bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mapping CO2 Floods Using the Depth-to-Surface Resistivity Method: A Technology and Field Example
Authors: Nieuwenhuis Greg , MacLennan Kris , Wilt Michael , Wilkinson Mark , Ramadoss Vivek 
Published: March 2016

Abstract
Depth to Surface Resistivity (DSR) has been shown to be effective at mapping CO2, water flood, and residual oil aerially and vertically. Provided there is sufficient resistivity contrast between injected and in-situ fluids and subject to the reservoir depth and overburden resistivity, the technique is applicable for monitoring IOR/EOR fields. This information can be used to evaluate cap rock integrity, fluid loss to faults, and migration paths. The following paper presents a study of a CO2 flood followed by water alternating gas (WAG) injection.
Investigation of Surfactant Induced Wettability Alteration in Wolfcamp Shale for Hydraulic Fracturing and EOR Applications
Authors: Neog Anirban , Schechter David S. 
Published: March 2016

Abstract
The application of surfactants to improve oil recovery in conventional reservoirs via wettability alteration and enhancement of spontaneous imbibition has been extensively studied in the literature. However, little work has been performed yet to investigate the interaction of these surfactants with ultra-tight oil-rich shale reservoirs such as Wolfcamp shale. The use of horizontal drilling and massive multistage hydraulic fracturing has made primary oil recovery from these ultra-tight oil-rich shale reservoirs possible. With declining production from existing shale wells, it is essential to explore potential "beyond primary" strategies in shale oil development. This paper analyzes the potential of surfactants in altering wettability and improving the process of spontaneous imbibition in oil rich shales demonstrating nanodarcy range permeability, relevant to stimulation and "beyond primary" chemical EOR applications in shales.
Novel proprietary surfactant blends along with traditional nonionic surfactants were investigated in this study using Wolfcamp shale core samples exhibiting nanodarcy permeability. X-ray diffraction analysis was performed which indicated that Wolfcamp shale has mixed mineralogy, with quartz, calcite, and dolomite acting as the major minerals in varying proportions depending on the interval depth. Contact angle and interfacial tension measurements were performed at reservoir temperature to identify the state of native wettability and the impact of surfactants in altering wettability. Thereafter, spontaneous imbibition experiments were performed using 3D computed tomography methods to understand the improvement in the magnitude of imbibition penetration due to surfactant addition. Contact angle and spontaneous imbibition experiments showed that Wolfcamp shale is intermediate-wet and surfactants have the potential to alter the native wettability to a preferentially water-wet state and improve oil recovery due to enhanced spontaneous imbibition.
Surfactants which altered the wettability significantly, but lowered the interfacial tension only slightly showed the highest oil recoveries due to the creation of strong capillary driven forces directly responsible for effective spontaneous imbibition. The potential of surfactants in altering wettability and improving oil recovery via enhanced spontaneous imbibition in ultra-tight oil-rich shales was verified in this study. The effectiveness of traditional nonionic surfactants in altering wettability and improving oil recovery was found to be comparable to that of novel, more expensive proprietary surfactant blends, and hence, the traditional nonionic surfactants provide a cost effective option for stimulation and EOR applications in Wolfcamp shale. Overall, this paper presents the theory behind surfactant interaction with ultra-tight shales and provides experimental results to validate the viability of surfactant induced improved oil recovery in shales.
Snorre In-Depth Water Diversion - New Operational Concept for Large Scale Chemical Injection from a Shuttle Tanker
Authors: Skrettingland K. , Ulland E. N. , Ravndal O. , Tangen M. , Kristoffersen J. B. , Stenerud V. R. , Dalen V. , Standnes D. C. , Fevang Ø. , Mevik K. M. , McIntosh N. , Mebratu A. , Melien I. , Stavland A. 
Published: March 2016

Abstract
Declining oil production and increasing water cut in mature fields highlight the need for improved conformance control. Here we report on a successful in-depth water diversion treatment using sodium silicate to increase oil recovery at the Snorre field, offshore Norway, utilizing a new operational concept of using a stimulation vessel as a platform for the large-scale injection into a subsea well. A custom modified 35,000 DWT shuttle tanker was employed for the field pilot. This paper describes the vessel preparations and the large-scale interwell silicate injection operation. The operational aspects of the large-scale interwell silicate injection include; identification of injection vessel requirements, major vessel modifications, chemical logistic, general logistics to site, major equipment set-up on vessel, subsea connection, mixing and pumping schedules, onsite QC, and real time monitoring. Experience from these operations and lessons learned are included in this paper.
After the injection of approximately 400,000 Sm3 (113,000 Sm3 preflush, followed by 240,000 Sm3 of sodium silicate gelant and 49,000 Sm3 of postflush fluid) at injection rates up to 4,000 Sm3/d, the injection from the vessel was stopped and the well was put on regular seawater injection. Following more than two years of regular production, transient pressure measurements, tracer testing and water cut data are presented from the ongoing comprehensive data acquisition program. These results demonstrate clearly the achieved in-depth flow diversion through a delayed breakthrough of injected tracers and lower water cut in the relevant production well.
Reservoir Modeling and Production Performance Analysis to Investigate the Impacts of Reservoir Properties on Steam-Assisted Gravity Drainage in Cold Lake Oil Sands, Alberta
Authors: Wang Zexuan 
Published: March 2016

Abstract
When compared with steam-assisted gravity drainage (SAGD) operations in the McMurray Formation, Athabasca Oil Sands, SAGD projects in the Clearwater Formation at Cold Lake did not perform as expected, likely because of reservoir properties. This paper will use the Orion SAGD case study to: (1) investigate the impacts of reservoir properties on the SAGD thermal efficiency by field evidences; (2) identify key geological parameters influencing each well pad; and (3) summarize major geological challenges for Orion SAGD expansion.
Wireline log data were interpreted to characterize reservoir properties, which were used to build 3D models. 3D visualizations and 2D cross sections of the reservoir revealed spatial distribution and heterogeneity of each property. SAGD production performance was analyzed using: (1) temperature profiles that monitored the growth of the steam chamber; (2) cumulative steam-oil ratios (CSORs); and (3) oil production rates (OPRates), which are direct indicators of thermal efficiency.
Results show that impermeable barriers and low-permeability zones were detrimental to steam injectivity and steam chamber growth, as observation wells in Pilot Pads 1 and 3 did not detect any steam saturation. High-permeability zones favored high steam injectivity and mobility, especially in Pad 105. Steam chambers were irregularly shaped by high shale-content zones, as two sharp spikes displayed on the temperature profile in Pad 103. Low oil-saturation zones and thin net-pays increased the CSORs, as seen in Pads 106 and 104. Impermeable barriers are almost horizontal, making no difference on well pad orientation by their dip angles. Lack of porosity variation made it difficult to identify the impact of porosity on each well pad.
The relatively extensive distribution of impermeable barriers between and above well pairs, as well as the relatively large area of low oil saturation and thin net-pay, were identified as major geological challenges.
Polymer Flooding: Establishing Specifications for Dissolved Oxygen and Iron in Injection Water
Authors: Jouenne S. , Klimenko A. , Levitt D. 
Published: March 2016

Abstract
It is now common knowledge among EOR practitioners that the combination of ferrous iron (Fe2+) and oxygen causes severe oxidative degradation to EOR polymers, resulting in a lowering of molecular weight and hence a loss of viscosity. During the design of polymer flooding projects, an important question is thus the acceptable levels of Fe2+ and dissolved oxygen that can be tolerated in injection water specifications. Furthermore, we would like to be able to predict the extent of degradation in the case of excess Fe2+ or oxygen ingress.
However, despite over fifty years of research and a general understanding of the degradation mechanism involved, quantitative prediction of the extent of degradation has proven elusive and dependent on the measurement protocol. This is likely due to the fastidious experimental protocols required to work under anaerobic or limited-oxygen conditions.
We examine existing protocols and demonstrate that experiments in which either Fe2+ or oxygen are the limiting reagent yield equivalent results when the stoechiometry of the Fe2+ oxidation reaction with oxygen is taken into account. Based upon these findings, a novel, easy approach is proposed to quantify polymer oxidative degradation as a function of either dissolved oxygen or Fe2+ content.
The limits of 225 ppb Fe2+ and 32 ppb dissolved oxygen are fixed for Flopaam 3630S in 6 g/l brine in the concentration range 500-1500ppm in order to ensure degradation of low-shear plateau viscosity does not exceed 10%. Higher levels will lead to severe polymer degradation. The influence of polymer concentration, temperature and salinity is also investigated. At last, evolution of redox potential and pH during Fe2+ oxidation are discussed.
There is a direct practical application of these finding for the design of surface facilities for polymer dissolution and transport and for the prediction of degradation in case of oxygen ingress. Moreover, a simple and easily performed protocol is proposed for the evaluation of polymer oxidative degradation.
Field Test Results of a New Silicate Gel System that is Effective in Carbon Dioxide Enhanced Recovery and Waterfloods
Authors: Oglesby Kenneth D. , D'Souza David , Roller Chad , Logsdon Ryan , Burns Lyle D. , Felber Betty J. 
Published: March 2016

Abstract
Field test results of a new silicate based Silicate-Polymer-Initiator (SPI) gel system for zonal conformance control are presented from: 3 treatments in a central Mississippi sandstone carbon dioxide (CO2) flood, including 1 producer; 5 injector treatments in a mature, west Texas San Andres dolomite, CO2 flood under Water-Alternating-Gas (WAG) operation; and 2 injector treatments in a northeast Oklahoma waterflood. Gel treatment volumes ranged from 130 to 4,349 barrels of the patented, environmentally friendly, silicate gel system that is pumped at a near water viscosity and density. That pre-gel liquid is triggered to a gel by a pH change caused by external or internal initiation methods. One unique aspect of these silicate solutions is that they can be initiated by both the pre- and post-treatment injected CO2 itself. Alternately, other external and internal initiators can be used in both CO2 and water-floods. Targeted gel times ranged from 1 hour up to 6 days, with maximum gel strength generated within 2–4 weeks. The resultant silicate gels are 10 times stronger than any known gelled polymer system, per CTI laboratory Extrusion and Penetrometer testing. Selected additives were utilized in the gel treatment fluids to focus the pre-gelled solutions into the desired high permeability zones. Furthermore, pre-gel fluid entry into water or oil zones will not set the silicate gel, but will instead dilute the leading edge.
Rate, pressure, injectivity and downhole profile surveys were used to evaluate the treatment in injection wells. Oil, water and gas rates, Water: Oil Ratios, Gas: Oil Ratios and CO2 utilization efficiency were used to evaluate treatments in production wells. Offset production wells were monitored, where possible, for production changes, sometimes seen outside the prior established patterns. Where the data was available, the new silicate gel field treatments were directly compared to prior polyacrylamide and similar conformance systems. In most cases, the new silicate system exhibited positive responses while previous polymer based systems did not respond.
Surfactant Effect On Foam: From Core Flood Experiments To Implicit-Texture Foam-Model Parameters
Authors: Jones S. A. , Laskaris G. , Vincent-Bonnieu S. , Farajzadeh R. , Rossen W. R. 
Published: March 2016

Abstract
Aqueous foams play an important role in many industrial processes, from ore separation by froth flotation to enhanced oil recovery (EOR), where the foam is used as a means of increasing sweep efficiency through oil-bearing rock. The complex, structure-dependent, flow behavior of the foam gives improved penetration of lower-permeability regions. Foam is stabilized by surfactant molecules, and the foam strength is influenced by the surfactant concentration in the water phase. It is therefore of great importance to understand the effect of surfactant concentration on foam processes.
Implicit Texture (IT) foam models eg STARS account for the surfactant effect with functions that depend on surfactant concentration in the water and a few other parameters. However, there is no evidence that these functions are able to capture adequately the effect of surfactant concentration effect. We present a comparative study of foam core-flood experiments with various surfactant concentrations. Core-flood tests were conducted in rock cores with a diameter of 1 cm and length of 17cm, significantly smaller than typical cores. Plots of apparent viscosity vs. injected gas fraction were obtained for surfactant concentrations at the critical micellar concentration (CMC) and above. Bulk foam stability and surface tension were measured for all concentrations, in order to define the CMC and to compare with coreflood results. The experimental results have been matched with the STARS IT foam model and the dependency of model parameters on the surfactant concentration is discussed.
This work found that the IT model is not able to predict the decrease of the foam strength with decreasing surfactant concentration. Instead, the study shows that the effect of surfactant concentration can be correlated with the dry-out function of the IT model, and specifically to the limiting capillary pressure
Oil Recovery from Outcrop Cores with Polymeric Nano-Spheres
Authors: Lenchenkov Nikita S. , Slob Michiel , van Dalen Ernst , Glasbergen Gerard , van Kruijsdijk Cor 
Published: March 2016

Abstract
In order to improve oil recovery from water flooded heterogeneous oil reservoirs, different chemical enhanced oil recovery (cEOR) technologies can be applied. One of the recently developed cEOR technologies for the improvement of oil recovery is based on prefabricated polymeric nano-spheres. These spheres are able to swell over time through absorption of brine. Literature review on the flow of the nano-spheres in porous media showed that the mechanism of oil displacement from heterogeneous as well as homogenous porous media is not well established. One of the proposed mechanisms is that prefabricated polymeric particles might reduce the residual oil saturation Sor (Goudarzi et al. 2014).
To validate this, a series of core flood experiments was carried out in order to study this mechanism in both a heterogeneous Boise outcrop and homogeneous Bentheimer outcrop. Saturation of the cores with highly viscous crude oil was done at 50˚C using the porous plates method. After the oil saturated core was water flooded at 1 ft/day, a bump flood was performed. It helped to achieve the residual oil saturation in the core. Subsequently, several slugs of the nano-spheres were injected into the core in order to study the influence of the nano-spheres on the residual oil saturation. In addition to that, the propagation of the nano-spheres in the core was studied via a pressure drop measurement at different sections of the core and by effluent collection.
The results of the experiments show that the oil displacement from a core with nano-spheres after a bump flood is marginal. Some oil extraction with nano-spheres might have happened due to restricting the flow in the highly permeable zones of the core. The subsequent injection of water could potentially result in improved microscopic sweep efficiency and increased oil production. However, in our experiments this effect was not significant. Our results do not show that nano-spheres significantly reduce the residual oil saturation of the core. Additional measurements showed that the nano-spheres are mostly retained in the inlet section of the core and the propagation of the nano-spheres in porous media is slow. Therefore, the effect of the extra oil recovery is likely limited to the inlet section of the core.
There is currently limited description in the literature on the oil recovery mechanism by polymeric nano-spheres. It has a large impact on how the behaviour of the nano-spheres in porous media needs to be modelled and on the screening of candidate reservoirs for the conditions described in the experiments. In our experiments we have seen no significant reduction of residual oil saturation and slow propagation. Further work is required to evaluate the conditions under which the performance of the nano-spheres can be improved.
Comprehensive Review of Fracture Control for Conformance Improvement in the Kuparuk River Unit - Alaska
Authors: Mishra Ashok , Abbas Sayeed , Braden John , Hazen Mike , Li Gaoming , Peirce John , Smith David D. , Lantz Michael 
Published: March 2016

Abstract
This paper is a field case review of the process and methodologies used to identify, characterize, design, and execute a solution for a waterflood conformance problem in the Kuparuk River Unit in late 2013. In addition, post treatment analysis in a complex WAG flood will be discussed. The Kuparuk River Field is a highly fractured and faulted, multi-layer sandstone reservoir located on the North Slope of Alaska. Large scale water injection in the field was initiated in 1981 and overall the field responded favorably to waterflood operations. In 1996, Kuparuk implemented a miscible WAG flood in many areas of the field. However, natural fault and fracture connectivity has resulted in some significant conformance issues between high angle wells in the periphery. Methodologies employed to identify and characterize one specific conformance issue will be outlined. Details of diagnostic efforts, and how they were used to identify, characterize and mitigate an injector/producer interaction through a void space conduit will be discussed. The solution selected to resolve this conformance issue involved pumping a large crosslinked hydrolyzed polyacrylamide (HPAM) gel system. The solution used a tapered concentration design with one of the highest molecular weight HPAM polymers available. Before execution of this solution, extensive history matching and modeling of the solution design and benefits were used to justify this effort. These modeling efforts and their projections will be reviewed. This solution was pumped into the offending injector in late 2013, and offset producers were carefully monitored for gel breakthrough. The polymer treatment design parameters, including rates and pressure limits were used to generate an effective solution. A discussion of this active design approach, a complete review of the well problem dynamics, treatment operations, products used, and potential complications associated with these products will be discussed. Post solution execution performance analysis was difficult due to the active nature of this MWAG flood. A variety of plotting and analysis techniques were used to identify and quantify the results. A discussion of these results will be provided. Finally, a summary of lessons learned, and a limited discussion of future plans will be presented.
Robust and Efficient Isenthalpic Flash Algorithms for Thermal Recovery of Heavy Oil
Authors: Paterson Duncan , Yan Wei , Michelsen Michael L. , Stenby Erling H. 
Published: March 2016

Abstract
The use of isenthalpic flash has become of interest for the simulation of some heavy oil recovery processes where large temperature changes are experienced. For these thermal simulations energy can be used as a primary variable. This leads to thousands or millions of individual multiphase isenthalpic flash calculations. Robust and efficient algorithms for multiple-phase isenthalpic flash are required to improve the efficiency of compositional simulations for thermal recovery.
The general framework on state function based flash specifications proposed by Michelsen (1999) is applied to general multiphase isenthalpic flash. An extension to the general multiphase case is presented for the two-phase Jacobian. This can be formulated as either a partial Newton or full Newton procedure. An extended solution strategy is presented to deal with many of the problems found in isenthalpic flash. This incorporates Q function maximisation for instances where other methods are not convergent.
Narrow boiling mixtures can be dealt with in the majority of cases without any significant difficulty. This is true of the direct substitution algorithm and the proposed solution procedure. The vast majority of examples can be solved without using Q function maximisation. The challenges associated with multiphase calculations in the Newton steps are investigated. In particular, inadequate initial estimate of the equilibrium type may lead to non-convergent iteration. This can usually be solved by introduction of a new phase and/or elimination of an existing phase. The speed of the method is analysed for a large number of specifications and is found to be only slightly more expensive than isothermal flash in the majority of cases.
Use of Partitioning Tracers to Estimate Oil Saturation Distribution in Heterogeneous Reservoirs
Authors: Dean R. M. , Walker D. L. , Dwarakanath V. , Malik T. , Spilker K. 
Published: March 2016

Abstract
Partitioning interwell tracer tests (PITTs) have been used to estimate remaining oil saturations during waterflooding. Compared to core tests, well logs and single well tracer tests, PITTs sample a much larger representative elemental volume (REV) and provide interwell estimates of remaining oil saturation. The test has historically been used to estimate residual oil saturation (Sorw) after waterflooding between injector-producer pairs when the oil is essentially immobile. During polymer flooding, especially with viscous oil, additional oil is displaced and traditional means of interpreting PITTs are not valid. In this paper we present the information gained from conducting a polymer PITT and the saturation estimated during the PITT. This paper presents mechanistic insights into tracer and polymer velocities during the PITT and hence allows for an estimate of remaining oil saturation left behind after polymer flooding and also presents a new log-normal fit which can be used to match multiple flow path responses as is seen in actual field tracer data and reduce the error in estimates of remaining oil saturation. The polymer PITT therefore allows characterization of polymer flood efficiency and is a useful tool in polymer flood evaluations in heterogeneous reservoirs.