bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predicting the Effects of Acid Gas on Enhanced Oil Recovery in Hydrocarbon Gas Injection
Authors: Lv Sanbo , Liao Xinwei , Chen Hao , Chen Zhiming , Lv Xianwei , Zhou Xiaojin 
Published: April 2016

Abstract
Hydrocarbon gas injection is one of the major EOR methods. Hydrocarbon gas has some similar properties with the oil in reservoir, which has no damage to the formation. In addition, there is a beneficial mass transfer between hydrocarbon gas and crude oil, when achieving miscibility, the residual oil saturation where the area is affected by hydrocarbon gas is very low. The effects of the components of hydrocarbon gas as well as its impurities on enhanced oil recovery have been researched. However, in some fields, injected gas is from the produced gas with large amounts of acid gas. The corresponding EOR effects of hydrocarbon gas with high acid gas content are rarely mentioned in the literatures. Thus it is necessary to study it when hydrocarbon gas with acid gas is injected.
In this paper, acid gas consisting two common components (78.11% of H2S and 21.89% of CO2 respectively) is studied. The oil sample from typical block in K oil reservoir is selected to investigate the EOR effects of hydrocarbon gas with the above acid gas. The slim-tube experiments are performed with different percentages of acid gas in injected gas at different displacement pressures. The acid gas percentages are respectively 0%, 10%, 20%, 30%, 40%, 50%. The experimental procedure is that firstly the slim tube is saturated with oil, then it is displaced by hydrocarbon gas with one certain percentage of acid gas at constant temperature and displacement pressure. The ultimate oil recovery which is also considered to be the displacement efficiency is obtained after injecting 1.2 pore volumes of gas or when there is no oil production. Similarly, the experiments at different pressures are also conducted.
The experimental results show that under the same temperature, oil composition and gas composition, the displacement efficiency increases as the displacement pressure increases. However, displacement efficiency is no longer increasing when displacement pressure increases to one certain value. This pressure point, that is to say, is minimum miscibility pressure (MMP). It means, when the pressure is higher than MMP, the effects of displacement pressure on the oil recovery would not be significant. The experimental results also indicate that under the same temperature, oil composition and displacement pressure, displacement efficiency increases as the percentage of acid gas in the injected gas increases.
From the work here, MMP can be predicted. The effects of acid gas on enhanced oil recovery can also be estimated. In the oil field, all the results can be for reference in hydrocarbon gas injection with high acid gas content. In a word, this work is very meaningful, which provides a new perspective on enhancing oil recovery as well as cutting the pollution of acid gas. It is a win-win work.
Increasing Performance of Multilateral Wells Using Oil Fingerprinting
Authors: Jensen M. D. , Werner M. R. , McCaffrey M. A. , Dahl J. E. 
Published: April 2016

Abstract
In multilateral wells, several distinct processes including sand production, mechanical failure, and pattern depletion can cause a decrease in overall well performance over time. Within a lateral, sand can fall out from the production stream and form sand bridges that obstruct production from that lateral. In addition, sand co-produced with oil from shallower laterals can settle through the production stream to obstruct the entry to a deeper lateral. However, a decrease in production cannot be assumed to be due to obstructions formed by co-produced sand, since a variety of completely different processes can also reduce production. It is critical to know the cause of decreased production from a well, since which method is used to reverse the decrease in production very much depends on the cause of the decrease.
Geochemical techniques can be used to quantitatively determine the contribution of each of several zones to a commingled oil (or gas) stream. This technique costs less than 1-2% of the cost of production logging. One particularly useful application of this technique is using oil fingerprinting to identify sanded-out intervals for fill cleanout (FCO)
In brief, production allocation is achieved by identifying chemical differences between end-member oils (single-zone samples collected from each of the zones being commingled). Parameters reflecting those compositional differences are then measured in the commingled oil. Those data are then used to mathematically express the composition of the commingled oil in terms of contributions from the respective end-member oils. That result is achieved using a linear algebra manipulation of the concentrations of 150-250 compounds naturally occurring in the end member oils and the commingled oils.
In the current study, we show three examples where this approach was used to identify a sanded out interval in each of three wells. Once the sanded-out interval was identified, an appropriate FCO operation could be conducted. This approach resulted in increased production of 200 BOPD, 500 BOPD, and 400 BOPD in the three respective wells. For those wells, the cost of the geochemical analysis was less than the value of 1 hr of increased oil production.
Unlocking the Potential of Monterey Shale Resource: An Analysis of Geological Characteristics, Completion Techniques, and Production Behaviors
Authors: Saini D. , Wright J. , Mantas M. , Mezei T. , Gomes C. , Shetty S. , Sirajuddin M. 
Published: April 2016

Abstract
Over the last thirty years, technology used to produce hydrocarbons has grown exponentially. With the optimization and combination of technologies such as horizontal drilling and hydraulic fracturing, the ability to produce low-permeability or tight hydrocarbon-bearing rocks (shale formations) which were once deemed economically impractical has now become a reality. However, these technologies which have made hydrocarbon production from unconventional reservoir possible have not been implemented in California's Monterey Shale Formation for its wide scale exploitation. Also, due to the relatively short time period of these technological advancements, there seems to be limited research that provides a comprehensive comparison of these three major U.S. analogous shale plays (i.e. Bakken, Eagle Ford, and Monterey) for gaining better understanding on their potential use in future exploitation of Monterey Formation.
First, using publically available data, a comparison of key geological characteristics, completion techniques, and production behaviors of Bakken, Eagle Ford, and Monterey shale plays is presented. Monterey shale is very young and geologically heterogeneous compared to Eagle Ford and Bakken but holds significantly more reserves. Compared to Bakken and Eagle Ford, oil viscosity in Monterey shale is significantly higher and one can also notice that Monterey oil production has declined over the years. Monterey shale has a field dependent completion (pattern spacing and fracturing stage) strategy.
Second, the similar analysis is expended to three Monterey specific oil fields (M, N, and R) that are located in the San Joaquin basin (SJB) of California. A detailed diagnosis of the production behaviors of both the horizontal hydraulically fractured and horizontal non-fractured wells present in the R Field shows that actually non-fractured horizontal wells are more productive which reinforce the needs of a new completion as well as new enhanced recovery strategies that could assist in future development of California's Monterey shale resource while complying with the toughest hydraulic fracturing regulations in the nation.
Though water use per hydraulic fracturing job is relatively low, nearly all fracturing water use in California is in regions of extremely high water stress. The potential use of oilfield-produced water for preparing fracturing fluid formulations can also assist industry in unlocking the potential of Monterey shale without putting burden on precious fresh water resources of the region.
The Effects of Faults on Induced Seismicity Potential During Water Disposal and Hydraulic Fracturing
Authors: Umholtz N. , Ouenes A. 
Published: April 2016

Abstract
A predictive geomechanical model of induced seismic events across many Oklahoma counties is presented—the potential of this validated workflow to address numerous concerns with recent earthquakes is demonstrated. A network of large scale faults can greatly alter the stress field, and consequently the potential of induced seismic events resulting from water injection. These effects are quantified using a geomechanical workflow that leads to the estimation of Induced Seismicity Potential (ISP). It appears that most of the recent earthquakes are clustered in high ISP areas which could be found near but also away from critically stressed faults that were the focus of most recent investigations. When considering the volumes of water injected, the low ISP areas seems to accept large volumes without causing any major earthquakes. In contrast, high ISP areas near Oklahoma City, seem to have many earthquakes despite the low volumes of injected water. In other words, the location of the water injection wells seems to be a critical factor impacting the inducement of earthquakes and reduction of water volumes alone may not reduce induced seismicity. The lack of earthquakes near very large injectors located in low ISP areas seems to point to the need to restrict water injection only to low ISP areas which may reduce the number and magnitude of earthquakes. This predictive tool could assist regulators, oil and gas companies, and insurance companies in selecting areas with the lowest risk of induced seismicity while bolstering the social license to operate unconventional reservoirs.
Production Geology as a Tool for Monitoring Water Influx in a Compartmentalized California Monterey Fractured Reservoir
Authors: Zhao Xiaoxi , Ershaghi Iraj 
Published: April 2016

Abstract
This paper through a case study exemplifies the use of some common sense reservoir engineering methods using performance data in characterizing heterogeneity and compartmentalization in a complex fractured reservoir producing from the Monterey formation. The field is highly faulted and water influx has been a source of energy in this reservoir.
Guided by 2D-3D seismic interpretation, we have examined the merits of using performance data (oil rate, cumulative oil production, GOR and WOR) to characterize block to block communication as an important aspect in characterization of geological complexities in various compartments of the reservoir. Using performance data for a number of wells, we have made estimations about the historical rise of oil-water contact and its relationship to the water influx, communication among blocks, block capacities and future production potential. Monitoring of water ratios has indicated that there are differences in the level of water entry depending on individual blocks properties. GOR's have indicated different stages of depletion. Our study shows that the performance data can provide insight and further assist in geological characterization.
Water Blocking Caused by Fracturing Fluid Leakage in Mixed-Wet Unconventional Tight Reservoirs
Authors: Kong Bing , Chen Shengnan 
Published: April 2016

Abstract
It has been recognized that, water blocking caused by water-based fracturing fluid leakage is one of the major reasons for well productivity reduction in hydraulic fractured tight formations. Mixed-wettability is broadly existing in tight/shale hydrocarbon reservoirs and it has profound impact on water blocking. In this paper, formation damage caused by water-based fracturing fluid leak-off in mixed-wet tight oil/gas reservoirs is studied. Sensitivity of water blocking on rock wettability, capillarity and permeability is analyzed and early time production is optimized to remediate the damage of formation productivity caused by water blocking.
The sensitivity of the water blocking behavior is studied by using a multi-phase dual-wettability model. Results from the reservoir simulations demonstrated that a well-resting period varying from one to twelve months can significantly affect early productivity rate and reduce flow-back of fracturing fluid in mixed-wet reservoirs. The damage to productivity due to water blocking will be reduced along production in a single-wet reservoir, however this damage is irreversible in a mixed-wet formation. The results also indicate that minimizing water leak-off in the formation is crucial in both single wet and mixed wet reservoirs.
The mixed wettability of an unconventional tight reservoir is considered in this study, and a multi-phase dual-wettability model is applied to study the water blocking in such formation. The results of this study can provide meaningful guide for hydraulic fracturing and early production in mixed-wet unconventional tight reservoirs.
Unlocking Gas From a Methane Hydrate Reservoir – Barrow, Alaska
Authors: Youngmun N. C. , Stokes P. J. , Walsh T. P. 
Published: April 2016

Executive Summary
Drilling and testing of the East Barrow Gas Field (EBGF) began in 1974. Over the next sixteen years, eight vertical production wells were drilled. In 1988, initial gas reserves were estimated to be 6.2 BCF OGIP with 5.7 BCF recoverable. Despite these early predictions, the field has produced approximately 9.1 BCF of natural gas and the reservoir has maintained pressure at ~ 935 psia, which suggests there are still untapped gas resources within the EBGF.
It was initially believed that continual re-pressurization of the reservoir was caused by an active water drive. However, no significant water has been produced, even from down dip producers. Reservoir modeling was performed to better understand reservoir drive mechanisms and to predict future reservoir behavior. Recent modeling and reservoir simulation strongly suggest that gas hydrate dissociation and negligible water influx is responsible for the constant re-pressurization within the EBGF. Recent drilling and production shows that gas production from the EBGF depressurizes the reservoir and raises the base of the gas hydrate stability zone, unlocking free gas from the hydrate bearing reservoir rock. This is a significant finding, and validates the presumption of commercial gas production from a hydrate resource. This paper summarizes the technical studies conducted to understand the reservoir behavior and the evidence supporting ongoing dissociation and production of methane hydrates from the EBGF.
Application of Dynamic Allocation Factors for Waterflood and EOR Performance Management
Authors: McElhaney Kevin , Jemison Jenny , Jhaveri Bharat 
Published: April 2016

Abstract
Field-wide displacement and EOR floods become increasingly difficult to monitor and analyze as a system matures. Dynamic effects such as slug size, well work, pressure management, and concurrent injection can all influence performance in a way that is not captured using geometric static allocation factors. By calculating dynamic allocation factors for each time step, the dynamics of field operations can be attributed to the corresponding wells. Proper allocations can influence field operating strategies by using past performance to predict future returns in the field.
Building on the concept presented in 2006 by Bharat Jhaveri, the dynamic allocation factors are calculated by an iterative process that includes all injection and production data in a time-step. Production-centered allocation factors are dependent on the surrounding volumes of injection supporting the well. Injector-centered allocation factors are dependent on the surrounding production volumes that the injector supports. Interactions are monitored and tracked using a matrix style catalog for each time step. Total injection allocation factors can then be modified for EOR application by taking into account the delayed production enhancing effects caused by solvent injection.
Dynamic allocation factor analysis was completed using real field data on a system with two injectors and fourteen producers. These injectors injected both water and miscible gas on regular WAG cycles. The results of the analysis were used to evaluate waterflood and EOR performance. For the waterflood, maturity, recovery, and pressure management are the metrics required to evaluate field performance. For the EOR performance, maturity, recovery, and utilization are used to optimize oil recovery. Dynamic allocation factors were able to capture lag time in injector-producer interactions, highlight non-interactions between wells owing to geological influence, and changes in reservoir streamlines during periods of shut-in wells.
Traditional well allocation factors between injectors and producers are assigned based on the geometry of that pattern. This method provides a static, unchanging view of the reservoir system, regardless of the operational dynamics. A dynamic allocation factor is derived iteratively to accurately depict reservoir interactions through time. Field management can be improved using this view of how fluids in the reservoir have historically interacted. Injection targets, infill drilling, and changes to injector conformance can all be optimized through analysis employing dynamic allocation factors.
Core to Pore Scale Visual Analyis of Mixing Process in the Presence of Interface Between Heavy-Oil and Solvent
Authors: Hassan Saleh F. , Babadagli Tayfun 
Published: April 2016

Abstract
Solvent injection, which is the only alternative to thermal methods to reduce the viscosity of heavy-oil, requires an effective solvent distribution in the reservoir to achieve the maximum oil-solvent contact. The dilution process, however, becomes slower as oil gets heavier. In this case, an initial interface exists between oil and -liquid or gas- solvent (similar to ultralow immiscible fluids cases). In case of heterogeneous reservoirs (fractured carbonates or wormholed oil sands), the diffusive mixing between the solvent in the fractures/wormholes and matrix oil requires longer contact times. Hence, an initial interface between the solvent and oil may exist and, depending on the wettability conditions, the existence of water and oil/solvent type, capillary imbibition (liquid solvent) or drainage (gas solvent) transfer into the matrix may take place. Intrusion of oil by capillary imbibition accelerates oil recovery reducing the time to get the oil and solvent contacted in order for the dilution (mixing) process to start.
To investigate this phenomenon and perform a parametric analysis, an experimental design was developed focusing on analyzing the oil-solvent mixing zone mechanisms. A wide range of oil types (50cp to 100,000cp) and solvents (heptane and decane) were used. Experiments were performed on oil saturated 3 × 7 cm 2-D glass (core scale) and glass capillary tubes by soaking them into solvent under static conditions. To identify the mixing process (by color gradient) and distinguish the phases, advanced illumination and photographic techniques were applied using UV light and coloring the solvent.
The followed experimental approach employed visual models at core and pore scale levels and successfully displayed the existence of both capillary imbibition and diffusion mechanisms in a solvent heavy-oil system. To what extent capillary imbibition could occur and assist in the recovery by miscible interaction was clarified for different oil, solvent, and wettability conditions. The results revealed that the solvent injection process might be enhanced by other mechanisms (imbibition or drainage) in heterogeneous reservoirs, which is usually neglected in modeling studies.
Initial capillary imbibition took place if the glass surface was more solvent-wet than the original oil. Diffusive mixing followed by convective mixing occurred. Time periods corresponding to different recovery mechanisms were identified for different wettabilities and oil viscosities.
Avoiding Flowline Plugging: A Deposition Velocity Model and Stability Map
Authors: Bbosa Ben , DelleCase Emmanuel , Volk Michael , Ozbayoglu Evren 
Published: April 2016

Abstract
Transportation of solids in form of slurries has become one of the most important unit operations in industries across several disciplines. In fact, the need is more pronounced in industries that are very important for human survival such as food processing, pharmaceuticals and energy (coal, oil and gas). A lot of work has been done in the past 30 years in understanding the factors affecting the deposition velocity of solids in slurries. Experimental observation and theoretical predictions pointed to mixture velocity and solid/fluid properties especially rheology of the resulting slurry to be the most important factors that dramatically affect particle motion and patterning.
This paper presents a critical deposition velocity model and a "stability flow map" for complex rheology slurries. The critical deposition model utilizes a more robust generalized 2-parameter rheology model to account for any given slurry rheology. The "stability flow map" demarcates the different flow patterns that may be observed at different mixture velocity and rheology. On this map, the homogeneous slurries are predicted at low rheology and high mixture velocity whereas heterogeneous slurries (with a concentration gradient) predicted at high rheology (yield stress effects).
Sensitivity analysis was conducted on critical Reynolds number, particle density, carrier fluid density, generalized flow behavior index, and pipe diameter. It was observed that increase in shear thinning behavior, particle density, pipe diameter, and particle diameter led to a decrease in the laminar region and an increased unstable region. The model showed good performance when tested on glass and stainless steel beads test data available in open literature. The model was tested on hydrate slurries generated with additives at The University of Tulsa and the flow regime predictions were in good agreement with observations.
Preliminary simulation with this map may help engineers select flowline size and carrier fluid rheology for a given type of solid particle.