bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Experimental Approach for Accurate Evaluation of Chemical EOR Processes in Tight Reservoir Rocks
Authors: Chevalier Thibaud , Labaume Julien , Gautier Serge , Chevallier Eloïse , Chabert Max 
Published: March 2018

Abstract
The sustained lower oil price for the last three years has shifted tight oil industry interest from an intensive drilling and completion based approach to more cost effective methods aimed at maximizing rates and ultimate recovery from existing wells. In that framework, application of conventional EOR methods to unconventional tight oil well has gained momentum in the recent period, with theoretical and experimental evaluation of approaches ranking from water and CO2 flooding to huff'n puff with chemicals. For that purpose, usual EOR experiments used for conventional rock cannot always be applied due to the extremely low volumes and permeability of tight reservoir rocks. This can lead to inaccurate results or extremely long experimental times. Here, we present a novel method for rapidly evaluating oil production by EOR methods in micro-Darcy permeability reservoir rock, and apply it to evaluate various chemical EOR approaches for unconventional tight oil wells.
Our method relies on a fast screening and a continuous NMR monitoring of fluid saturations during imbibition experiments at reservoir temperature in miniaturized plugs. This permits to evaluate oil and water saturations in the rock samples as a function of time without having to interrupt the experiment for carrying out measurements. We validate this method by evaluating recovery from 10 μD sandstones and carbonates during imbibition of LowIFT formulations with various chemical additives. Despite the extremely low permeability, oil production from plugs using various chemicals can be evaluated and compared in less than 72 hours.
Our new protocol shall be of interest to all laboratories trying to adapt EOR techniques to unconventional reservoirs, by permitting a real-time accurate and quantitative evaluation of various EOR options. In addition, the data we generated using various chemical EOR techniques support the interest of using low-IFT inspired chemical EOR methods to improve the ultimate recovery from tight reservoirs.
De-Risking Alaskan Viscous Oil: Study, Field Trial Plans and Challenges for Improving Recovery via IOR/EOR
Authors: Garg A. , Paskvan F. , Jerauld G. , Gould T. , Skinner R. 
Published: March 2018

Abstract
This paper summarizes BP's Alaskan viscous oil resource appraisal strategy to de-risk viscous oil resource progression with a goal to improve recovery factor by 10%. A key to recovery improvement is application of improved oil recovery/enhanced oil recovery (IOR/EOR) methods. However, even after detailed studies, moving to the next stage including field pilots is not always easy in the mature and remote Alaskan North Slope.
The paper also covers BP's Alaskan viscous oil technology strategy, extraction technologies selection, simulation and analytical studies, laboratory studies, and field trials for various shortlisted methods. A comprehensive study strategy conducted for progressing chemical EOR processes is discussed. The paper also addresses the challenges of obtaining new core and fluid samples for laboratory studies and logistical and economic considerations for field trials due to location and weather conditions in this part of the world.
Results of the UK Captain Field Interwell EOR Pilot
Authors: Poulsen Anette , Shook G. Michael , Jackson Adam , Ruby Nicolas , Charvin Karl , Dwarakanath Varadarajan , Thach Sophany , Ellis Mark 
Published: March 2018

Abstract
An enhanced oil recovery (EOR) pilot was conducted by Chevron North Sea Limited ("Chevron") at the Captain Field in the UK North Sea between 2011 and 2013. Results from the polymer injection are presented along with an assessment of incremental oil recovery.
The polymer solution was selected and qualified using a combination of laboratory and yard tests to determine optimum specifications for injection. The selected polymer was initially tested in an injectivity test in 2010, followed by continuous polymer injection in 2011, after establishing a waterflood baseline. Continuous polymer injection was terminated in 2013 due to injectivity decline associated with polymer emulsion injection. An unambiguous response from the reservoir was observed with a significant uplift in oil production.
The three mechanisms of a successful polymer flood were observed and evaluated: (1) acceleration of oil production, (2) incremental oil production due to improved polymer sweep, and (3) water production and injection minimization. Our results demonstrate that waterflood recovery can be accelerated by polymer flooding. Secondly, incremental oil was produced due to increased volumetric sweep by changing the displacing phase fluid mobility with the viscosified polymer. Finally, the reduction in water production translates into reduced water handling and thereby lower operating costs.
Before and during the pilot chemical injection, production logging tools were run in the injector and producer to measure their respective outflow and inflow phase profiles along the horizontal completions. These logs confirmed that polymer promotes crossflow to make injection rates more uniform along the wellbore. We also drilled a post-polymer observation well in the swept zone between the pilot wells. Logs from this well established remaining oil saturations to polymer that we used to confirm our calculations for polymer flood volumetric sweep. The post-polymer flood oil saturations confirmed the performance of the polymer flood.
We show a full suite of surveillance data and its use in quantitative interpretation. We also show innovative uses of the surveillance data in our interpretation methods. The results prove the subsurface and operational success of polymer flooding a heavy oil reservoir with horizontal wells, even in a harsh offshore environment such as the UK North Sea.
Reducing Uncertainty at the Chichimene In Situ Combustion Pilot by Means of a Nitrogen Connectivity Test
Authors: Trujillo M. , Delgadillo C. , Niz-Velásquez E. , Claro Y. , Rodriguez E. , Rojas R. 
Published: March 2018

Abstract
Prior to starting any Enhanced Oil Recovery (EOR) process, it is desirable to characterize the flow pattern within the affected reservoir volume. This becomes of critical importance for in situ combustion in heavy oil reservoirs, where the mobility ratio is highly unfavorable, oftentimes resulting in channeling or early breakthrough. An inter-well connectivity test through immiscible gas injection aids in characterizing the flow distribution, in addition to: 1) calibrating estimates for sweep efficiency, 2) evidencing geological features that may lead to preferential flow towards a particular well or group of them, or lack of connection amongst them, 3) creating a gas path between the injector and producer wells to enable a safe progression of the combustion front, and 4) evaluating the performance of artificial lift and well control systems under high gas-liquid ratio conditions.
A connectivity test using nitrogen was designed, implemented and evaluated at the Chichimene field, prior to the ignition of the in situ combustion pilot. This process is summarized and described in this paper. This will be the first in situ combustion trial in a deep (≈ 8,000 ft), extra-heavy oil reservoir, and will serve as a data source to evaluate the development of resources under similar conditions in the eastern plains basin of Colombia. This set of reservoirs bears a significant fraction of the hydrocarbon resources in the country and under Ecopetrol operation.
The importance of this pilot makes this connectivity test of even larger relevance to reduce the subsurface and operational uncertainty, identify risks, and increase the probability of success of the combustion process as an option to economically producing these resources.
Waterflood Forecasting for More Accurate EOR Performance Evaluation
Authors: Behzadi Hamid , Hampton David 
Published: March 2018

Abstract
This paper presents modeling CO2 enhanced oil recovery (EOR) flood performance through the application of dimensionless scaling for both forecasting and surveillance purposes. While the methodology has been used successfully for West Texas CO2 floods for more than two decades, a recent modification in the process enhances the certainty of forecasted tertiary response based on simulation and analog results. The primary focus of this paper is on how this new approach improves the use of analog or observed production history to develop more reliable forecasts for EOR processes. Business units favor analog methods since they are fast, adaptable and explicit.
Analog tertiary production response is the incremental oil production over an estimated base waterflood oil recovery. The original formulation, published in a different paper (Simmons and Falls 2005), for the underlying base waterflood was modeled using an exponential decline throughput-based regression fit of historical pattern based performance, but in effective waterfloods, many times the oil production approaches a harmonic decline. In this paper, the impact of waterflood maturity level on analog dimensionless analysis is demonstrated by both simulation and multiple historical waterflood scenarios across the Permian Basin. The authors offer an improved approach to predict base waterflood and consequently tertiary oil recovery response. This method integrates multiple waterflood forecast methods, e.g., hyperbolic and dimensionless. The new approach results in a reduction in difference between simulation and analog forecasts. Also, the estimated final tertiary response using this method converges closer for various San Andres CO2 floods started at different times in West Texas. Finally, the modified analog response is compared against simulation.
Chemical EOR Under Harsh Conditions: Scleroglucan As A Viable Commercial Solution
Authors: Jensen T. , Kadhum M. , Kozlowicz B. , Sumner E. S. , Malsam J. , Muhammed F. , Ravikiran R. 
Published: March 2018

Abstract
While synthetic polymer floods are being deployed in mild temperature and low salinity fields, many oilfields (harsh conditions) remain inaccessible due to performance limitations, and concentration requirements, which adversely affect project economics. Historically, biopolymers have been considered in such reservoirs, with mixed results. Xanthan was used in the 1980's, while more recently schizophyllan polymer was tested in a pilot study. This study presents scleroglucan polymers as a class of viscosifiers that demonstrate excellent performance in harsh temperature and salinity reservoirs. Scleroglucan polymers do not suffer from catastrophic drop in viscosity in the presence of high concentration of divalent ions. This makes produced water re-injection projects without water treatment a reality. This work demonstrates that cost-effective, high purity EOR grade Scleroglucan polymers, show excellent performance in lab trials as related to excellent rheological properties, injectivity, bio and thermal stability and with minimal shear degradation.
Injectivity tests demonstrated good propagation through cores without blockage or injectivity issues. Resistance factors and residual resistance factors are in the desirable range. Core floods carried out in sandstone and carbonate outcrop cores demonstrated that adsorption values and oil recoveries are consistently in the expected range for polymer recoveries. Shear degradation studies showed that recycling scleroglucan through a centrifugal pump causes less than 5% drop in viscosity after 100 passes while synthetic polymer showed substantial loss after a single pass and a 50% drop after 10 passes through the same pump. Capillary shear testing (API RP 63 method) of scleroglucan shows little change in viscosity upon multiple passes through shear regimes greater than 150,000 s−1. Scleroglucan polymer solution showed less than 25% drop in viscosity after exposure to 115 °C for six months. No change in viscosity was observed at 95 °C after one year. Scleroglucan has no compatibility issues through 6 months (at 37, 85, and 95 °C) with glutaraldehyde and tributyl tetradecyl phosphonium chloride (TTPC) biocides. Long term biostability studies at various temperatures and salinities are ongoing - current data will be presented. Scleroglucan has excellent stability in the presence of hydrogen sulfide (H2S) and ferrous species (Fe2+) under fully aerobic conditions!
This work provides insight on the potential of using EOR grade scleroglucan for CEOR in harsh condition reservoirs. Currently, the program is moving towards pilot implementation of a scleroglucan formulation to demonstrate large scale hydration, long term injectivity and oil recovery.
The Generation, Stabilization and Migration Rules of Crude Oil Emulsion During the Process of Amphiphilic Polymer Flooding
Authors: Lu Yao , Li Zhe , Wu Hairong , Jiang Jiatong , Jiang Jianfang , Hou Jirui , Kang Wanli , Yang Hongbin , Zhang Xiangfeng , Bai Baojun 
Published: March 2018

Abstract
It has been proven by field tests that crude oil recovery could be enhanced with the generation of stable emulsions. Amphiphilic polymers display better capability in emulsifying crude oil as compared with that of traditional polymers attributing to the co-existence of hydrophilic and hydrophobic groups in molecular chains. To investigate the generation of emulsified oil droplets with the hydrophobically modified polyacrylamide (HMPAM) in reservoirs, porous mesh shearing method to generate emulsions was first conducted. The stabilization mechanism was then elucidated by comparing properties of emulsions which are stabilized by HMPAM with different degree of β-cyclodextrin (β-CD) inclusion. The flow behavior of various HMPAM emulsions was further evaluated by rheological method and comparative seepage experiments. The results show that the snapping action of residual oil and the shearing action of HMPAM solution in porous media are the main reasons of the generation of emulsions, the emulsifying property of which is mainly affected by the concentration of HMPAM, injection rate, migration distance as well as the average diameter of pore throats. β-CD could mask hydrophobic groups on HMPAM molecules because of the host-guest interaction, resulting in a transition of corresponding polymer emulsion from stable state to unstable one. Over 80% reduction in stability index is observed after inclusion for the emulsion with polymer concentration above the critical aggregation concentration, indicating that the presence of hydrophobic groups is the most important source of emulsifying and stabilizing capability of HMPAM. Furthermore, the viscoelasticity of the emulsion system is enhanced by the synergistic effect of supramolecular networks and emulsified oil droplet. During its transport through porous media, the polymer emulsion shows high flow resistance and its injection pressure exhibits an obviously creeping fluctuation increasing phenomenon as compared to surfactant emulsion and sheared polymer solution.
An Experimental Investigation of Polymer Mechanical Degradation at cm and m Scale
Authors: Åsen Siv Marie , Stavland Arne , Strand Daniel , Hiorth Aksel 
Published: March 2018

Abstract
In this work, we challenge the common understanding that mechanical degradation takes place at the rock surface or within the first few mm. The effect of core length on mechanical degradation of synthetic EOR polymers was investigated. We constructed a novel experimental set-up for studying mechanical degradation at different flow rates as a function of distances travelled. The set-up enabled us to evaluate degradation in serial mounted core segments of 3, 5, 8 and 13 cm individually or combined. By recycling we could also evaluate degradation at effective distances up to 20 m. By low rate reinjecting of polymers previously degraded at higher rates, we simulated the effect of radial flow on degradation.
Experiments were performed with two different polymers (high molecular weight HPAM and low molecular weight ATBS) in two different brines (0.5% NaCl and synthetic seawater).
In linear flow at high shear rates, we observed a decline in degradation rate with distance travelled, but a plateau was not observed. Even after 20 m there was still some degradation taking place. The molecular weight (MW) of the degraded polymer could be matched with a power law dependency, MWD ~L-x, where x for the HPAM was 0.07 and x for ATBS was 0.03.
We conclude that in linear flow, the mechanical degradation depends on the core length. However, in radial flow where the velocity decreases by length, the mechanical degradation reaches equilibrium with no further degradation deeper into the formation.
For the experiments where we evaluated degradation over large distances at high shear rates, we observed a decline in degradation rate with distance travelled, but we could not conclude that we reached a plateau. Even after 20 m there is still some degradation taking place. It is important to consider this knowledge when interpreting core scale experiments. However, the observed degradation is associated with high-pressure gradients, in the order of 100 bar/meter, which at field scale is not realistic.
We confirmed previous findings; degradation depends on salinity and molecular weight. Results show that in all experiments with significant degradation, most of the degradation takes place in the first core segment. Moreover, the higher the shear rate and degradation, the higher is the fraction of degradation that occurs in the first core segment.
Ethane-Enriched Gas Injection EOR in Niobrara and Codell: A Dual-Porosity Compositional Model
Authors: Ning Yanrui , Kazemi Hossein 
Published: March 2018

Abstract
The Niobrara and Codell in the Wattenberg Field of the Denver-Julesburg Basin (DJ Basin)have been in the centerstage of horizontal drilling and multi-stage hydraulic fracturing ever since 2007. Based on the current well completion strategy, oil rates drop to 20 bbl/day/well in five years of primary production. The cumulative primary production in the first five years amounts to 3%. Nonetheless, a substantial amount of producible hydrocarbon still remains. In this paper, we propose a most feasible enhanced oil recovery (EOR) technique for the Niobrara and Codell and other similar unconventional oil reservoirs. Realizing the unavailability of CO2 in the area while having easy access to methane, ethane, propane and butane, we designed an injecting gas consisting of ethane enriched with methane, propane and butane for EOR. A dual-porosity compositional model was constructed using data from seismic, well logs, core analysis, and production performance. After successful history matching, as well as verification with seismic and microseismic interpretations, a producer with five years of production history was converted to an EOR-gas injector in the numerical model. We used the model to determine the optimal injection gas composition for producing the largest amount of oil. We also studied the contribution of molecular diffusion at the fracture-matrix interface for the incremental oil recovery from gas injection. Model results indicate that converting three producers to injector wells, and producing from the remaining eight producers, yielded total oil recovery of 4.68% in fifteen years of production with 13% of which attributed to gas injection EOR.
Screening for EOR and Estimating Potential Incremental Oil Recovery on the Norwegian Continental Shelf
Authors: Smalley P. C. , Muggeridge A. H. , Dalland M. , Helvig O. S. , Høgnesen E. J. , Hetland M. , Østhus A. 
Published: March 2018

Abstract
This paper presents an improved approach for rapid screening of candidate fields for EOR and estimation of the associated incremental oil recovery, and the results of applying it systematically to oil fields on the Norwegian Continental Shelf (NCS), an area that already has a high average recovery factor (47%). Identifying, piloting and implementing new improved recovery methods within a reasonable time is important if substantial remaining oil volumes on the NCS are not to be left behind.
The approach uses up-to-date screening criteria, and has more sophisticated routines for calculating screening scores and incremental oil recovery compared to previous published methods. The EOR processes screened for are: hydrocarbon miscible and immiscible WAG, CO2 miscible and immiscible WAG, alkaline, polymer, surfactant, surfactant/polymer, low salinity, low salinity/polymer, thermally activated polymers and conventional near well gel treatments. Overall screening scores are derived from sliding-scale scores for individual screening criteria, weighted for importance, and with the ability to define non-zero scores when non-critical criteria are outside their desired range, so avoiding the problem of processes being ruled out completely even though rock or fluid properties are only marginally outside the threshold of applicability. Incremental recoveries are estimated taking into account the existing recovery processes in the field and are capped by theoretical maximum recovery factors derived from theoretical/laboratory values for displacement and sweep. The methodology calculates the expected increment (and uncertainty range) for each EOR process and the increments for the top three compatible process combinations.
The methodology was implemented in a spreadsheet-based tool that allowed multiple fields to be screened and the results compared and evaluated. The new tool was used to estimate the potential EOR opportunity for 53 reservoirs from 27 oil fields on the NCS. The results indicate a mid case EOR technical potential of 592 million standard cubic metres (MSm3) with a low- to high case range of 320-860 MSm3. The most promising processes are low salinity with polymer, surfactant with polymer, and miscible hydrocarbon and CO2 gas injection. Some field clusters were identified that could provide economies of scale for such processes.
The EOR screening study has enabled the Norwegian Petroleum Directorate to advocate EOR-technology studies, including pilots, in specific regions or fields. Such pilots will play an important role in verifying process feasibility and narrowing the uncertainty range for incremental recovery potential.