bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comparative Thermal IOR Simulation Study with Experimental Design for Optimal Future Performance of a Heterogeneous Light Oil Reservoir
Authors: Al-Mudhafer Wathiq 
Published: April 2013

Abstract
Steamflooding has been widely used to improve oil recovery in heavy and light oil reservoirs. It has proved its efficiency to thrive the oil displacement and enhance the sweep efficiency by changing the reservoir and fluid properties, especially in heterogeneous formation. The reservoir under study is the main pay/upper sandstone member in South Rumaila oil field located in Iraq. This field, with a 58-year production history, has 40 production wells and is surrounded by an infinite active edge water aquifer from the east and the west flanks. Since the east flank is much less effective than the west one, twenty injection wells have been drilled at the east flank over the last 35 years. The formation depth is 10350 ft. sub-sea with a maximum vertical oil column of 350 ft. The average bubble point pressure of 2660 psi and the average reservoir temperature is 210°F while oil density is 34°API. In this study, a comparative thermodynamic simulation study has been done in conjugation with experimental design to investigate the main factors controlling the Steamflooding feasibility in improve oil recovery and to determine the optimal future Steamflooding scenario that has the maximum cumulative oil Production in a future production period.
Firstly, the thermodynamic reservoir simulator (CMG-STARS) has been applied to demonstrate the impact of steam flooding to enhance the sweep efficiency through this heterogeneous reservoir. A full factorial approach considering full interaction terms has been adopted to determine the optimal Steamflooding scenario considering four main factors to be changed in two-levels. The response in this approach is the cumulative oil production in twelve future production years. The factors are steam quality, steam injection rate, number of steam injection wells, and the steam temperature. For two levels of four factors in full factorial design, sixteen observations have been done according to the (2^k factorial design). The entire analysis of the current designed experiments have been performed by R statistical software packages. The regression model has been tested by ANOVA table, p-value, R Squared & R adjusted, and basic diagnostic plots and it has shown reliable evaluation. The results have shown that the steam quality, injection rate, and no. of wells have the most influence factor on the cumulative oil production in addition to some interaction rate that have no temperature. There is very limited effect of the temperature.
Among these runs, the optimal scenario, which has distinct target, has low levels of steam quality, flow rate, steam injectors, and temperature. The rationale behind these results is that the reservoir under study is light oil and has high heterogeneity at the east flank that lead to high steam distortion and spread. The optimal scenario has been compared with the base case without injection and has distinct different in cumulative oil production.
Weakly Emulsifying Surfactant Reduces Formation Damage and Enhances Well Productivity in Acid Stimulation
Authors: Xu Liang 
Published: April 2013

Abstract
Surfactant is a critical component used during acid stimulation. While many variables, such as interfacial surface tension, wettability, and compatibility with other acid additives, must be considered to tailor a surfactant to specific well conditions, the focus is on the most fundamental property of a surfactant, which is its emulsification tendency. The technical norm for surfactant applications in acidizing, however, is that a non-emulsifying (NE) surfactant should be selected to avoid the formation of tight emulsions. Tight emulsions are thought to block the oil and gas flow by plugging the pore throats in the rocks. While this concept is true to some degree, it neglects the ultimate purpose of surfactant use. In contrast, a weakly emulsifying (WE) surfactant is capable of generating transient oil in water emulsions with lower viscosity; thus, mobilizing the oil more effectively.
In this study, the primary difference between NE and WE surfactant is highlighted in terms of emulsion tendency and using preliminary production data from multiple wells in the Monterey formation.
Natural Convection in CO2-Based VAPEX
Authors: Javaheri Mohammad , Abedi Jalal 
Published: April 2013

Abstract
Vapor Extraction (VAPEX) is a promising technique for the recovery of heavy oils and bitumen in reservoirs where thermal methods cannot be applied. In this work, the effects of dispersion and viscosity variation in the boundary layer of VAPEX on natural convection are studied. Natural convection may happen in VAPEX, if the solvents that are used to decrease oil viscosity, increase its density. This can occur with carbon dioxide-based solvents. The reduction of the oil viscosity due to solvent dissolution can have a large impact on the onset of convection, by decreasing the critical Rayleigh number by up to two orders of magnitude. The analysis shows that the longitudinal Peclet number does not have a significant impact on natural convention; however, the transverse Peclet number is a crucial parameter in determining the critical Rayleigh number. The wave number increases with the Rayleigh number, but decreases with the transverse Peclet number. When the effect of viscosity is included in the analysis of boundary layer instability in VAPEX, natural convection may occur in highly permeable reservoirs, leading to a greater oil production rate. The current models that are used to predict the oil production rate in VAPEX do not consider this effect and underestimate the oil production rate in case natural convection occurs.
Portable Technology Puts Real-Time Automated Mineralogy on the Well Site
Authors: Ashton Tom , Ly Chi Vinh , Spence Graham , Oliver Guy 
Published: April 2013

Abstract
With the growing interest in the using hydraulically fracturing reservoirs both in main land USA and now globally, there has been a growing need to better characterize the reservoir to maximize hydrocarbon recovery while also reducing the overall cost in the recovery of the hydrocarbon. With current fracc-ing regimes relying on a large number of stages to ensure maximum recovery, which in many cases leads to upwards of 30% of these stages being unproductive. This reduces the overall profitability of well even with maximum hydrocarbon recovery. With the ongoing development of automated mineralogy tools, such as the RoqSCAN, there is now the ability to characterize a reservoir at the well-site in real-time and also rapidly in a laboratory.
In this paper we will review the current development of these mobile and ruggedized instruments using a real life project for Eagleridge Energy LLC, on their Burgess lateral well. The paper will show the application of automated mineralogical analysis of cuttings samples pre-drilling in defining stratigratic zones via mineralogy/elemental data. And then explore the application of the same data to assist, and in this case lead, the decision making process during directional drilling of the lateral well. The paper will also look at the use of the technology in defining tactical fracc-ing zone based on rock properties (e.g. ductility) determined from the mineralogical, elemental and textural data.
This paper will show that through the use of automated mineralogical instruments, such as the RoqSCAN, companies can pro-actively steer wells by identifying mineral changes within lateral borehole, indicating a deviation from the target zone. Additionally, this type of technology can be used to reactively steer by it ability to rapidly identification subsurface changes, such as unknown (undetected) faults. Finally the paper will show that through through the better characterization of this reservoir companies can reduce the risk accociated with the drilling of expensive lateral wells.
Water Management in Mature Oil Fields using Preformed Particle Gels
Authors: Goudarzi Ali , Zhang Hao , Varavei Abdoljalil , Hu Yunpeng , Delshad Mojdeh , Bai Baojun , Sepehrnoori Kamy 
Published: April 2013

Abstract
Excess water production is a major problem that leads to early well abandonment and unrecoverable hydrocarbon in mature oil fields. Gel treatments at the injection wells to preferentially plug the thief zones are cost-effective methods to improve sweep efficiency in reservoirs and reduce excess water production during hydrocarbon recovery. A recent gel process uses the preformed particle gels (PPGs) to overcome distinct drawbacks inherent in in-situ gelation systems, i.e. lack of control on gelation time, uncertain gelling due to shear degradation, chromatographic fractionation or change of gel compositions, and dilution by formation water.
This paper describes the results of PPG injection in both fracture and sandpack models where the experimental results were used to develop and validate mechanistic models to design and optimize the flowing gel injection for conformance control processes. Crucial properties gel such as in-situ rheology and swelling ratio in addition to oil recoveries were investigated. The water and oil permeability reduction factors were measured and modeled as a function of gel strength, rock permeability, and flow rate. The PPG transport models were successfully implemented in a reservoir simulator and validated against the laboratory experiments.
A Stochastic Model To Develop Braided Stream Reservoirs: Montalvo Field, Ventura Basin
Authors: Zahner Robert , Morris Peter , Ozgen Chet 
Published: April 2013

Abstract
The Montalvo field has produced 42 million barrels of oil from the 3000 foot thick non-marine fluvial Sespe formation. Pressure transient analysis suggests that individual reservoirs are less than 200 feet in width and have limited connectivity. Since detailed mapping of individual sands is virtually impossible, early development was focused on the bigger sand packages. This case study presents the methodology to pick stepout locations and evaluate bypassed reservoirs in a field that has produced for over 60 years.
With as many as 200 small-scale reservoirs at Montalvo, conventional structure and net pay maps are of limited use when picking locations. Venoco used a stochastic approach that identifies deposition trends with models that varied channel width, length, sinuosity, orientation and facies. Issues addressed include the lack of a common oil-water contact, significant variations in reservoir pressures, and transmissibility of faults. The geologic model was populated with over 1000 realizations then reduced to 133 by history matching fluid production and reservoir pressures in a dynamic model. An objective function was then used to pick the best 30 realizations for prediction runs. The authors concluded it was unrealistic to expect the model to predict recovery from individual wells, but it could identify trends and rank locations. Drilling results have confirmed this conclusion, with a wide variation in performance of the eight wells drilled since 2010 and an average estimated ultimate recovery (EUR) very close to predictions.
The methodology is especially relevant where operators hope to increase recovery in fields with a long production history, poor data resolution, multiple horizons and/or significant variation of reservoir quality. This work shows that it is possible to use reservoir modeling to identify oil reservoirs on a scale smaller than seismic resolution.
Flow Units: From Conventional to Tight Gas to Shale Gas to Tight Oil to Shale Oil Reservoirs
Authors: Aguilera Roberto 
Published: April 2013

Abstract
Core data from various North American basins with the support of limited amounts of data from other basins around the world have shown in the past that process (or delivery) speed provides a continuum between conventional, tight and shale gas reservoirs (Aguilera, 2010). This work extends the previous observation to tight oil and shale oil reservoirs. The link between the various fluids is provided by the word ‘petroleum’ in ‘Total Petroleum System’ (TPS) which encompasses liquid and gas hydrocarbons found in conventional, tight and shale reservoirs. Results of the present study lead to distinctive flow units for each type of reservoir that can be linked empirically to gas and oil rates and under favorable conditions to production decline. To make the work tractable the bulk of the data have been extracted from published geologic and petroleum engineering literature. The paper introduces a new unrestricted transition flow period in tight reservoirs that is recognized by a straight line with a slope of -0.75 on log-log coordinates. This straight line occurs as a transition between 2 linear flow periods.
Process speed is the ratio of permeability and porosity. The approximate boundary between viscous and diffusion dominated flow in gas reservoirs is estimated with Knudsen number which can be calculated from pore throat radius (a function of process speed). Viscous flow is present, for example, when the architecture of the rock is dominated by megaports, macroports, mesoports and sometimes microports (port = pore throat). Diffusion flow on the other hand is observed at the nanoport scale, which can occur in both tight and shale reservoirs.
The process speed concept has been used successfully in conventional petroleum reservoirs for several decades and in tight and shale gas reservoirs during the past 3–4 years. The concept is extended in this paper to tight oil and shale oil reservoirs, and hence to the complete petroleum system, with the support of core and drill-cuttings data. The approach permits estimating volumes of petroleum-in-place, differentiating between viscous and diffusion dominated flow in gas reservoirs and the contribution of each flow mechanism with the use of a unified diffusion-viscous flow model. This is valuable, for example, in those cases where the formation to be developed is composed of alternating stacked layers of tight and shale reservoirs, or where there are lateral variations due to facies changes.
It is concluded that there is significant practical potential in the use of process speed as part of the flow unit characterization and production performance prediction in unconventional petroleum reservoirs.
Group Testing: A Novel Approach To Increase The Effective Frequency Or Accuracy Of Well-tests Without Increasing Infrastructure Costs
Authors: Lin Yenting , Ortega Antonio 
Published: April 2013

Abstract
This paper presents a novel method to increase the well-testing frequency or accuracy without changing current infrastructure. In the current operation of automatic well-testing (AWT) systems, at any given time only one producer is connected to the testing facility in order to perform the flow rate measurement. Thus, AWT systems sequentially perform well-testing for a series of wells in the field, which may take as long as a few weeks for one round of testing, depending on how many wells are assigned to each AWT system. For a testing facility which uses a gravity based separator, the testing period is limited by the minimum time it takes to accumulate a measurable fluid sample in order to produce a sufficiently reliable measurement. In this scenario, low production rate wells are a key limiting factor, because it takes much longer for these to reach a measurable level. We use the "group-testing" concept and propose a novel approach where at any given time the fluid from several wells is diverted to the testing facility. Thus, what is measured is the "sum" of the production of the corresponding wells. Our proposed approach involves changing the combinations of wells (i.e., different combinations of wells are measured at different times) in order to ensure that it is possible to estimate the individual production rates of each well from a series of aggregate measurements. Because we connect multiple wells at the same time, the total fluid rate will be higher and the time needed to reach the level required for a reliable measurement will be reduced, thus making it possible to obtain more frequent well-testing data.
This process can be pre-programmed, automated and requires no-extra manpower in the field. For example, for a low production well it may take 8 hours to accumulate a minimum measurable sample. With our group testing, if we combine four wells together this level will be reached in just 2 hours. In this example, if 24 low production wells are connected to the AWT, the sequential well-testing method requires about 8 days to complete the testing, while our method only takes 2 days, which reduces the well-testing period by 75%.
Modified Inversion Technique for Determining the In-situ Stress Field
Authors: Shahri Mojtaba P. , Miska Stefan Z. , Yu Mengjiao , Ozbayoglu Mehmet E. , Zhang Jianguo , Majidi Reza 
Published: April 2013

Abstract
One of the major challenges of oil industry is to predict the in-situ stress field accurately. Accordingly, different techniques have been developed to predict the reservoir stress field in the past decades. Inversion Technique is a powerful method which was developed to determine the minimum and maximum horizontal stress components and their direction using fracturing data, i.e., leak-off tests or mini-fracture tests, by solving an over-constrained system of equations. As compared to other indirect methods, the actual fracturing data is used in this technique to back calculate the stress field.
In this paper, a new feature is added that enable us to determine the stress field using the data gathered during the production history of reservoir. In this approach, the effect of pore pressure changes on the reservoir stresses is incorporated into the Inversion Technique using constitutive equations of orthotropic rock model. Using the proposed technique, minimum and maximum horizontal stress components can be determined corresponding to different pore pressure during the reservoir life. According to the field data, the new formulation increases the prediction accuracy when fracturing data is gathered corresponding to different pore pressure. The proposed approach can be used for more accurate well design applications during the life of reservoir.
Quantitative Time-Lapse Seismic Integrated History Match in Delhi Field
Authors: Cui Q. , Hoffman B. Todd , Davis T. L. 
Published: April 2013

Abstract
Quantitative integration of time-lapse seismic and flow simulation in a CO2 enhanced oil recovery (EOR) process is an effective tool for performing dynamic reservoir characterization. The non-uniqueness of the history match process is largely reduced by quantitatively incorporating 4D seismic responses along with production data. Many papers in the literature had discussed the application of 4D seismic assisted reservoir simulation in either water flood or EOR reservoirs. However, very few of these publications have touched a stratigraphically complex reservoir with continuous CO2 injection strategy such as Delhi Field in Northeastern Louisiana. In this research, we proposed a time-lapse seismic assisted reservoir simulation workflow to improve history match of CO2 flood stage and reservoir modeling in in Delhi Field. The objective of this work also includes investigating the feasibility of incorporating time-lapse seismic data into history matching a very thin reservoir with unavailable historical water flood scheme. 4D seismic data was utilized in both qualitative and quantitative manner to assist reservoir model updating. A Petro-Elastic Model (PEM) was constructed to connect simulation outputs with seismic attributes. In this process, dynamic simulation results (pressure, saturation and CO2 density) along with elastic moduli were assembled into synthetic seismic attributed. The quantitative comparison of seismic inversion attributes and synthetic seismic attributes is an effective tool to evaluate previous history match process and guide the subsequent model updating.
This paper shows three level of history match process. The first level is preliminary model with poor production rate and pressure match. After that, a careful history match was performed by qualitatively incorporating time-lapse seismic interpretations. As a result, the production is greatly improved. The final stage of is to quantitatively compare synthetic and observed seismic attributes and use the objective function to further optimize the simulation model. The results of level two and three demonstrate that time-lapse seismic plays a significant role in Delhi Field reservoir simulation.
The contribution of this research consists of the following aspects. First, an updated and predictable model is important for the subsequent reservoir engineering work in Reservoir Characterization Project (RCP) at Colorado School of Mines (CSM). Secondly, this work provides an effective integration procedure of interdisciplinary dynamic reservoir characterization process for complex reservoirs. Thirdly, the optimized simulation results validate the effect of 4D seismic integration in continuous CO2 injection EOR process.
Effect of Dynamic Surface Activity of Surfactant on Performance of Foam for Gas Well Deliquification
Authors: Yang Jiang , Wang Xiaoling , Lu Yongjun , Guan Baoshan , Yang Guanke 
Published: April 2013

Abstract
As gas well flow rate decreases, liquid loading occurs in the wellbore and reduces the gas productions. Among various artificial lift methods for liquid removal, foam is one of most economic and widely used method. Foam process in gas deliquification is different from foam applications in drilling fluid and fracturing fluid. The foam for gas well deliquification is generated by gas flow in the tubing. The liquid is accumulated in the thin film of foam and plateau border area, which reduces the overall density of the fluid and unload liquid at lower gas flow rate. In this foaming process, a dynamic diffusion of surfactant to the interface is involved. Dynamic surface and elastic properties of foam are very important parameter to success in foam deliquification. We hereby studied the dynamic surface properties of the foaming surfactant by maximum bubble pressure tensiometer at high flow rate/frequency. The different molecular structures of surfactants were studied and compared. The dynamic surface activity is correlated well to performance of liquid unloading with foam column test method, while equilibrium surface activity obtained by Wilhelmy plate tensiometer is not correlated. Surfactant concentration can be also optimized by evaluation of its dynamic surface activity. For the foam evaluation test method, blender test is also widely used to in the industry to evaluate foam in gas well deliquification. It was found that the two foam generation test methods gave different results when they were compared with the performance of different foamers. The blender foam test is more static, and is not simulated well to the real foam generating process in the gas well. Hence, dynamic surface activity of surfactant by maximum bubble pressure tensiometer gives a high throughput screening parameter to predict performance of different foamers for liquid deliquification.