bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Experimental Study of Cyclic CO2 Injection to Improve Shale Oil Recovery
Authors: Gamadi T. D. , Sheng J. J. , Soliman M. Y. , Menouar H. , Watson M. C. , Emadibaladehi H. 
Published: June 2014

Abstract
The low recovery and high oil volume remaining in shale oil reservoirs are a strong motivation to investigate the application of enhanced oil recovery methods in these reservoirs. This paper presents the potential of applying cyclic CO2 injection to improve the recovery factors of shale oil reservoirs. Cyclic CO2 injection could be an effective technique to improve the oil recovery of this type of reservoirs for several reasons. It is a single-well process; well-to-well connectivity is not required, the hydraulic and natural fractures provide a large contact area for the injected gas to penetrate and diffuse into the low-permeability matrix; and the payback period of the cyclic CO2 injection process is short compared with the other flooding process. Very limited numerical and laboratory studies are available to study the feasibility of CO2 huff-n-puff for shale oil reservoirs. Latest numerical studies have revealed that CO2 huff-n-puff technique could be an effective method to increase recovery factors of shale oil reservoirs. In order to support the numerical studies results, a laboratory study was conducted using shale cores from Mancos and Eagle Ford. The aim of this study is to evaluate the potential of cyclic CO2 injection. Many design parameters such as soaking period, soaking pressure, and numbers of cycles were considered to evaluate the feasibility of cyclic CO2 injection. The laboratory results indicate that cyclic CO2 injection improved recovery of shale oil cores from 33% to 85% depending on the shale core type and the other operating parameters. These results have shown that cyclic CO2 injection is a promising method to improve the recovery of shale oil reservoirs. Also this study aided to develop a better understanding of the performance of cyclic CO2 in shale oil reservoirs.
Validating Surfactant Performance in the Eagle Ford Shale: A Correlation between the Reservoir-on-a-Chip Approach and Enhanced Well Productivity
Authors: He Kai , Xu Liang , Gao Yuefeng , Neeves Keith B. , Yin Xiaolong , Bai Baojun , Ma Yinfa , Smith Jonathan 
Published: June 2014

Abstract
For liquids-rich shale plays, surfactants have proven to be a critical component in hydraulic fracturing fluid systems for enabling enhanced oil and gas recovery. The industry's most commonly used surfactant is a non-emulsifying surfactant (NES), but it has been previously demonstrated that a weakly emulsifying surfactant (WES) appears to be more efficient at mobilizing oil through tight pore throats. In this study, fundamental differences between those two surfactant types were further demonstrated using a Reservoir-on-a-Chip (ROC) approach, which allows direct visualization of oil recovery with the various surfactant fluids, allowing for the testing on both homogenous and heterogeneous pore structures with various geometries. The laboratory testing showed that, compared to a non-surfactant-bearing control fluid and the NES, the WES showed higher oil recovery efficiency at equal driving pressure.
As a result of the laboratory testing indications, a multiple well trial program was conducted in two separate areas of the Eagle Ford shale. Production data from the wells stimulated using a WES-bearing fracturing fluid were normalized in terms of lateral lengths and fracturing stages, and compared to the offset wells stimulated using a NES-bearing fracturing fluid. Early production results suggest that wells treated with the WES exhibited enhanced productivity compared to those treated with the NES.
Simulation of Surfactant Flooding in the Presence of Dissolved and Free Gas Accounting for the Dynamic Effect of Pressure and Oil Composition on Microemulsion Phase Behavior
Authors: Trouillaud Adrien , Patacchini Leonardo , de Loubens Romain , Moncorgé Arthur 
Published: June 2014

Abstract
The dynamic effect of pressure and Oil composition on Microemulsion phase behavior, complementing the key effect of variable salinity, has been implemented in our four-fluid-phase, fully implicit in-house research reservoir simulator. This has been achieved through self-consistent coupling of a traditional Gas/Oil/Water phase equilibrium model, either compositional or generalized black-oil,—providing phase fractions, oleic composition, and aqueous salinity—with a Microemulsion model based on oleic/aqueous/chemical pseudophase equilibrium.
As an application example and validation test case, we consider a hypothetical surfactant/polymer (SP) coreflood of a saturated Oil, interrupted by a progressive depressurization, during which dissolved gas is released, which shifts the Microemulsion phase state from Winsor Type III to Type II-. This proves the good functioning of our new option, and shows, yet on a simple case, that it does not degrade numerical performance, despite the introduction of additional nonlinear dependencies.
An Integrated MEOR Project; Workflow to Develop a Pilot in a German Field
Authors: Alkan H. , Biegel E. , Krüger M. , Sitte J. , Kögler F. , Bültemeier H. , Beier K. , McInerney M. J. , Herold A. , Hatscher S. 
Published: June 2014

Abstract
The workflow and the results of the work packages of a Microbial Enhanced Oil Recovery (MEOR) project aiming at a pilot are introduced and discussed. An enrichment culture consisting of a community of various microbial species derived from one of the Wintershallfields shows good growth and EOR characteristics upon nutrient stimulation tailored for the given reservoir characteristics, including high salinity (160000ppm). The emulsification indices as well as measured interfacial tensions (IFTs) between dead oil and the microbial culture supernatant collected during the exponential and stationary growth phases indicate potential beneficial impacts on capillary forces. Imbibition experiments with Bentheim sandstones support the measurements. The rheology of cell-free medium after growth shows pseudoplastic behavior resulting in viscosities of up to 3-6mPa•s at representative shear rates. An important EOR effect was gas (CO2) generated during growth, which resulted in a calculated reduction of 3-4mPa•s in oil viscosity. The effect of pressure (reservoir pressure is 30bar) on the metabolite generation is being investigated with growing cells in high-pressure bio-reactors. Model systems including micromodels, sandpacks and corefloods were used under sterile and anaerobic conditions to monitor the oil displacing effects of the nutrient-stimulated communities. Experiments using polydimethylsiloxane (PDMS) micromodels consisting of channels with different pore sizes indicated an improvement of the sweep efficiency potentially due to selective plugging. A sandpack system was designed to test the dynamic performance of the bacteria and proposed nutrient formulations. The flooding tests performed under reservoir temperature showed incremental oil of up to 18% of OOIP after three successive medium treatments. The oil recovery performance of the proposed nutrient formulations is also being tested with coreflooding experiments at reservoir pressure and temperature. Numerical simulation work packages focused on modeling all MEOR components as tracer in oil and water phases and implement growth/decay of bacterial cells by Monod equation. The implementation of this concept into the commercial reservoir simulator STARS/CMG using its reaction kinetics option is ongoing. Polymer and surfactant effects in water phase and gas generation effect on oil viscosity are modeled using standard approaches. The parameters are calibrated with batch as well as dynamic growth experiments. The implementation was validated by comparison to data obtained from sandpack and coreflood experiments. Results of both experimental and numerical work packages indicated additional oil recovery due to selective plugging, emulsification, CO2 generation and beneficial viscosity changes of water and oil phases.
An Interim Case Study of an Alkaline-Surfactant-Polymer Flood in the Mooney Field, Alberta, Canada
Authors: Watson Andrew , Trahan Gregory A. , Sorensen Wayne 
Published: June 2014

Abstract
Chemical Enhanced Oil Recovery (CEOR) use is expected to increase as more production companies implement tertiary oil recovery methods. This case study provides an outline of the process used to determine the applicability of an Alkaline-Surfactant-Polymer (ASP) flood, how the ASP chemical package was selected and tested, and the current field trial status. The selected field for this project is the low temperature Mooney field in north-central Alberta, Canada, producing ~16° API gravity oil with a viscosity of 150 to 1,500 mPa-s from the Cretaceous Bluesky sand formation at a depth of approximately 900 meters.
In 2006 a waterflood pilot test recovered an incremental 3% of the original oil in place (OOIP) over the primary production recovery (~4 to 5%). A three well polymer-only pilot was started in 2008 for 14 months and showed a total recovery of 18% OOIP suggesting a tertiary recovery method could be more successful than a waterflood. An independent laboratory tested multiple ASP packages, formulated with various surfactant types, either NaOH or Na2CO3 as the alkali in softened injection water, and with a partially hydrolyzed copolymers of acrylamide and acrylic acid. This independent reservoir screening identified several ultra-low interfacial tension ASP chemical package candidates, and core flooding confirmed increased oil recovery. Low chemical concentrations were specifically tested to minimize ASP chemical costs and downstream issues with emulsions. Economics were promising enough to proceed with company and Canadian approvals for ASP Phase One field implementation. Commercial injection began September 2011.
The Phase One ASP scheme consists of 25 injectors and 26 producers. Production from the ASP flooded area increased from approximately 175 barrels of oil per day (BOPD) in summer 2011 to a current high of ~2600 BOPD in December 2013, a period of 30 months. ASP chemical injection is continuing. Some injection delays have been caused by operational issues (water source and pipeline/facility modifications). These promising oil recovery results allowed Phase Two to be approved, and it is slated to be completed in 2014. Phase Three development is in the planning stage including drilling 16 additional primary horizontal wells.
The ASP flood of the Mooney field is a multi-well ASP flood that is progressing well but is still in the preliminary stages of data collection. The reservoir will continue to be monitored over the coming years to develop a comprehensive analysis of the tertiary oil recovery and how it compares with the initial laboratory ASP test results and predictions.
Operational Aspects of a Biopolymer Flood in a Mature Oilfield
Authors: Ogezi Oja , Strobel Joachim , Egbuniwe Daniel , Leonhardt Bernd 
Published: June 2014

Abstract
Bockstedt, a mature oilfield in Northern Germany, was discovered in 1954 and put on-stream in the same year. The waterflooding of this high permeability Valanginian sandstone reservoir, with moderately viscous oil and highly saline brine was started in 1959 and continues to date, albeit at a high watercut. A compartment within this field was selected for a pilot test of the biopolymer Schizophyllan; a polysaccharide, with considerable viscosifying efficiency and high salinity and temperature stability.
As the biopolymer flood progresses, surveillance and monitoring techniques that estimate in-situ polymer properties and help to understand the influence of the polymer on reservoir performance are applied. Operational procedures have also been developed and tested to ensure a manageable restart of operations in the event of planned and unplanned well shut-ins. Production logging test runs in the injection well during the water injection phase showed a homogeneous injection profile over the reservoir interval. Well logs from new wells drilled within the pilot area provide additional insight with regards to the saturation distribution. Passive and partitioning tracers have been injected and are regularly being sampled and analysed.
After a successful polymer injectivity field test was conducted in mid-December 2012 for Schizophyllan, continuous polymer injection commenced in early January 2013. High-resolution data available from permanent downhole gauges show an initial increase and subsequent stabilization of bottom-hole pressure at a higher value in the injection well after the start of polymer injection. A modified Hall plot used to assess the polymer injectivity does not show any significant reduction in injectivity. An estimation of the reservoir properties during the water injection phase and subsequently the in-situ effective polymer viscosity during the polymer injection phase using several falloff tests confirms that, the polymer is not shear degraded in the reservoir and offers insight as to the position of the polymer front in the reservoir. The work was accompanied by numerical simulation to better understand the in-situ rheological properties of the polymer.
This paper discusses the challenges, experiences and early results from the polymer flood pilot operations in a mature oilfield after an early technical evaluation.
Polymer Flood of Viscous Oils in Complex Carbonates
Authors: Doorwar Shashvat , Mohanty Kishore K. 
Published: June 2014

Abstract
Polymer flooding is investigated in laboratory cores as a non-thermal enhanced oil recovery process for viscous oils in heterogeneous carbonate reservoirs. Core floods were performed in vuggy dolomite cores saturated with 200 cP crude oil and complementary pore-scale investigations were conducted using 2D glass micromodels. Tertiary polymer floods conducted after waterfloods of a viscous oil recovered more oil than secondary polymer floods in vuggy dolomite cores as well as Berea cores. This was also observed in oil-wet dolomite cores. The oil recovery in secondary polymer floods decreased as the polymer viscosity decreased. The secondary polymer flood, of course, recovered the oil faster than tertiary polymer floods. The oil recovery was also lower and slower in oil-wet cores compared to water-wet cores. Micromodel experiments showed that the spacing between viscous fingers increases as the viscosity ratio increases. The viscous oil bypassed in waterfloods is mobile and can be recovered by a polymer flood. The waterflood recovery in a micromodel with connected heterogeneity was low, but the tertiary polymer flood recovered a significant amount of oil. Water imbibed into the low permeability bypassed regions and pulled the oil into high permeability regions which was later recoverd by the polymer flood. There was also no imbibition in oil-wet micromodels where the oil recovery was lower and slower compared to water-wet micromodels.
Magnus WAG Pattern Optimization Through Data Integration
Authors: Erbas Demet , Dunning Matthew , Nash Timothy M. , Cox David , Stripe John A. , Duncan Euan 
Published: June 2014

Abstract
This paper focuses on studies carried out to explore possibilities to improve both areal and vertical sweep efficiency in mature WAG patterns in the Magnus oil field. Magnus tertiary miscible gas injection started in 2002 through a WAG scheme taking the recovery factor close to 56% to date at a very high net efficiency of 3.5 mscf/stb. Pore scale sweep efficiency is very good with 8% residual oil to miscible gas flood (Sorm) based on core flood data. However, areal and vertical gas sweep efficiency seems to be sub-optimal based on 4D seismic and PLT data.
The Magnus Sandstone Member (MSM) consists of a number of stacked turbidite sand lobes separated by intra formational shales with varying thickness and lateral extent. The WAG scheme has been operated and managed by considering the MSM as a single reservoir unit. As the patterns have matured, it has become apparent that the scheme could be optimized by further vertical separation of the reservoir units. Key surveillance data such as 4D seismic monitoring gas movement, PLTs from both producers and injectors, well performance and open hole saturation logs have been coupled with simulation to study options for vertical and areal sweep improvement. These options involve changing sweep direction and intervals by means of adding new perforations and shutting off zones, complete reversal of the patterns – i.e. converting producers to injectors and vice versa, and use of chemicals for flood diversion.
Evaluation of multiple options resulted in a phased WAG optimization programme of which the first phase in the Central Panel is being proposed for execution in 2014. This phase involves changing perforation intervals in both producers and injectors. Later phases consist of further changes in perforation intervals, potentially pattern reversals and use of chemicals for diversion. A behind flood front core is planned in 2015, which is expected to help calibrate the optimization programme by quantifying Sorm and the degree of vertical sweep achieved in the field. The study required a detailed review of the surveillance data from various sources including 4D seismic and PLT data which were crucial in understanding the sweep efficiency. Relatively low cost options were identified to improve the sweep as opposed to drilling new wells. Integration with the operations team was the key in creating a business case for pattern optimization on a 30-yrs old, bed space constrained platform.
The workflow of this study and the learnings are applicable to mature patterns in any WAG EOR scheme. Optimizing the WAG patterns enables more efficient use of the available gas, which (given that the cost of gas is a significant component of any gas injection project) makes this more commercially viable and cost effective tertiary recovery option.
Safety Considerations for Air Injection into Light Oil Reservoirs
Authors: Fassihi M. R. , Moore R. G. , Mehta S. A. , Ursenbach M. G. 
Published: June 2014

Abstract
The presence of oxygen and carbon dioxide in the injection and production streams of any high pressure air injection (HPAI) project or the high oxygen partial pressures associated with enriched air/oxygen injection projects may create serious safety concerns such as potential of explosion or corrosion. Compilation of field problems and reported solutions from such projects indicate that no insurmountable problems exist in the implementation of high pressure air injection projects. Generally, the operators have successfully implemented safe operations when injecting at pressures as high as 6,000 psi. The long term successes of the HPAI projects in the Williston Basin which were initiated in 1978 by Koch Industries, Inc. and continue to be operated today by Continental Resources, Inc. have confirmed that HPAI is a viable and safe process for recovering light oils.
A number of oilfield oxygen injection programs have also been undertaken since the early 1980's when Greenwich Oil operated the first oxygen injection project at Forest Hills, Texas. In Canada during the 1980's, oxygen was injected by BP/AOSTRA at Marguerite Lake, by Dome Petroleum at Lindberg, by Husky Energy at Golden Lake, by Mobil Oil at Fosterton, and by Gulf Canada at Pelican. In the U.S. oxygen injection pilots were operated by ARCO in the Holt Sand Unit, Texas and more recently by NiMin Energy at Pleito Creek, California.
With increased oxygen partial pressure, there is a greater chance of safety or corrosion problems. In fact, the high oxygen content associated with the Holt Sand Unit project in West Texas caused a severe energy release that resulted in test termination. The reported data on this field are scarce and the nature of energy release has not been discussed in detail. This paper will first discuss some important details on the Holt Sand Unit (HSU) oxygen injection pilot and, then, will provide an overview of the key learnings from this project. The reasons behind the energy release in the HSU project will be discussed using the surveillance data, combustion tube test and numerical modeling results. Operational aspects during and after the test termination will be discussed. This information should provide a better understanding of the safety aspects of oxygen handling and proper practices in such operations.
Assessment of Three Phase Relative Permeability and Hysteresis Models for Simulation of Water-Alternating-Gas WAG Injection in Water-wet and Mixed-wet Systems
Authors: Shahrokhi Omid , Fatemi Mobeen , Sohrabi Mehran , Ireland Shaun , Ahmed Kamran 
Published: June 2014

Abstract
Obtaining reliable relative permeability (kr) values and their variations is difficult particularly in processes involving three-phase flow and flow reversal (e.g. WAG injection) which results in kr hysteresis. The current approach in the industry is to use a three-phase kr correlation (e.g., Stone I, Stone II, Baker) in conjunction with a kr hysteresis model (e.g., Killough, WAG- Hysteresis). However, these models have been mostly developed based on water-wet systems and have rarely been benchmarked against experimental measurements.
In this paper, we present the results of an extensive assessment of different three-phase relative permeability models available in the most widely used reservoir simulators. The input two-phase data needed for using three-phase kr correlations were obtained from core flood experiments. The simulation results were directly compared with WAG injection experiments performed under both water-wet and mixed-wet conditions.
The results show significant differences between the simulation and experimental results of WAG injection. In water-wet rocks, the results show that without considering kr hysteresis, Stone-I model underestimates WAG performance, but it overestimates oil recovery in mixed-wet rocks. SWI and Baker correlations overestimate WAG performance in water-wet rocks while for mixed-wet rocks they significantly underestimate production data. For both wettabilities, Stone-II significantly underestimates oil production. The generated recovery trends by IKU model show a relative advantage over other models but still underestimates the performance of WAG injection especially for later cycles.
Coupling of three-phase kr correlations with hysteresis models (Carlson, Killough and Jargon) generally results in highly overestimated oil recovery predictions especially for mixed-wet conditions. For water-wet systems, coupling Stone-I with WAG-hysteresis model improves the predictions up to the second gas injection period. Nevertheless, serious underestimation is observed for further cycles. The WAG-hysteresis model overestimated WAG performance in mixed-wet systems. To improve its prediction, based on our experimental results, WAG-hysteresis model parameters were adjusted after each cycle. This modified approach improved simulation results in water-wet systems. However, none of the available approaches could adequately reproduce experimental results obtained for mixed-wet conditions. This is a major concern for predication of WAG performance in real reservoirs which are believed to be mixed-wet.