3D-printing technology. First, we geostatistically generated a numerical depiction of a rough fracture surface. Then the surface was printed with resin using a 3D-printer. The hardened resin model of the rock sample was used to make a mold, which was in turn used to create a rock sample made of cement. High strength cement was used so that the samples had similar mechanical properties to unconventional reservoir rocks. With this methodology, we created multiple samples with identical surface roughness and features, allowing us to isolate and test other parameters, such as proppant size and concentration.
Fracture conductivity tests were conducted using a modified API conductivity cell and artificial rock samples that are nominally 7 inches long and 2 inches wide. A well-established protocol to generate propped fracture conductivity as a function of closure stress was employed to test three different proppant concentrations on identical rough surfaces. For all three experiments, 100 mesh sand was used. The study demonstrates how proppant concentration affects propped fracture conductivity behavior in a systematic way.
Implementation of Renewable Technologies and Its Impact on Oil & Gas Resources Under Energy Market Dynamics Worldwide
Authors: Yurukcu Mesut , Yilmaz Koray , Yondemli Hande , Oskay Mehmet Melih 
Published: May 2023

Abstract
Investment in renewable energy resources and technologies from the oil and gas sector has increased consistently in the past two decades, turning the industry into one of the primary sources of capital for these newer energy sources, despite the potential that renewables possess to replace oil and gas since 1859. Renewables can be considered complementary, or competitors to oil and gas resources. Market forces respond differently to investments in renewables and the dynamics that these transfers of capital trigger in the general environment. For example, in Southern California and Oman, renewables are used to improve and decarbonize various oil and gas production processes. Meanwhile, alternative energy sources have displaced significant market oil and gas shares in other parts of the world, significantly altering supply and demand dynamics. Part strategy, part environmental commitment, the oil and gas sector has invested increasingly more capital in renewables in the past few decades. Despite the seemingly competing nature of its relationship with alternative energy sources, markets have adapted to work under a more collaborative approach, at least in the medium term.
The literature has covered the advent of renewables in detail, but it has focused less on the response from the oil and gas markets after the changes brought about by this arrival. We bridge that gap while exploring the advantages and challenges of maintaining a complementary relationship and how a strong investment in renewables can be the way forward for the oil and gas sector. This paper explores the dynamics between renewable energies and the oil and gas industry, both as complementary sources also as competing resources, that exacerbate or retreat depending on factors like geography, regulations, or market forces.
Field-Scale Multi-Stage and Multi-Objective Optimization of Rate and Concentration for Polymer Flooding
Authors: Zhang Ruxin , Li Ao , Chen Hongquan , Datta-Gupta Akhil , Chitale Ashish , Shekher Sunit , Kumar Ritesh , Das Joyjit 
Published: May 2023

Abstract
Field-scale simultaneous optimization of well rate and polymer concentration is challenging due to the geologic heterogeneity, large number of wells, and operational constraints. This paper proposes a multi-stage optimization strategy to achieve a multi-objective goal: maximize cumulative oil production and minimize cumulative polymer injection.
The proposed optimization strategy follows a sequential step: well rate optimization followed by polymer concentration optimization. In the first stage, streamline-based method is used to adjust the water injection rate and liquid production rate for hundreds of wells. This method equalizes the well pair efficiency that quantifies the amount of oil recovered per barrel of water injection, to maximize oil recovery. Key injectors are selected from the first stage and included in the multi-objective optimization for the second stage. A novel stochastic approach, multi-objective global and local surrogate-assisted method (MO-GLS), is utilized to optimize polymer concentration, to maximize cumulative oil production while minimizing cumulative polymer injection. This method considers a global prescreen and local search to obtain the trade-off solutions along the pareto front based on a dominance relation. Proxy model is built inside and updated during the iteration to improve optimization efficiency and particle swarm optimization is adopted as the optimizer for a fast convergence rate.
After multi-objective optimization, multiple trade-off solutions can be found along the pareto front, which have lower parameter uncertainty compared to the initial population. The optimization results are visualized using streamlines, which provide insights into the improvement in sweep efficiency from rate and concentration optimization. The sequential optimization workflow conducted in this paper provides theoretical basis and operational recommendations for the optimization of well rate and polymer concentration. The practical feasibility of the approach is demonstrated through a large-scale field application.