bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bakken IOR Model for a Pilot Injection Project
Authors: Hoffman B. Todd 
Published: March 2018

Abstract
Over the last decade, unconventional resources like the Bakken formation have revolutionized the petroleum industry, but they have only produced by primary mechanisms, and recovery factors have remained low. The need for IOR processes is clear, but there has only been minor work in this area and no commercial field applications. Flow simulation models can be used to test different methods without interrupting field operations, but models have had a poor track record for unconventional IOR, partly because there is little field injection information to validate the models. In this work, we history matched the model to an IOR injection pilot location in Mountrail County, North Dakota that included both water and gas injection tests.
A county sized geologic model was previously constructed based upon available core, log and geologic information. The model allows for easy extraction of smaller segments for flow simulation. For the current study, a segment around the pilot injection area was isolated. The injection well and two offset producing wells were included in the model. Fluids were added into the model based on a nearby PVT report, and the hydraulic fracturing was captured with a dual permeability grid. The model was matched to the historical production and injection data. At the offset wells, breakthrough times, water cuts and gas oil ratios were also reproduced by changing the fracture and matrix properties.
By matching the injection data, the interwell connectivity is reproduced, which should improve predictions from the model. Various situations were then tested with the model including both gas and water injection scenarios. In the actual field pilot, gas was only injected for two months in the injection well, and there was only a minor response. In one scenario, therefore, we injected into all three wells in a huff-n-puff manner for ten years, and the results showed significant additional oil recovered – 30% more than the primary recovery. In other scenarios, water was injected in both a continuous and huff-n-puff manner. The continuous case had early breakthrough and poor sweep, but the huff-n-puff injection case indicated that oil rates would increase almost as much as the best gas injection cases.
This work shows that by reproducing the field injection data in unconventional reservoirs, more realistic models are created. We evaluated a large number of scenarios, and some of them did not show any increase in oil production, but the models that did show an increase helped us identify IOR techniques that have a better chance of success in the Bakken, which will improve designing the much needed next generation of field pilot tests.
X-Ray Micro-Focus Monitoring of Water Alternating Gas Injection in Heterogeneous Formations
Authors: Luo J. S. , Chen X. , Espinoza D. N. , Nguyen Q. P. 
Published: March 2018

Abstract
Water alternating gas (WAG) injection is a common technique in enhanced oil recovery. However, gas injection often associates with fingering due to high gas mobility, which leaves a large portion of the reservoir unswept. This study addresses gas mobility control observations through novel X-ray microfocus visualization of core-flood experiments and interpretation aided by numerical simulation. We use foam as our primary mobility control agent for improving conformance.
The experimental setup utilizes an automated fluid injection system monitored by an X-ray microfocus scanner to quantify displacement patterns and saturations during WAG core-flood experiments. The core-flood device – placed within an X-ray shielded cabinet – is wirelessly operated through a computer. The resolution of the images permits observation of not only core scale fingering but also pore-scale displacement. We use a metastable foam with surfactant dissolved in the liquid phase to stabilize the gas diffusion in the liquid and to decrease the permeability and/or lower the apparent gas viscosity.
Results show that saturation patterns and displacement front during WAG injection are highly influenced by bedding orientation and rock heterogeneity. Without gas mobility control during WAG injection, fingering and early breakthrough occur in those cases in which bedding orientation facilitates gas to flow through high permeability layers. In these cases, sweep efficiency is low during early time injection of nitrogen and only improves after injection is prolonged. With gas mobility control, the displacement efficiency is significantly improved. Also, dynamic processes like phase trapping, which could severely impair permeability and overall sweep efficiency, is more clearly visualized with the microfocus technique. Simulation work matches experimental data well and replicates saturation patterns measured experimentally in laminated Berea sandstone samples.
The novel visualization technique presented here provides new pore-scale experimental insight to quantifying WAG displacement in heterogeneous media, a resolution one order of magnitude higher than with medical X-ray CT or other core-scale visualization techniques. The findings are useful for understanding flow regimes in structurally complex and heterogeneous formations.
An Experimental Study of Emulsion Flow in Alkaline Solvent Coinjection with Steam for Heavy-Oil/Bitumen Recovery
Authors: Sheng Kai , Argüelles-Vivas Francisco J. , Baek Kwang Hoon , Okuno Ryosuke 
Published: March 2018

Abstract
Water is the dominant component in steam injection processes, such as steam-assisted gravity drainage (SAGD). The central hypothesis in this research is that in-situ oil transport can be enhanced by generating oil-in-water emulsion, where the water-continuous phase acts as an effective oil carrier. As part of the research project, this paper presents an experimental study of how oil-in-water emulsion can improve oil transport in porous media at elevated temperatures from 373 K to 443 K.
Diethyl amine (DEA) was selected as the organic alkali to form oil-in-water emulsions with Athabasca bitumen and NaCl brine at 1000 ppm salinity and 0.5 wt% alkali concentration. This composition had been confirmed to be optimal in terms of oil solubility in the water-external emulsion phase at a wide range of temperatures. Then, flow experiments with a glass-beads pack were conducted to measure effective viscosities for emulsion samples at shear rates from 5 to 29 sec−1.
Results show that the oil-in-water emulsions were more than 18 times less viscous than the original bitumen at 373 and 403 K. At an estimated shear rate of 5 sec−1, for example, the emulsion viscosity was 12 cp at 373 K, at which the bitumen viscosity was 273 cp. The efficiency of in-situ bitumen transport was evaluated by calculating bitumen molar flow rate under gravity drainage with the new experimental data. Results show that oil-in-water emulsion can enhance in-situ molar flow of bitumen by a factor of 64 at 403 K and 95 at 373 K, in comparison with the gravity drainage of oil-water two phases in conventional SAGD. This is mainly because the mobility of the bitumen-containing phase is enhanced by the reduced viscosity and increased effective permeability. A marked difference between alkaline solvents and conventional hydrocarbon solvents is that only a small amount of alkaline solvent enables to enhance in-situ transport of bitumen.
Design, History Matching and Utility of a Simulation Model for a Polymer Pilot
Authors: Thompson A. R. , Martino L. A. , Gandi S. , Barros P. 
Published: March 2018

Abstract
A polymer injection pilot started in 2015 in the Rayoso Formation, Desfiladero Bayo field (Neuquen Basin, Argentina) A detailed monitoring of the pilot was planned and the amount of data anticipated led to the construction of a reservoir model with a high level of detail in order to compare the results to prognosis and to reduce the uncertainty to the business case forecast.
A specific complication was that the Rayoso Fm. had been produced to date in a commingled way with no exclusive production data before the pilot. Subsequently other data was needed to constrain the simulation model. Clearly, when the pilot started, the Rayoso Fm. was not in a virgin state (after ten years of waterflooding), so RFT data, saturation logs of infill wells, injection logs, tracer and geochemical data were used instead, adding production and injection exclusively from the Rayoso Fm. in the new wells and workovers subsequent to the pilot starting.
The history match of the water injection stage of the pilot showed things that were not initially obvious; one was that the production of one of the pilot producer wells was not consistent with the log response and core data. It was subsequently established that errors were occurring in the production tests of this well in the field that were then corrected.
Breakthrough times for water were consequently history matched and it was established that even after polymer injection started, water cut was expected to initially rise, this being key for expectation management.
As the pilot has progressed, the tracer dosed with the polymer was seen before polymer, this suggesting either the presence of a thief zone or as a methodology for estimating the polymer retention. Additionally the mismatch of tracers between the simulation and actual data was used to estimate the real injection rates into the Rayoso Fm. of commingled injectors lying near the pilot area.
In this paper we discuss how a detailed pilot simulation model can be constructed and constrained when production data specific to the formation is absent. Subsequently, when field results are different to expectation, simulation can be used as tool to establish the probable cause of the deviation from prognosis and hence identify remedial action if required. Finally, the simulation model was key to manage expectations; unrealistic expectations are one of the leading causes of pilots failing.
Oil Recovery by Alkaline-Surfactant-Foam ASF Flooding: Effect of Drive Foam Quality on Oil Bank Propagation
Authors: Janssen Martijn T. , Zitha Pacelli L. , Pilus Rashidah M. 
Published: March 2018

Abstract
Alkaline-Surfactant-Foam flooding is a novel enhanced oil recovery process which increases oil recovery over water flooding by combining lowering of the oil-water interfacial tension by two to three orders of magnitude and foaming. We report an experimental study of the formation of the oil bank and its displacement by foam drives of varying qualities. Experiments include: (a) bulk phase behaviour and foam testing studies using n-hexadecane and a single internal olefin sulfonate surfactant which was found to lower the oil-water interfacial tension by at least two orders of magnitude and (b) series of CT scanned core-floods using Bentheimer sandstone cores. A major goal of this study was to investigate the effect of drive foam quality on oil bank displacement. Core-flood results, performed at under-optimum salinity conditions yielding an oil-water interfacial tension in the order of 10−1 mN/m, showed similar ultimate oil recovery factors for the range of drive foam qualities studied. Although the total oil recovery is not affected by drive foam quality, results indicate a more frontal oil bank displacement at lower foam qualities. The findings in this study suggest that a) a lower drive foam quality favours oil bank displacement and b) the amount of clean oil produced by the oil bank is not effected by drive foam quality.
Effect of Salinity on Crude Oil/Brine/Rock Interfaces: A Cryo-BIB-SEM Approach to Carbonates Wettability
Authors: Gmira A. , Cha D. K. , Al-Enezi S. M. , Yousef A. A. 
Published: March 2018

Abstract
Smart water and low salinity waterflooding has been established as an effective recovery method in carbonate reservoirs by demonstrating a significant incremental oil recoveries in secondary and tertiary modes compared to seawater injection. Therefore, understanding of multiphase flow phenomena in reservoir rocks is critical to optimize injected water formulations for substantial increase in oil recovery. Characterization of fluid-fluid and fluid-rock interactions have been extensively conducted at micro- and macroscopic scale, attempting to reveal the underlying mechanisms responsible for wettability alteration. Indeed, routine methods for assessing macro-wettability of fluids on rock surfaces (contact angle) include the sessile drop and captive bubble techniques. However, these two techniques can provide different contact angle depending on rock surface heterogeneities, roughness and drop size. Thus, contact angle measured at macroscale can only be used to characterize the average wettability and a direct visualization at nanoscale is needed to identify oil and brine distribution in the carbonate matrix and wettability state at the pore scale. The application of ion-beam milling techniques allows investigation of the porosity at the nanometer scale using scanning electron microscopy (SEM). Imaging of carbonate porosity by SEM of surfaces prepared by broad ion beam (BIB) and under cryogenic conditions allow to investigate preserved fluids inside the rock porosity and, combined with energy dispersive spectroscopy (EDS) identify crude oil and brine distributions and quantify carbonate-oil interfaces and wettability state. The experiments have been conducted on carbonate rock samples aged in crude oil and saturated with brines at high and reduced ionic strength. This study established an experimental protocol using Cryogenic high resolution broad ion beam (Cryo-BIB SEM) equipped with energy dispersive spectroscopy (EDS). The results show that ion-BIB milling provides a smooth surface area with large cross-section of few mm2. High resolution imaging analysis allowed identification of the different phases, chemical mapping and distribution of oil, brine within the porous matrix. Segmentation of rock-oil-brine interface allowed an estimation of the in-situ contact angle and showed the effect of injected salinity brine on the 2D contact angle and more accurate description of the carbonate wettability at nanoscale.
Experimental and Theoretical Study of Operating Pressure and Capillary Pressure on Vapor Oil Gravity Drainage VOGD in Fractured Reservoirs
Authors: Tang B. , Anand N. , Nguyen B. , Sie C. , Verlaan M. , Díaz O. Castellanos , Nguyen Q. P. 
Published: March 2018

Abstract
The Vapor-Oil Gravity Drainage (VOGD) is a low temperature, solvent-enhanced gas-oil gravity drainage (GOGD) process targeting naturally fractured viscous reservoirs. The experimental set up and corresponding acquired data was previously introduced by the authors (Anand et al., 2017) in which the effects of temperature, solvent injection rate, and solvent type (n-Butane and dichloromethane (DCM)) were investigated. Results from Anand et al. work indicated encouraging high oil rates and ultimate recoveries; results also demonstrated that the oil rates and recovery were impacted by diffusion and dispersion (in the form of intrinsic gas rate), asphaltene precipitation, and capillary pressure. The intent of this work is to further study the mechanisms behind VOGD; in particular those related to operating pressure and solvent vapor-oil capillary pressure. The results from this work show that the ultimate recovery and oil rate are positively correlated to the operating pressure; experiments conducted at 50% and 75% saturation pressure (Psat) yielded lower ultimate oil recoveries, ranging from 33% to 68% of original oil in place (OOIP), when compared to the experiments conducted at 90% Psat (70% of OOIP). Moreover, n-butane performed better than DCM and lesser asphaltene precipitation was seen at lower Psat. The main drivers for these observations were found to be lower solvent solubility and larger capillary pressure values at lower values of Psat.
Solvent Leakoff During Gel Placement in Fractures: Extension to Oil-Saturated Porous Media
Authors: Brattekås B. , Ersland G. , Seright R. S. 
Published: March 2018

Abstract
Crosslinked polymers extrude through fractures during placement of many conformance improvement treatments, as well as during hydraulic fracturing. Dehydration of polymer gel during extrusion through fractures has often been observed, and was extensively investigated during the last decades. Injection of highly-viscous gel increases the pressure in a fracture, which promotes gel dehydration by solvent leakoff into the adjacent matrix. The present comprehension of gel behavior dictates that the rate of solvent leakoff will be controlled by the gel and fracture properties, and to a less extent impacted by the properties of an adjacent porous medium. However; several experimental results, presented in this work, indicate that solvent leakoff deviates from expected behavior when oil is present in the fracture-adjacent matrix. We investigated solvent leakoff from Cr(III)-Acetate-HPAM gels during extrusion through oil-saturated, fractured core plugs. The matrix properties were varied to evaluate the impact of pore size, permeability and heterogeneity on gel dehydration and solvent leakoff rate. A deviating leakoff behavior during gel propagation through fractured, oil-saturated core plugs was observed, associated with the formation of a capillary driven displacement front in the matrix. Magnetic Resonance Imaging (MRI) was used to image water leakoff in a fractured, oil-saturated carbonate core plug and verified the position and existence of a stable displacement front. The use of MRI also identified the presence of wormholes in the gel, during and after gel placement, which supports gel behavior similar to the previously proposed Seright filter-cake model. An explanation is offered for when the matrix impacts gel dehydration and supported by imaging. Our results show that the properties of a reservoir rock may impact gel dehydration; which, in turn, strongly impacts the depth of gel penetration into a fracture network, and the gel strength during chase floods.
Performance of Conformance Gels Under Harsh Conditions
Authors: Unomah Michael , Thach Sophany , Shong Robert , App Jeff , Zhang Tiantian , Kim Do Hoon , Malik Taimur , Dwarakanath Varadarajan 
Published: March 2018

Abstract
Permeability reduction provided by conventional polymer gels is affected by harsh reservoir conditions. Harsh conditions are defined by high temperature (&gt; 75°C), high salinity, high divalent ions and the presence of H2S. Polymer gels undergo syneresis when exposed to high salinity and hardness reservoir brines. We evaluated conventional polyacrylamide-based polymer (HPAM)-gels and other modified HPAM-gels with molecular weights between 2-20MM Daltons for gelation time and long-term gel stability under harsh conditions. In addition to polymer degradation, the cross-linkers are also sensitive to harsh reservoir conditions. Specifically, H2S can consume cross-linkers and inhibit gelation. The cross-linkers tested were Chromium (III) Acetate and Chevron Unogel formulation consisting of a combination of hexamethylenetetramine (HMTA) and hydroquinone (HQ). High performing gels were tested for sensitivity to high salinity brines and H2S in a limited number of experiments. The gels were observed for gel strength, and syneresis with time. The goal of our work was to identify a combination of polymer and cross-linker that would provide effective conformance under harsh conditions.
Sulfonated polyacrylamide (ATBS) polymers were found to provide better resistance to high salinity/hardness brines than partially hydrolyzed polyacrylamides in high temperature conditions. The addition of hydrophobic groups to the sulfonated-acrylamide backbone does not increase the hardness tolerance of the polymer. Higher concentration, low molecular weight sulfonated polymers are recommended for use at high temperature and salinity. Polymer gels made with 2MM Dalton polymer show less syneresis with time compared to higher molecular weight polymer at the same polymer concentration. HMTA/HQ ATBS polymer gels are preferable to chromium (III) ATBS polymer gel for high temperature and salinity conditions. Chromium (III) ATBS polymer gels show more susceptibility to syneresis compared to organic crosslinked gels at same polymer concentration. HMTA/HQ crosslinker is ineffective in the presence of hydrogen sulfide. Gelants consisting of HMTA/HQ do not mature into rigid gels after 14 days of exposure to sour gas. Preformed HMTA/HQ gels lose strength upon exposure to sour crude. This is mostly due to HMTA ability as a sour gas/crude sweetener. Chromium (III) gels form weak gels in the presence of sour gas. Chromium competes with sulfide ions to produce insoluble chromium sulfide leading to consumption of crosslinker and poor gelation. Malonate and tartrate are effective gel retardants for chromium (III) polymer gels. Malonate is better at extending onset of gelation for longer periods of time. Tartrate is more effective for shorter gelation time at lower concentrations.
Co-Current Spontaneous Imbibition in Porous Media with the Dynamics of Viscous Coupling and Capillary Back Pressure
Authors: Andersen Pål Østebø , Qiao Yangyang , Standnes Dag Chun , Evje Steinar 
Published: March 2018

Abstract
This paper presents a numerical study of water displacing oil by combined co-current / counter-current spontaneous imbibition (SI) of water displacing oil from a water-wet matrix block exposed to water at one side and oil at the other. Counter-current flows can induce a stronger viscous coupling than during co-current flows leading to deceleration of the phases. Even as water displaces oil co-currently the saturation gradient in the block induces counter-current capillary diffusion. The extent of counter-current flow may dominate the domain of the matrix block near the water-exposed surfaces, while co-current imbibition may dominate the domain near the oil-exposed surfaces implying that one unique effective relative permeability curve for each phase does not adequately represent the system. As relative permeabilities are routinely measured co-currently it is an open question whether the imbibition rates in the reservoir (depending on a variety of flow regimes and parameters) will in fact be correctly predicted. We present a generalized two phase flow model based on momentum equations from mixture theory that can account dynamically for viscous coupling between the phases and the porous media due to fluid-rock interaction (friction) and fluid-fluid interaction (drag). These momentum equations effectively replace and generalize Darcy's law. The model is parameterized using experimental data from the literature.
We consider a water-wet matrix block in 1D that is exposed to oil on one side and water on the other side. This setup favors co-current SI. We also account for the fact that oil produced counter-currently into water must overcome the socalled capillary back pressure, which represents a resistance for oil to be produced as droplets. This parameter can thus influence the extent of counter-current production and hence, viscous coupling. This complex mixture of flow regimes implies that it is not straightforward to model the system by a single set of relative permeabilities, but rather relies on a generalized momentum equation model that couples the two phases. In particular, directly applying co-currently measured relative permeability curves gives significantly different predictions than the generalized model. It is seen that at high water-to-oil mobility ratios, viscous coupling can lower the imbibition rate and shift the production from less counter-current to more co-current as compared to conventional modelling. Although the viscous coupling effects are triggered by counter-current flow, reducing or eliminating counter-current production via the capillary back pressure does not eliminate the effects of viscous coupling that take place inside the core, which effectively lower the mobility of the system. It was further seen that viscous coupling can increase the remaining oil saturation in standard co-current imbibition setups.