bluuebunny/crossref_metadata_2025_split huggingface dataset:
Physics-Based and Data-Driven Wettability Alteration Model
Authors: Bordeaux-Rego Fabio , Mehrabi Mehran , Eltahan Esmail , Sepehrnoori Kamy 
Published: April 2022

Abstract
This paper presents a new wettability alteration model based on surface complexation theory and an extensive experimental dataset. The objective is to provide a general correlation for contact angle calculation that (1) captures the main mechanisms that impact rock-brine-oil wettability and (2) minimizes the number of parameters used to tune with experimental data.
We compile a set of 141 zeta-potential and contact-angle measurements from the literature. We study the oil/rock surface-complexation reactions and model the electrostatic behavior of each data point. We develop a new wettability model that estimates the contact angle and consists of five terms based on the Young-Laplace equation. We use the Nelder-Mead optimization algorithm to determine the model-parameter values that produce the best fit of experimental observations. The contact angle estimates produced by our model are also verified against those calculated by Extended-Derjaguin-Landau-Verwey-Overbeekand (EDLVO) theory and are validated using UTCOMP-IPhreeqc to simulate five limestone Amott tests from the literature.
The Blind-testing test reveals that our model is predictive of the experimental data (R2 = 0.81, RMSE = 12.5). While reducing the tuning parameters by half, our model is comparable to and–in some cases–even superior to the EDLVO modeling in predicting the contact angle measurements. We argue that EDLVO modeling has 10+ parameters, and the individual errors associated with each parameter could lead to wrong predictions. Amott-test simulations show excellent agreement between the proposed wettability-alteration model and experimental data. The rock's initial wettability was measured to be strongly oil-wet, with a negative Amott index and recovery factor around 5%, corroborating the calculated contact angle of 160 degrees. The recovery factor increases to about 20-35% as the rock becomes more water-wet after interaction with engineered water (contact angle changes to 90-64 degrees). Further analysis indicates the proposed model's capability to capture significant wettability-alteration trends. For example, we report increased water-wetting as brine ionic strength decreases, depicting the low-salinity effect. In addition, our model resulted in better convergence in some of the simulated core floods compared to EDLVO modeling. We conclude that our physics-based and data-driven model is a practical and efficient approach to predict rock-brine-oil wettability.
State-of-the-Art Laboratory Methods for Chemical EOR
Authors: Dean Robert Matthew , Britton Chris James , Driver Jonathan William , Pope Gary Arnold 
Published: April 2022

Abstract
The objective of this paper is to present a critical review of best practices for conducting laboratory experiments to evaluate chemical EOR. Some legacy methods and procedures are outdated and need to be updated to address their inherent flaws. This paper presents the reasons improvements are necessary and serves to introduce or highlight better methods, while providing a good resource to review past studies. Common laboratory methods and procedures used to evaluate chemical EOR are critically reviewed and discussed for polymer flooding, surfactant-polymer flooding, alkaline-surfactant-polymer flooding, alkaline-co-solvent-polymer flooding specifically but also apply to similar processes. The laboratory methods for evaluating chemical EOR include surfactant phase behavior, coreflooding, chemical adsorption and retention measurements, polymer residual resistance factor measurements, polymer transport, polymer filtration ratio measurements, polymer stability. The best methods and procedures for these and other measurements should take into account how the laboratory measurements will be used for making field-scale performance predictions, the type of oil reservoir, the chemical EOR process and many other factors. Conducting corefloods with a low residence time is an example of a common mistake. New or improved methods are introduced or highlighted to bring best practices to the forefront. New methods that are highlighted include Residence Time Distribution Analysis to determine polymer retention and IPV, polymer transport in cores with two-phases present, and the addition of solvents/pre-shearing for improved polymer transport. The state-of-the-art laboratory methods and procedures discussed herein yield more accurate, more scalable data that are needed for reservoir simulation predictions and field-scale applications of chemical EOR. The recommended best practices will provide a better understanding needed to help select the appropriate chemicals and to determine the optimal chemical mass for field applications of chemical EOR.
Analytical Method for Forecasting ROZ Production in a Commingled MOC and ROZ CO2 Flood
Authors: Hampton David Wayne , Wagia-Alla Ahmed 
Published: April 2022

Abstract
Residual Oil Zone (ROZ) refers to a formation whose discovery saturation equals the rock's residual oil saturation. The ROZ makes up an excellent target for CO2 flooding since this oil is immovable by primary and secondary production processes. The San Andres ROZ has been recognized as an extensive residual oil saturated fairway in the Permian created during the Leonardian uplift, which caused spillage from the natural traps (Melzer, 2006). It has been developed through CO2 flooding in several fields across the Permian, including the Denver Unit in the Wasson San Andres formation, where it was developed years after the Main Oil Column (MOC). Both zones are producing from commingled producers and are flooded by commingled or dedicated injectors. This commingled configuration presents a challenge in discerning the production coming from each zone. In this paper, we will present an analytical approach to distinguish between MOC and ROZ production without the need for numerical simulation or costly well interventions such as production logging or zonal isolation.
A sector of the Denver Unit's CO2 flood was used as an example in this paper. Dimensionless analysis, which entails normalizing production and injection to the target pore volume, was used along with the Pulser process (Liu, Sahni, and Hsu, 2014; informal communication with Deepak Gupta, 2019) to history-match MOC production and then extrapolate it using zonal injection obtained from injection profile logs. This calculated MOC production is then subtracted from the total production to calculate ROZ production, with its dimensionless response function fitted with Pulser for forecasting. Additionally, a fully compositional numerical simulation of the same area was history-matched and used to validate the approach mentioned above.
The results of the analytical approach showed excellent agreement with the numerical simulation results and with historical performance through multiple years. A few challenges presented themselves, such as pattern-to-pattern interference, the quality of injection profile logs, and pattern reconfigurations, which we will discuss below along with limitations and assumptions that must be considered when using this approach.
The methodology presented in this paper presents a simple method to allocate and forecast MOC and ROZ performance individually despite changes in injection throughput, based on injection distribution without the need for complex simulation or costly well configuration. This approach could also be applied to any commingled flood that meets the criteria outlined in this paper.
Evaluation of Carbon Footprint for a Hydrocarbon Foam EOR Field Pilot
Authors: Castellanos Diaz Orlando , Katiyar Amit , Hassanzadeh Armin , Crosley Matt , Knight Troy , Rozowski Pete 
Published: April 2022

Abstract
EOR intervention methods, such as surfactant injection for in-situ foam as a conformance improvement, help increase energy efficiency of the EOR process. However, it is very important to have a calculation framework that identifies actual values to these energy efficiency benefits and contrast them with the energy requirements of making the EOR intervention methods work in the field. Such a calculation framework was introduced in this work with a life cycle thinking approach. To showcase the calculation methodology, a foam assisted gas-EOR process trial was used as an example of a successful EOR intervention technology, specifically a field pilot from a trial between Dow Chemical and MD America Energy (SPE 201199). Injection and production data, together with industry averages on electricity generation, gas compression, and water treatment, were utilized to calculate energy input into the process prior, during, and post-trial. Energy differences due to the foam technology deployment were translated into carbon footprint equivalence and contrasted with the carbon footprint of manufacturing and transporting the surfactant. A benefit-to-burden carbon footprint ratio of 21 was obtained, which means that for every carbon units emitted while producing the foaming agent 21 carbon units would be saved when implementing the technology as opposed to not implementing it. On a per barrel basis, the carbon footprint of the technology is reduced by more than 50% when using the foam additive than the baseline, even including the carbon footprint of making the material. The calculations also showed that the gas compression and separation steps dominate the energy inputs of the EOR intervention method.
Carbon Capture, Utilization, and Storage in the Context of Petroleum Industry: A State-of-the-art Review
Authors: Magzymov Daulet , Dindoruk Birol , Johns Russell T. 
Published: April 2022

Abstract
The petroleum industry is one of the few industries that deal with high-pressure high-temperature conditions involving complex fluid behavior, rock and fluid interactions, and flow dynamics in the subsurface. Moreover, petroleum industry has the critical domain expertise to reach and manage deep reservoirs both onshore and offshore. These capabilities and know-how put petroleum industry at the forefront to capture, utilize, and store carbon dioxide and other greenhouse gases in the subsurface. The objective of this paper is to review the existing body of literature and outline the most prominent methods or options to manage carbon dioxide (CO2) and other gases.
We review the rigorous efforts presented in the literature to implement carbon capture, utilization, and storage (CCUS) projects, in the context of technological challenges, capacities, and perspectives. We categorize the options into three groups: 1. Currently available technologies; 2. Near-future technology; 3. Long term technology. Categories (2) and (3) are discussed in terms of cost and scale-up, where both can be an impediment for wide-scale deployment. Many such options are functions of the energy price and as well as local incentives. Therefore, while focusing on the technical aspect we also discuss some of the enabling factors for its application. Some of the elements of (2) are also related to source-sink match yet direct air capture is being highlighted as a remedy of this issue while the costs are still an impediment for widespread use. We examine methods that use carbon dioxide and other gases to improve the recovery of hydrocarbons and simultaneously store concentrated CO2 in the subsurface. Our main conclusion in this review paper is that the petroleum industry has all of the tools and expertise to implement and adopt CCUS projects and to contribute to the sustainable future from a technological perspective.
We show that there are many well-established methods in the petroleum industry that can be used directly for CCUS purposes. The petroleum industry may be regarded as a contributor to carbon and other gas emissions, however, in this paper we present the reverse concept that the petroleum industry has all the necessary tools and expertise to capture, utilize, and store carbon gases. The perspective presented in this paper will help petroleum industry to recognize its own strengths with the goal to reduce emissions not only within petroleum industry but also to lead carbon emission reduction efforts from other industries.
Confirmation of Polymer Viscosity Retention at the Captain Field Through Wellhead Sampling
Authors: Johnson Geoffrey , Hesampour Mehrdad , Toivonen Susanna , Hanski Sirkku , Sihvonen Stina , Lugo Nancy , McCallum Jennifer , Pope Michael 
Published: April 2022

Abstract
The Ithaca-operated Captain field is located in Block 13/22a in the U.K. sector of the North Sea, 130 km northeast of Aberdeen, in a water depth of 360 ft. The Captain Field has an adverse mobility ratio across all the producing reservoirs and so has undergone improved oil recovery by polymer flooding since 2011 using Anionic polyacrylamide (HPAM) in liquid form. This paper presents recent offshore wellhead sampling from the Captain facility that confirms high polymer solution viscosity retention from a producing well, even after significant mechanical degradation through the Electrical Submersible Pumps (ESP), which is used for artificial lift.
The continuing commercial success of the Captain Field polymer flood is underpinned by maintaining polymer viscosity throughout the system. High polymer returns, combined with declining oil rates, may result in the continued operation of these wells to be unattractive. This paper summarises the data used to shut-in mature wells that are producing polymer to the surface, to enable the polymer flood to continue displacing oil to offset production wells.
Samples were collected from the wellhead in oxygen free conditions into pressurized cylinders. The measurements in laboratory were taken inside a glove box to avoid oxygen ingress. The absence of oxygen was confirmed through measurements of dissolved oxygen and redox potential. Viscosity of the solutions have been measured with Brookfield viscometer inside the glove box and the results were compared to the expected viscosity from fresh non-degraded polymer solution. The expected viscosity was determined using a concentration – viscosity curve of a fresh polymer in synthetic Captain brine. Polymer solution concentration is measured on-site using KemConnect™ EOR, a time resolved fluorescence method, the collected samples were subsequently confirmed with size exclusion chromatography (SEC) in the laboratory. The polymer concentrations measured from these wellhead samples with KemConnect™ EOR were in the region of 700-900 ppm.
Previously collected downhole viscosity samples confirmed &gt;70% viscosity retention prior to being produced through the ESP, while 50-80% of the original viscosity was found to be retained after production through the ESP to the surface facilities under anaerobic conditions for the range of concentrations sampled. These findings demonstrate the resilience of the polymer product to degradation in a real-world operational setting. It also provides data that may be used to estimate the expected downhole polymer solution viscosity from wellhead samples for defined operating conditions. The ability to estimate polymer solution downhole viscosity retention from wellhead samples provides a simpler and less expensive method of estimating viscosity retention than downhole sampling, which is especially useful for wells that do not have downhole access for sample collection.
Potential and Challenges of Foam-Assisted CO2 Sequestration
Authors: Rossen William R. , Farajzadeh Rouhi , Hirasaki George J. , Amirmoshiri Mohammadreza 
Published: April 2022

Abstract
Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome.
CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping, dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geological traps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden. Maximizing storage while minimizing overburden stress in the near term depends on residual trapping in the swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiency and capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foam applications.
Foam increases both sweep efficiency and residual gas saturation in the region swept. Both properties reduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foam generation, better injectivity, and better prospects for long-distance foam propagation at low pressure gradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil, as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency while reducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helps equalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reduces gravity segregation of CO2.
Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, either through pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-design strategy.
We review foam field trials for EOR and the state of the art from laboratory and modeling research on CO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.
Viscous Oil Polymer Flood Milne Point Field Case History Concept to Full Field Implementation
Authors: Edwards Reid , Aitkulov Almas , Redwine Connor , Cunha Katherine 
Published: April 2022

Abstract
Milne Point Field initiated the first polymer injection pilots on the North Slope of Alaska starting in 2018 and have rapidly progressed to full-field polymer injection within four years. The two initial pilot projects injected at an initial total rate of 6,000 bwpd utilizing 5 horizontal injection wells. Expansion activities began two years later in 2020 with the addition of 4 additional polymer injection units. By the end of 2021, total field polymer injection rate was 32,000 bwpd via 29 horizontal injection wells. Targeted reservoirs have average permeabilities ranging from 100 – 1000md and in-situ oil viscosities ranging from 40 cp to 1300 cp. Both secondary and tertiary floods are being conducted in both greenfield and brownfield development areas each with varying, yet all promising, results. The highest observed recovery is in a secondary polymer flood pattern at 27% of OOIP with an oil viscosity of 850 cp and no water breakthrough observed to date. Responses in injection well injectivities have ranged from as low as 0% up to 50% loss to date and are observed to be correlated by well spacing and total reservoir mobility. Multiple polymer injection designs exist throughout the field which were driven by existing infrastructure, specific needs from pattern to pattern, and increased learning over time. A logistics system has also been successfully developed that allows for large scale polymer flood on the North Slope of Alaska. The intent of this paper is to a.) provide sufficient historical context to give insight into field development when polymer flood was started b.) highlight what has been done to date in regards to moving from polymer flood concept to near full field expansion and c.) present observed results with the hope that they can help set expectations for future polymer flood projects.
Use of Horizontal Injectors for Improving Injectivity and Conformance in Polymer Floods
Authors: Hwang Jongsoo , Zheng Shuang , Sharma Mukul , Chiotoroiu Maria-Magdalena , Clemens Torsten 
Published: April 2022

Abstract
Several field cases have demonstrated polymer injection in a horizontal well increases oil recovery. It is important to maintain high injectivity while preventing injection-induced fractures to ensure good reservoir sweep. Our primary goal in this paper is to better understand polymer injection data from horizontal injectors in the Matzen field using a fully integrated reservoir, geomechanics, and fracturing model.
By simulating polymer injection history, we present several advantages of horizontal injectors over the vertical wells. Horizontal injectors delay fracture initiation and provide better tolerance to polymer plugging on the wellbore surface. Simulations explain the measured PLT data of fluid distributions influenced by accumulated polymer deposition in multiple zones. We show that gradual injectivity decline is attributed to both polymer filter cake buildup and high-viscosity, shear-thickening zones created around the wellbore. The field case simulation also clarifies the flow distribution in different sands and how polymer rheology affects this. This distribution is found to be different than for water injection.
Results from periodic acid treatments clearly show that free-flowing particles in the polymer solution are responsible for formation damage. Polymer plugging and the viscous pressure drop in the shear-thickening zone are the primary factor affecting the measured injection pressure. Based on the strong near-wellbore viscosity impact, geomechanical simulations identify reservoir zones prone to fracture growth during long-term injection, and we suggest strategies to avoid injection induced fractures that can lead to poor conformance.
Evaluation of Historical and Ongoing Double Displacement Process in Yates Field Unit
Authors: Mohebbinia Saeedeh , Pennell Stephen Peter , Valdez Raul , Eskandaridalvand Kiomars 
Published: April 2022

Abstract
Implementation of a second Double Displacement Process (DDP2) has been evaluated for Yates Field Unit (YFU). A DDP2 Demonstration Area Project has been designed to test DDP2 in a mature, high recovery area of the field. A detailed, geologically based reservoir description was used to build a simulation model for the DDP2 pilot area to study the DDP process and evaluate DDP2 performance. Initial saturations and relative permeability curves were generated based on a capillary pressure based Saturation Height Function (SHF) study. The fracture system was simulated using a hybrid dual porosity/permeability system. A 9-component equation of state (EOS) was used to model the YFU fluid properties. Capillary pressure of imbibition is used to capture the effect of hysteresis and oil trapping in the zones invaded by the aquifer during primary depletion. The simulation model has been tuned against historical performance since 1927, focusing on the first DDP process (DDP1) implemented over 1992-2000. Matching historical production/injection, field pressure and fluid contacts data were the history matching objectives. The DDP2 pilot project will include lowering 31 Horizontal Drain Hole (HDH) lateral completions by 25 feet to lower the contacts. The tuned model has been used to generate flow streams for different forecasting scenarios utilizing the DDP2 process. Forecast results show incremental oil recovery by lowering the contacts by 25 feet during the DDP2 phase. This paper presents a comprehensive study of YFU DDP1 process and evaluation of the second DDP process by a 3D numerical simulation model. The simulation model is used to improve understanding of the complex Gas-Oil Gravity Drainage (GOGD) and Gas Assisted Gravity Drainage (GAGD), and provide forecasts for the DDP2 process. Success of the pilot will result in extending the field life another 10-20 years.