bluuebunny/crossref_metadata_2025_split huggingface dataset:
Boosting Oil Recovery in Unconventional Resources Utilizing Wettability Altering Agents: Successful Translation from Laboratory to Field
Authors: Kazempour Mahdi , Kiani Mojtaba , Nguyen Duy , Salehi Mehdi , Bidhendi Mehrnoosh Moradi , Lantz Mike 
Published: March 2018

Abstract
In recent years, the United States (US) has experienced a resurrection in hydrocarbon recovery owing to the extraction of oil and gas from unconventional resources. Due to the ultra-low permeability nature of these reservoirs and their oil-wet characteristics, oil production declines are steep and oil recoveries remain very low (&lt; 12% of OOIP). This challenge endures even with the assistance of hydraulic fracturing advancements and well spacing optimizations. The billions of barrels of remaining oil is a good target for chemical enhanced oil recovery (EOR) technologies.
In this study, after comprehensive laboratory testing, a series of customized chemical formulations was developed to improve oil recovery under the challenging conditions of the Middle Bakken and Niobrara formations (temperature &gt;110 °C, salinity&gt;220,000 ppm, and hardness&gt;15,000 ppm). To examine the performance of the selected formulation in the field-scale, a single well enhancement trial was carried out. A detailed review of the lab and field data (pre-and post- treatment) is discussed in this study. Oil rate decline analysis and numerical simulations were used to obtain more insight about the true effectiveness of the chemical treatments. The results of this field trial reveal that injecting a proper wettability altering agent can improve oil recovery from shale oil reservoirs by up to 25% of the estimated ultimate recovery (EUR). The results of numerical simulations also show that the additional oil recovered in this field trial cannot be achieved by either well shut-in or straight water injection.
The lessons learned from this study provide practical information to optimize similar field trial designs leading to more profitable projects. The concepts and information here can be also translated to other unconventional basins and gas condensate or wet/dry gas reservoirs.
Fluoroacrylate Polymers as CO2-soluble Conformance Control Agents
Authors: Enick Robert M. , Lee Jason J. , Cummings Stephen D. , Zaberi Husain A. , Beckman Eric J. , Dailey Chris , Vasilache Mihai 
Published: March 2018

Abstract
In this study, we propose a CO2-polymer solution for conformance control agent in order to divert the subsequently injected CO2 away from thief zones and toward lower permeability oil-rich zones. A novel CO2-soluble polyfluoroacrylate (PFA) was synthesized. PFA is an amorphous, sticky, transparent, homopolymer that dissolves readily in CO2 at temperatures and pressures commensurate with CO2 EOR. PFA is based on a monomer that contains six (rather than eight) fluorinated carbons, thereby eliminating the environmental concerns associated with possible degradation products. Because PFA has high molecular weight, the addition of ~1wt% PFA to CO2 thickened CO2 by a factor of about four. Nnumerous core floods were then conducted to determine if the adsorption of PFA onto the rock surfaces could provide conformance control. When a CO2-PFA solution is injected into porous media, a portion of the dissolved PFA strongly adsorbs onto the mineral surfaces, regardless of what fluid was originally present in the pores. Because PFA is highly hydrophobic and oil-phobic, the thin PFA film deposited on the rock surfaces changes the wettability and dramatically reduces the permeability of the rock (especially sandstone) for subsequently injected fluids. This strong adsorption and change in wettability significantly reduces the permeability of the rock to subsequently injected brine or CO2. Dual parallel core floods were conducted to demonstrate the efficacy of PFA-CO2 solutions for conformance control. Excellent results were obtained when a CO2-PFA solution was injected solely into an isolated high permeability (80 mD) Berea sandstone core (the thief zone) that was previously flooded with brine and CO2. After this treatment, the Berea core was then placed in parallel with a 20 mD Carbon Tan sandstone core. All of the subsequently injected CO2 was diverted to the Carbon Tan core. Similar results were obtained with dual parallel limestone cores. To the best of our knowledge, PFA is the first known example of a CO2-soluble polymeric conformance control agent.
Evaluation of Viscosity Loss of Viscosified Brine Solutions Due to Shear Degradation in Distribution System Components
Authors: Theriot Timothy P. , Linnemeyer Harold , Alexis Dennis , Malik Taimur , Perdue Charles 
Published: March 2018

Abstract
High molecular weight HPAM's tend to be highly shear sensitive. Various components of polymer mixing and distribution systems pose risk to the integrity of HPAMs due to high shear experienced at valves, chokes and other flow control devices. At a minimum, this risk can severely impact chemical EOR operating cost due to polymer degradation and consequential viscosity loss of the injectate. Low-shear, low-cost polymer injection distribution systems have the potential to reduce polymer usage, maintain injection stream viscosity, and enable integration into brownfield facilities. Lower viscosity losses translate into optimized operating and capital cost for CEOR pilot and full field projects. The objective of this work was to determine the equipment (piping), process, and polymer parameters that affect viscosity loss due to shear degradation.
In this work, polymers were evaluated from two different vendors. The effects of molecular weight, chemical concentration, and brine salinity on polymer sensitivity to viscosity loss due to shear degradation were investigated. Polymer solutions were either blended on site or purchased pre-blended in synthetic brine solutions. Pumped by a positive displacement, low-shear pump, the solutions flowed through a mass meter and were delivered to a distribution system component at various flow rates. For flow control devices, pressure differentials were adjusted at fixed flow rates. Polymer solution samples were collected upstream and downstream of the tested component. Samples were taken in no-shear sample collectors. Pressure upstream and downstream of the test component and flow rate were recorded during the flow test. Viscosity was measured with a Brookfield viscometer at ambient temperature. When higher concentration solutions were tested, viscosity was measured of diluted samples at target concentration to determine amount of shear degradation as evidenced by viscosity loss.
Results indicate that viscosity degradation of polymer solutions does occur in flow control devices and is directly correlated to pressure differential across the pipe device. Internal geometry has little impact on the amount of degradation. Velocity has little impact on the amount of degradation. Polymer molecular weight and structure both affect the amount of degradation due to shear as does solution concentration. Generally, viscosified brine solutions will lose viscosity when flowed through devices with greater than 50 psi differential pressure in the range of 15-50% of initial viscosity. Using more concentrated polymer streams and diluting to target concentration after flow control will reduce the amount of viscosity loss.
Based on the laboratory results, design and operating condition, recommendations can be made for polymer injection distribution systems to minimize shear degradation of the flowing viscosified brine stream.
Improving CO2 Foam for EOR Applications Using Polyelectrolyte Complex Nanoparticles Tolerant of High Salinity Produced Water
Authors: Nazari Negar , Tsau Jyung-Syung , Barati Reza 
Published: March 2018

Abstract
Although surfactant generated CO2 foam improves the mobility control for CO2 flooding, it suffers from instability in the presence of crude oil and in high salinity environments. The objective of this work is to improve the stability of the interface by lowering surfactant drainage and improving the stability of lamellae in high salinity produced water using polyelectrolyte complex nanoparticles and generate a more stable foam front in the presence of crude oil. This results in improving the recovery efficiency of foam floods.
In this project, an optimized system of polyelectrolyte complex nanoparticles was used to improve scCO2 foams prepared in high salinity produced water. The effect of nanoparticles on the interfacial properties of the foam was studied. Thereafter, a set of core flooding experiments with and without the crude oil in the system was conducted to measure the apparent viscosity and the incremental oil recovery due to addition of polyelectrolyte and polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam in high salinity produced water.
Studying the interfacial properties of different foam systems shows that addition of polyelectrolytes and polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam improves the elasticity of the interface. Furthermore, adding polyelectrolytes and polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam, improves the efficiency of the oil recovery by improving the apparent viscosity and making the foam more stable in the presence of crude oil. Polyelectrolyte complex nanoparticles produced incremental oil when the surfactant foam system reached its residual oil and produced no more oil.
Generating a very stable system of the foam by adding polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam prepared in high salinity produced water, results in a longer lasting foam and increase the incremental oil recovery up to 10%. The sea water salinity is applicable for all the locations with access to the sea water as well as locations with produced water salinities close to sea water. The higher salinity system covers a wide range of the reservoirs in the United States and worldwide with access to produced water.
Exploring the Upper Limit of Oil Viscosity for Polymer Flood in Heavy Oil
Authors: Delamaide Eric 
Published: March 2018

Abstract
Large scale polymer flooding projects in heavy oil are now ongoing in several countries and numerous other projects are at the pilot or design stages. However, there is currently no guideline for the maximum acceptable oil viscosity, one of the important parameters in the screening of new projects. Standard screening criteria do not take the latest field results into account and more recent guidelines rely mostly on viscosity averages whereas they should focus on the extreme values instead.
Since the laboratory can only provide little help to settle this issue we propose to examine current field projects for guidance.
To the best of the author's knowledge, the Pelican Lake and the Seal polymer floods, both in Canada, are operating in the highest oil viscosity ranges; moreover, the data is public and can easily be accessed. We have therefore examined the performances of polymer injection in the highest ranges of oil viscosity in both fields to get an understanding of the limits. This involved first the identification of the highest oil viscosity patterns, then the estimation of the live oil viscosity during the polymer flood in these patterns and finally the performances of the polymer flood.
Viscosity measurements are notoriously difficult and not always very reliable in heavy oil and the evaluation of in-situ viscosity is even more difficult; therefore, we used ranges of viscosity rather than definite values. The observations from Pelican Lake and Seal seem in good agreement and suggest that polymer flood is still feasible and can provide an acceleration in production for live oil viscosities up to 10,000-12,000 cp. There is little experience beyond these values, but it appears that for higher ranges of viscosity polymer injection becomes much more difficult; in Seal polymer flood does not appear to be working satisfactorily in oil viscosities above 14,000 cp.
To the best of the author's knowledge, this is the first time that the issue of maximum oil viscosity is investigated in such a manner. Although these results are preliminary and would require further confirmation from other field cases, this paper will provide guidance to engineers screening heavy oil reservoirs for potential application of polymer flood.
Multi-Well Analytical Solution for Coning Under Simultaneous Steady-State Flow of Three Phases
Authors: Ahn Eunnam , Johns Russell T. , Phaiboonpalayoi Chonpatin 
Published: March 2018

Abstract
Unwanted water or gas production from upward or downward coning can significantly erode profits in oil recovery processes. Simulation estimates of the magnitude and timing of coning can be erroneous owing to unknown reservoir heterogeneity, large grid blocks near the wells, and inaccuracies in simulation well models, such as that from Peaceman.
This paper presents a multi-well steady-state analytical solution for coning of three phases (water, oil, and gas) flowing simultaneously. The solution for multiple wells is developed using superposition with a coning potential function that includes capillary pressure and relative permeability. The assumption of vertical equilibrium (VE) is made, which gives maximum crossflow vertically and therefore the largest possible coning. Any model for relative permeability and capillary pressure can be used, although we used Stone 2 for relative permeability and Brooks-Corey for capillary pressure. We give dimensionless inflow performance windows (IPW) to show the allowable physical window of three-phase rates and the maximum oil rate as a function of the water and the total well flow rate. The new potential functions are also used to demonstrate superposition for several well patterns with no-flow boundaries. Besides estimating critical oil rates, the solution could be important to benchmark numerical solutions and improve the accuracy of Peaceman's well model.
Sulfonated Polyacrylamides - Evaluation of Long Term Stability by Accelerated Aging at Elevated Temperature
Authors: Nurmi Leena , Sandengen Kristian , Hanski Sirkku , Molesworth Peter 
Published: March 2018

Abstract
When EOR by polymer flooding is applied in the offshore environment, polymer can be expected to face long reservoir retention times of up to several years. The stability and viscosity retention of the polymer needs to be evaluated throughout this time. Copolymers of acrylamide (AM) and acrylamide tertiary butyl sulfonic acid (ATBS) are a potential polymer choice for relatively high temperature and salinity reservoirs. In this study, it was evaluated how the long term stability of AM-ATBS copolymers can be predicted by accelerated aging tests at elevated temperature.
The main cause of viscosity loss in AM-ATBS copolymer solutions is the hydrolysis reaction turning AM and ATBS groups into acrylic acid (AA). This hydrolysis was studied in strictly anaerobic conditions at 70-120°C. Besides temperature, the impact of ATBS content in the copolymer (15-55 mol%), pH, salinity and divalent ion concentration were studied. In addition, some tests were done with copolymers of ATBS and AA to elucidate the effect of neighboring monomer on ATBS hydrolysis. The reaction progress was followed by 13C NMR and viscosity measurements.
Over a range of conditions, it was observed that AM-ATBS copolymers aged at different temperatures but at otherwise equal conditions, had similar AA/AM/ATBS ratios at equivalent degrees of hydrolysis. Additionally, the shapes of viscosity retention vs. time curves were corresponding in the studied temperature interval after being normalized into the same time scale. It is proposed that AM hydrolysis is the rate determining step, resulting in a similar hydrolysis pathway over a range of temperatures. AM hydrolysis reaction rates were fitted into an Arrhenius function to estimate acceleration at elevated temperatures.
The data generated in this study helps to predict how the results from accelerated tests (e.g. at 100-120°C) correlate to stabilities at lower temperature (e.g. actual reservoir temperature at 70-80°C). Specifically, a practical overview of expected time of stability (viscosity retention &gt;80%) has been generated for AM-ATBS copolymers in seawater.
Nuclear Magnetic Resonance Study on Oil Mobilization in the Shale Exposed to CO2
Authors: Wang Haitao , Lun Zengmin , Lv Chengyuan , Lang Dongjiang , Luo Ming , Zhao Qingmin , Zhao Chunpeng 
Published: March 2018

Abstract
The reservoirs in Qian 34 10 rhythmic layer of Qianjiang Basin were shale oil with intersalt sediments. During natural depletion development process production rapidly decreased. Water injection and CO2 injection were considered as potential technology for shale oil EOR. Due to high salt content of shale rock and dissolution of salt in water, water injection damaged the reservoirs. CO2 injection didn't react with salt to damage the reservoirs. Meanwhile, CO2 could enter micro pores of reservoir rock and mobilize oil by the mechanisms of diffusion, extraction and swelling and so on. In order to verify oil mobilization in shale exposed to CO2 exposure experiments based on nuclear magnetic resonance (NMR) were conducted in this study.
NMR T2 spectrum can measure the oil signal and determine the oil content of rock with low permeability. In this study 10 fresh shale samples (from 6 depths) were measured and oil contents were determined using NMR T2 spectrum. Two shales with higher oil content were selected and performed exposure experiment. Under the temperature of 40 °C and the pressure of 17.5 MPa fresh shale was exposed to CO2 and NMR T2 spectrum was used to measure the oil content of shale continuously. Oil mobilization in shale exposed to CO2 was determined.
The results of NMR T2 spectrum showed that NMR signals of 9 fresh shale samples were good and oil contents of fresh shales were high. Recovery of S5# shale exposed to CO2 was 51.2% after 8 days. Recovery of S9# shale exposed to CO2 was 55.8% after 6.1 days. These results indicated that more than half of shale oil were mobilized with relative long exposed time during CO2 injection. The results of NMR T2 spectrum showed that oil in all pores could be mobilized as exposure time increased.
This study showed the quantitative results for CO2 injection and EOR in shale oil of Qianjiang Basin. All conclusions provided confidence to start CO2 EOR pilot project in shale oil with intersalt sediments with ultra-low permeability.
Application of Multi-Well Steam Injection and CO2 Technology in Heavy Oil Production, Liaohe Oilfield
Authors: Jin Fu , Xi Wang , Shunyuan Zhang , Bingshan Liu , Chen Chen 
Published: March 2018

Abstract
Liaohe Oilfield is well-known for wide distribution of heavy oil resoures whose viscosity is around 6.2×104mPa·s (degassed crude oil at 45°C). Heavy oil resources are usually found at the depth of 500-1700m. An integrated research has been completed to study the most efficient utilization of steam huff and puff methodology.
In order to compare the new steam injection method with the conventional EOR method, we selected 7 wells in which steam injection was simulated by software. The high temperature gel particle plugging agents, high temperature frothers and resins were tested. The overall sweep efficiency and oil production rate of these wells were compared with that of adjacent wells that depended on conventional steam injection methodologies.
The multi-well steam injection requires injecting steam into a specific group of wells, so that an overall thermal field may be created. In this way, steam channeling caused by longitudinal heterogeneity of heavy oil reservoirs may be overcome. CO2 has the best role in reducing the oil viscosity, while natural gas and nitrogen follow it. So CO2 is the most appropriate EOR gas. CO2's dissolubility declines as temperature goes up and improves as pressure increases. Temperature of liquefied CO2 varies a lot with different injection speeds, in that the heat diffusion time is different. The faster CO2 is injected, the shorter the heat diffusion time is, which makes downhole temperature change less. As CO2 is injected into formation, it dissolves rapidly with heavy oil and makes it expand. Steam is injected then to heat the borehole, while CO2 diffuses rapidly and its dissolubility declines as temperature goes up, which makes CO2 separated from oil and diffused by scale. Thus, clean-up additives and steam are widely distributed. After shut-in CO2 spreads until it keeps balanced dynamically with viscosity reducers.
The daily production rate used to start to decrease after 5 rounds of steam injection. By injecting steam and CO2 into a group of wells we succeeded in improving the sweep efficiency and production rate.
In Situ Carbon Dioxide Generation for Improved Recovery: Part II. Concentrated Urea Solutions
Authors: Wang Shuoshi , Yuan Qingwang , Kadhum Mohannad , Chen Changlong , Yuan Na , Shiau Bor-Jier , Harwell Jeffrey H. 
Published: March 2018

Abstract
While injection of CO2 has great potential for increasing oil production, this potential is limited by site conditions and operational constraints such as lack of proper infrastructure, limited cheap CO2 sources, viscous fingering, gravity override at the targeted zones, and so forth. To mitigate some of these common limitations, we explore alternative methodologies which can successfully deliver CO2 through gas generation in situ, with superior IOR performance, while offering reasonable chemical cost.
While dissolved easily in reservoir brine, urea is thermally hydrolyzed to CO2 and NH3 after equilibration under reservoir conditions. Therefore, given its exceptional compatibility with reservoir fluids, its CO2 producing capacity and reasonable cost benefit, urea appears to be a promising candidate for delivering CO2 to increase oil recovery. The in-situ gas generation requires single chemical slug, which can minimize the complexity of the injection system.
One-dimensional sand pack tests and core flooding experiments were operated at pre-set conditions: different API gravity oils were used, varying from 27 to 57.3. In addition, the reaction rates of the urea hydrolysis and urea solution PVT property were tested separately under reservoir conditions.
Most importantly, results of injecting urea solution (as low as 10 % solution) showed superior tertiary recovery performance (as high as 37.97%) are realized as compared to the most recent efforts at our group (29.5%) as well as similar in situ CO2 generation EOR (2.4% to 18.8%) approaches proposed by others.
The economic feasibility and operational advantages of this newly developed method were demonstrated in this work. In brief, results of this work served further as a proof of concept for designing in situ CO2 generation formulations for tertiary oil recovery at both onshore and offshore fields under proper conditions.