bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lab Investigation of EOR Potential for a Stack Pilot
Authors: Jiang Haifeng , Antle Ryan , Gao Panqing , Murrell Glen 
Published: August 2020

Abstract
Laboratory studies of unconventional reservoirs are faced with considerably more challenges than those of conventional reservoirs. The assessment of Enhanced Oil Recovery potential in unconventional reservoirs (UCR EOR) in particular needs to address the characterization of static and dynamic properties given the tightness of the rocks, available sample size and simulation of EOR under elevated pressure and temperature conditions. This paper summarizes a laboratory study designed and performed for a potential EOR pilot utilizing cyclic gas injection (Huff-n-Puff) in the Sooner Trend Anadarko Canadian Kingfisher (STACK) shale play in Oklahoma. The lab study focuses on characterizing the rock-fluid interactions as well as upscaling key parameters for the field-scale modeling and simulation.
A systematic approach was followed in the design of a laboratory program specific to the characteristics of rock/fluid interaction and the proposed injection scheme of a cyclic gas injection pilot. Digital Core Analysis (DCA) incorporating micro CT, SEM and FIB-SEM analyses were performed in order to determine basic petrophysical properties at micro scale, with capillary pressure and relative permeability curves simulated digitally. Porosity and relative permeability end points were also measured on preserved STACK core plugs. Minimum miscibility pressure (MMP) measurements of field separator gas and STACK crude oil was performed with a rising bubble apparatus (RBA). Finally, a huff-n-puff experiment was designed and performed within a custom pressure cell to study the recovery efficiency at the existing core sample scale.
Digital Core Analysis (DCA) has been shown to reliably produce petrophysical properties for tight STACK cores. Laboratory miscibility pressure measurements were conducted at reservoir conditions (4,500 psi and 183 °F) using field crude samples and the associated gas composition. Seven injection/production cycles were applied to a re-saturated standard core plug with oil production observed and measured in the effluent. Cyclic injection continued until no further oil could be visually observed in the effluent. A customized 2-stage drawdown was incorporated to provide input for the recovery process. The total recovery after seven cycles reached 82 %OOIP.
This work provides the first rock and fluid analysis integrating digital and traditional approaches for assessment of EOR potential in unconventional reservoirs such as those found in the STACK. This systematic approach presents properly designed and executed laboratory experiments without leaving out key formation and fluid variables. This workflow can be applied in similar UCR EOR studies to lay a solid foundation for appraising UCR EOR potential and providing reliable inputs for upscaling to the field level studies.
Alkali-Surfactant-Polymer ASP Flooding Field Test Using Horizontal Wells: Design, Implementation and Evaluation
Authors: Guo Hu , Jiang Guipu , Zhang Jin , Hou Jirui , Song Kaoping , Song Qingjia 
Published: August 2020

Abstract
An Alkali-surfactant-polymer (ASP) field test using 2 horizontal injectors and 3 horizontal producers (HASP) was conducted to check the combination of horizontal wells and ASP flooding technology as well as recovering remaining oil in higher position due to gravity effect. Designed chemical slug is 0.675PV with four slugs (0.0375PV pre-slug high concentration polymer+ 0.30 main ASP slug+0.15PV vice ASP slug+0.20PV post polymer slug). This four-slug design was very common in many previous field tests, although this practice remained to be optimized. ASP slug viscosity was designed 40 cP at injectors wellhead and ultra-low interfacial tension (IFT) between ASP and Daqing oil was basic requirement. Actual viscosity of chemical slugs was well implemented, while the chemical slug size was increased. Reference water flooding started in January 2008 until May 2009 when pre-slug started. ASP slug started in January 2010, and finished in April 2012. Post polymer slug started in April 2013 after vice ASP slug. As of December 2015, 0.919 PV chemical slug with dosage 1890.23 mg/LPV and 0.323 PV post water flooding have been injected. Incremental oil recovery factor (IORF) is 29.66% original oil in place (OOIP) and IORF in main ASP injection stage is 17.46%. Vice ASP and post polymer slug contributed an IORF of 4.63% and 3.64% OOIP respectively. HASP IORF was 10% larger than the other vertical well ASP (VASP) with an IORF of 20% OOIP. Water cut decrease was 3.7% higher than VASP. Injection index and fluid production index were higher than VASP. Chemicals breakthrough was later than VASP. Horizontal well pattern was predicted better than combination of vertical and horizontal wells. However, up to present, whether HASP has been widely used in Daqing remains unknown. This test indicated that horizontal wells can be used to recovery gravity caused bypassed remaining oil in the upper layers even separate layer injection is adopted. Gravity effect should be given more attention for thick layers or multiple layers. Incremental oil recovery in HASP can be as high as 30% OOIP under Daqing reservoir condition.
Development of Swelling-Rate Controllable Particle Gels to Control the Conformance of CO2 Flooding
Authors: Bai Baojun , Sun Xindi 
Published: August 2020

Abstract
This paper summarizes the work conducted for the project "Development of Swelling-Rate-Controllable Particle Gels to Enhance CO2 Flooding Sweep Efficiency and Storage Efficiency", a three-year project funded by the US Department of Energy. The overall objective of this project is to develop a novel particle- based gel technology that can be used to enhance CO2 sweep efficiency and thus improve CO2 storage in mature oilfields. In this paper, we first provide our classification of conformance problems in CO2 flooding fields, and addresses the importance of developing novel particle gels to efficiently control CO2 flooding conformance in oilfields. Then, we highlighted our research results about the three types of novel preformed particle gels (PPGs) that we successfully developed, including AMPS-based PPGs, CO2 responsive PPGs (CR-PPG) and CO2 resistance PPGs (CRG). The developed particles is size controlled from nanometer to millimeters, and the swelling time can be controlled from a few hours to three months, depending on the type of conformance problems to be solved. The millimeter-sized PPGs (10 um to a few millimeters) are obtained through bulk gel synthetization, cutting and drying, mechanically crushing and screening process, and they are mainly used to solve the conduits, fractures, or fracture-like channels problems. The nano- and micro-sized polymer particles are synthesized through either emulsion polymerization or dispersion polymerization process under scCO2, and they are mainly designed to solve the matrix problem for far-wellbore conformance control. Overall, the project has provided a series of reliable and cost-effective swelling-rate-controllable particle gel products that can be used to solve the different reservoir conformance problems for CO2 flooding, which will not only aid in improving oil recovery for CO2 flooding projects but can also help to improve CO2 storage efficiency for CO2 storage projects.
Enhanced Oil Recovery for Liquid-Rich Unconventional Shale Reservoirs Using Low-Salinity Surfactant and Wettability Altering Dilute Surfactants
Authors: Uzun Ozan , Torcuk Mehmet Ali , Kazemi Hossein 
Published: August 2020

Abstract
Classical waterflooding methods which rely on water displacing oil are not plausible in unconventional shale reservoirs because of the low permeability of such reservoirs because the pressure gradients required to push the water through the reservoir matrix rock is impractical. However, when the shale reservoir is stimulated via multistage hydraulic fracturing a large number of microfractures form which provides a preferred pathway when subsequently water is injected into the reservoir. If this water has low salinity compared to the salinity of the resident brine in the matrix pores, an osmotic pressure gradient establishes between microfractures and the matrix pores that would cause water to enter the matrix pores and pushing oil out. In oil-wet shale reservoirs, this osmotic pressure allows brine imbibition into the matrix that promotes counter-current flow of oil into the fractures. In our research, this phenomenon was studied via carefully designed osmotic imbibition experiments that used low- salinity brines. Furthermore, adding a simple surfactant, or a wettability altering chemical, not only could enhance imbibition of water into the matrix, it can also create a low-IFT environment that would break the oil droplets into smaller ones to facilitate oil movement out of the micro and macro fractures to enhance oil recovery from the matrix. To scale laboratory results and observations to the field conditions, a multi-component mass transport model that includes advective and diffusive transport of water molecules was developed and used to match experimental results. We will present the core imbibition and numerical modeling results that indicate that low salinity brine plus a dilute surfactant enhances oil production.
This paper pertains to a research effort conducted to assess the potential of a new EOR method, which involves the use of a mixture of low-salinity brine and low-concentrations of a surfactant or wettability altering chemical. In what follows, we will present the core flooding and numerical modeling results pertaining to the research objective. The results are intended to be used as the basis for designing economic EOR field applications in unconventional shale reservoirs.
Evaluation of Seawater Based Surfactant Polymer Formulation in a Single Well Test Offshore
Authors: Harris Robert R. , Paramanathan Subashini , Dickson Sara-Jane , Bouwmeester Ron C. , Southwick Jeffrey G. , Keijzer Efraim , van Rijn Carl H. , Batenburg Diederik W. 
Published: August 2020

Abstract
The effectiveness of a low complexity chemical flooding formulation that was developed for application in offshore environments was evaluated in a single well test offshore South China Sea. The SP formulation uses seawater with no additional water treatment beyond that which is normally performed for water flooding (filtration, de-oxygenation, etc.). The ability to use a formulation based on only seawater avoids water treatment and reduces complexity for commercial implementation.
The Single Well Test was conducted in an existing producer with its wellhead on an existing production platform offshore. The injection facilities were placed on work barge that also had accommodation to house the people that executed the injection test. The facilities on the barge consisted of seawater lift and filtering equipment, surfactant and polymer mixing capability, and high-pressure pumps to deliver the mixed fluids through a flexible high-pressure hose to the platform. A laboratory to support the QA/QC of the injected fluids was also installed on the barge. Standard Single Well Chemical Tracer test procedures were applied to determine the remaining oil saturation after waterflood and after injection of the SP formulation.
The Single Well Test was completed in accordance with the objective without any recordable HSSE cases ahead of schedule. The composition of the injected SP formulation was well within the specifications resulting in good injectivity of the formulation. The single well tracer tests conducted after the SP and polymer injection indicate that the residual oil saturation was reduced to values between 7-9% (Sorc).
The main contributions described in the paper are:
demonstration that a seawater-based SP formulation can be effectively mixed and injected from a barge offshore. the interpretation of the single well tracer tests conducted after the SP and polymer injection indicate that the residual oil saturation was reduced to values similar to those observed in core floods with the SP formulation in the laboratory.
Simulation of Advanced Waterflooding in Carbonates Using a Surface Complexation-Based Multiphase Transport Model
Authors: Abu-Al-Saud Moataz , Al-Saleh Salah , Ayirala Subhash , Yousef Ali 
Published: August 2020

Abstract
Understanding the injection water chemistry effect, in terms of both salinity and ionic composition, is becoming crucial to increase oil recovery from waterflooding in carbonate reservoirs. Various studies have shown that that surface charge alteration is the main mechanism behind favorable wettability changes toward water-wet conditions observed during the injection of controlled ionic composition water in carbonates. Therefore, the synergistic coupling between multiphase transport and electrokinetics of brine/calcite and brine/crude oil interfaces becomes important to optimize injection water compositions for enhanced oil recovery in carbonates.
In this investigation, the electrokinetic interactions of brine and crude oil in carbonates are accounted for and coupled with the multiphase Darcy flow model. The electrokinetic interactions are parametrized by the zeta-potential values of brine/calcite and crude-oil/brine interfaces, which are determined using a Surface Complexation Model (SCM). The SCM zeta-potential parameters are computed based on the local concentration of aqueous ions that follow the transport equation. The relative permeability and capillary pressure curves are altered based on zeta potential shifts, which resembles the wettability alteration process. The SCM zeta potentials are compared with the experimental zeta-potential measurements, while the multiphase transport model coupled with geochemistry is validated through a comparative coreflood experimental data reported in the literature.
The SCM results governed by specified surface geochemical reactions agreed well with zeta-potential measurements obtained at both calcite/brine and crude-oil/brine interfaces. The coupled geochemical SCM with multiphase transport model accurately matched both recovery and pressure drop data from forced imbibition tests reported by Yousef et al. (2011) in both secondary and tertiary modes. The generated relative permeability curves followed Craig's rules in shifting the wettability from oil-wet toward water-wet conditions for advanced waterflooding processes in carbonates. These results confirm the robustness of proposed model based on validated SCM electrokinetic interactions. The development of such a coupled geochemistry based multiphase transport model is an important step to simulate advanced waterflooding processes in carbonates at reservoir scale by taking into account of more representative physicochemical effects.
The novelty of this work is that it validates the SCM results with experimental zeta-potential data for different injection water compositions. Also, the applicability of coupled SCM with a multiphase transport model is successfully demonstrated by history matching the experimental coreflood data. The developed model and new findings shed some light on the importance of lower salinity and controlled ionic composition during fluid flow and oil recovery in complex carbonate formations.
CO2 Foam Pilot in a West Texas Field: Design, Operation and Results
Authors: Mirzaei Mohammad , Kumar Deepanshu , Turner Dwight , Shock Austin , Andel Derek , Hampton David , Knight Troy E. , Katiyar Amit , Patil Pramod D. , Rozowski Peter , Nguyen Quoc P. 
Published: August 2020

Abstract
In this paper, we describe the design, implementation and results of a CO2 foam pilot in a mature CO2 flood in West Texas. The objective of the pilot was to demonstrate improved conformance/sweep efficiency of the CO2 foam over CO2 WAG injection. Laboratory experiments to guide design of the flood and the monitoring program to understand and model flood performance are described. Monitoring included rate and pressure tracking, injection profiles and inter-well tracer programs before and during the foam flood. While changes in injection rate and injection profile confirmed the formation of strong foam near the wellbore and redistribution of fluids in the injectors, oil response was weak, with significant oil gain observed in one of the four patterns. The gas production rate also changed very slightly from the baseline conditions. The comprehensive monitoring program in this pilot provides new insights into effectiveness of CO2 foam in actual field applications. The results from this pilot may help to better screen and design future foam injection pilots.
A Reconstructed Core-Scale Model of the Lower Eagle Ford Shale Through FIB-SEM, SEM-EDS, and Microscopy for Gas Huff-n-Puff Simulation
Authors: Cudjoe Sherifa , Fu Qinwen , Tsau Jyung-Syung , Barati Reza , Goldstein Robert , Nicoud Brian , Baldwin Amanda , Zaghloul Jose , Mohrbacher David 
Published: August 2020

Abstract
Simulation of gas huff-n-puff (HnP) in core models is often simplified by assuming homogenous, isotropic models, which are not representative of fine-grained multi-component shales with multiple types of pore space and anisotropic permeability. According to the previous literaturte, history matching of a 6-cycle HnP process and tuning of cross-phase effective diffusion coefficients using a homogeneous model presented a need for a detailed core-scale geomodel to capture variations in effective diffusion coefficients as a result of heterogeneity experienced during each diffusion cycle. A workflow for reconstructing a corescale volume of Lower Eagle Ford (LEF) shale is presented that combines rock characterization using high-resolution digital images at the micrometer/nanometer scale and transmitted light microscopy to provide models for detailed heterogeneity of the LEF shale for gas huff-n-puff simulation.
Core-scale models form LEF are reconstructed using high-resolution SEM-EDS and FIB-SEM images. SEM-EDS and FIB-SEM images were coupled with transmitted light microsocpy and micro-computed tomography (CT) to constrain facies distribution, discrete fracture networks and to distribute petrophysical properties. The reconstruction method produced a more representative core model of the LEF and can be used for simulation of core-scale huff-n-puff experiments conducted in a diffusion cell.
Common grain types observed in the SEM-EDS images at different resolutions include detrital quartz, calcite, microfossils and fragments, microfractures, clay minerals, traces of dolomite, and albite. Also common is diagenetic calcite, pyrite, kaolinite, and secondary organic matter (OM) infilling the chambers of foraminifer tests ("forams") and other mineral pores. FIB-SEM analysis provided organic bulk transport properties including tortuosity and permeability within the generated pore network models of the LEF shale. Transmitted light microscopy provided the lamina-scale variation of samples from the LEF shale to be incorporated in the core model.
A detailed workflow is presented for reconstructtion of a LEF shale core-scale model using high- resolution images and photomicrographs. The model detailed the original core morphology, multiple pore space, and multicomponent mineral distributions for gas huff-n-puff simulation. Several realizations of the geomodel were prepared by varying mineral distributions within the layers as well as the range of petrophysical properties in order to present different gas huff-n-puff simulation scenarios. This provided the compositional model using a sophisticated heterogeneous component of tortuosity/permeability instead of a homogenous and isotropic model.
Chemical EOR While Fracturing: An Experimental Study for Evaluating Nanoparticle Additives
Authors: Yuan Lin , Zhang Yanze , Ahmad Yusra Khan , Dehghanpour Hassan 
Published: August 2020

Abstract
In this paper, we evaluate the idea of adding nanoparticles (NPs) in fracturing water to enhance its wetting affinity to oil-wet pores and to mobilize part of the oil during the extended shut-in periods. We analyzed the performance of two different nanoparticle additives (NP1 and NP2) on core plugs collected from the Montney Formation. Additive 1 is a colloidal dispersion with highly surface-modified NPs and additive 2 is a micellar dispersion with highly surface-modified silicon dioxide NPs, solvents and surfactants. The proposed methodology consists of the following steps: 1) Characterizing wettability of the candidate rock samples under different conditions of brine salinity and NP concentrations through dynamic contact-angle measurements, 2) Evaluating NP-assisted imbibition oil recovery during the shut-in period by conducting systematic counter-current imbibition tests, and 3) Evaluating pore accessibility by comparing the mean size of the particles formed in the NP solutions measured by dynamic light scattering (DLS) method with pore-throat size distribution of the core plugs obtained from scanning electron microscopy (SEM) and mercury injection capillary pressure (MICP) analyses.
The dynamic contact-angle results show that the core plugs are oil-wet in the presence of reservoir brine and fresh water as base fluids, and water-wet in the presence of the NP solutions. Consistently, the measured oil recovery factor (RF) by the NP solutions is 5% to 10% higher than that by the base fluids, which can be explained by the wettability alteration by NPs. Comparing the mean particle size of the NP solutions with the pore-throat size distribution of the plugs evaluates pore accessibility of core plugs. From MICP and SEM analyses, most pores of the rock samples have pore-throat radius in the range of 4 to 100 nm. The mean particle size of NP1 in low-salinity water is less than 30 nm while that of NP2 in low-salinity water is around 40 nm. The NPs can pass through most of the pore throats under low-salinity conditions. This is supported by fast and spontaneous imbibition of the NP solutions into the oil-saturated core plugs, compared with the base cases without the NPs solutions. When salinity increases, the particle size for NP solutions increases to more than 200 nm. Therefore, fewer pores may be accessed by NPs under high-salinity conditions if the NP solutions are not optimized for such conditions.