bluuebunny/crossref_metadata_2025_split huggingface dataset:
Methodology for Development of Laboratory-Based Comprehensive Foam Model for Use in Reservoir Simulation of EOR
Authors: Abbaszadeh Maghsood , Varavei Abdoljalil , de la Garza Fernando Rodriguez , Pino Antonio Enrique , Salinas Jose Luis , Puerto Maura C. , Hirasaki George J. , Miller Clarence A. 
Published: September 2016

Abstract
An integrated methodology is presented for development of a comprehensive empirical foam model based on tailored laboratory tests and representative numerical simulations that encompass processes of foam generation, coalescence, shear thinning along with rheological characteristics and flow regimes. Multitude of steady state and unsteady state laboratory experiments of foam floods in a vertical column of sandpack with and without oil at different surfactant concentrations and at varied gas-surfactant solution injection rates are designed, conducted and analyzed. The logic and basis for the conduct of each of these experiments are provided. Test results from experiments in the presence of oil provide information on the oil-induced foam-lamella coalescence functions. Unsteady state experiments are conducted to characterize foam generation and foam dry-out phenomena, while steady state experiments capture the effects of foam quality, foam velocity and surfactant concentration. Process-based numerical simulations of these experimental results are combined with analytical solutions of foam flow equations to provide a methodology for comprehensive foam model. Simulations of unsteady state foam flow experiments with and without oil saturation quantify the foam generation and coalescence function parameters. A procedure is presented to fully model the effect of surfactant concentration on foam strength and quantify all concentration function parameters, and in particular, epsurf. The combination of sound mathematical principles of governing foam flow equations and numerical simulation techniques is shown to be the key for uniquely defining the empirical foam model parameters and for preserving consistency with simulations of foam flow processes.
An Innovative Approach to Model Two-Phase Flowback of Shale Gas Wells with Complex Fracture Networks
Authors: Yang Ruiyue , Huang Zhongwei , Li Gensheng , Yu Wei , Sepehrnoori Kamy , Tian Shouceng , Song Xianzhi , Sheng Mao 
Published: September 2016

Abstract
Two-phase flow has generally been of more concern in the hydraulic treatment design of shale gas reservoir, especially, during the flowback period. Investigating the gas and water production data is important to evaluate the stimulation effectiveness. We develop a semianalytical model for multi-fractured horizontal wells by incorporating the two-phase flow in both matrix and fracture of the shale-gas wells. We employ the node-analysis approach to discretize the complex fracture networks into a given number of fracture segments, depending on the complexity of fracture system. The two-phase flow is incorporated by iteratively correcting the relative permeability to gas and water phase and capillary pressure for each fracture segment with the fracture depletion. The model is validated by numerical model and field observation. A good match between them was obtained. Then, the early-time gas and water production performance is analyzed using various fracture properties and geometries. A systematic type curves are obtained with the fracture system from simple to complex geometries. The flow regimes that were identified could assist in constraining the fracture geometry and complexity. Additionally, the gas and water decline rates highly depend on the fracture properties such as initial gas saturation in fractures, fracture conductivity, fracture spacing, fracture geometry and connections with natural fracture networks. The improved network fracture conductivity and complexity especially the connections between hydraulic fracture and natural fractures can enhance the gas production and shorten the dewatering time, illustrating that the effective stimulation could facilitate the fractures to clean up more quickly. The gas/water supply from natural fractures and their flow dynamics controlled by two-phase relative permeability effects could be the major reasons for the formation of "V-shape" behavior on the plot of gas/ water ratio vs. cumulative gas production. This work, for the first time, extends the semianalytical model from single-phase flow to two-phase flow in shale gas reservoir with complex fracture networks. The method is simple and gridless, but is capable of capturing the complex fracture system and gas/water transport mechanisms. Also, it provides an efficient technique to evaluate the hydraulic fracture treatment design in multi-fractured horizontal wells for shale gas reservoirs at early production times.
Turning Data into Knowledge: Data-Driven Surveillance and Optimization in Mature Fields
Authors: Temizel Cenk , Aktas Sinem , Kirmaci Harnn , Susuz Onur , Zhu Ying , Balaji Karthik , Ranjith Rahul , Tahir Sofiane , Aminzadeh Fred , Yegin Cengiz 
Published: September 2016

Abstract
Decision making in the oilfield is a crucial process in petroleum oilfield activities where numerous attributes and uncertainties exist in the complete process. In the development process of new fields, a well-organized historical database to minimize uncertainty is important as it decreases risks, provides better insight and robustness in decision making.
Statistics is a strong tool to turn information or data into knowledge when used with care and physical understanding of the cause-effect relation between the attributes and the outcome. Unfortunately, historical data and learnings from the past cannot be used in an efficient way in oilfield decisions due to lack of systematically organized historical data where there is a huge potential of turning terrabytes of data into knowledge and understanding, for more successful decisions and results. On the other hand, using historical data on reservoir enginnering studies are generally very complex since it requires integration of vast amount data from several diciplines that have different data sources and from different scales, which is sometimes leading modelers to prefer new data collections from the field rather than using complex historical data on hand.
In this sense, a multi-attribute based statistical model for each reservoir will greatly enhance the outcomes of future actions through bringing a statistical understanding to a physically more complex relation between the causes and effects or in other words, attributes and results. The data driven models are established for the desired phenomena by means of collecting relevant historical data, after which a multivariate regression is carried out to show the significance of each attribute in the model. These statistical models are then used to make future decisions in the same reservoir in such a way that attributes can be selected within the optimum ranges that yield best results and outcome. Attributes can consist of events and key parameters that influence the outcome.
The model is illustrated to investigate the factor affecting the performance of vertical and horizontal wells in tight reservoirs. The data-driven model is validated with the numerical reservoir simulation model and used to determine the significance of each parameter and the optimum operating intervals.
Injection Induced Fracture Propagation and Stress Reorientation in Waterflooded Reservoirs
Authors: Bhardwaj Prateek , Hwang Jongsoo , Manchanda Ripudaman , Sharma Mukul M. 
Published: September 2016

Abstract
It is now well established that poro-thermo-elastic effects substantially change the magnitude and orientation of in-situ stresses. Fractures induced in injectors during water injection for waterflooding or produced water disposal have a profound impact on waterflooding performance. These effects, coupled with injectivity decline due to plugging caused by injected particles, lead to permeability reduction, fracture initiation and propagation. Models are available for fracture propagation in single injection wells and single layered reservoirs that account for these effects. However, the impact of fluid injection and production on fracture growth in multiple wells and multi-layered reservoirs with competing fractures has not been systematically modelled at a field scale.
In this work, a three-dimensional, two-phase flow simulator with iteratively coupled geomechanics has been developed and applied to model the dynamic growth of injection-induced fractures. The model is based on a finite volume implementation of the cohesive zone model for arbitrary fracture propagation coupled with two-phase flow. A dynamic filtration model for permeability reduction is employed on the fracture faces to incorporate effects of internal damage and external filter cake build-up due to the injection of suspended solids and oil droplets. All physical phenomena are solved in a single framework designed for multi-well, field-scale simulation.
The pressure distribution, saturation profile, thermal front, mechanical displacements and reservoir stresses are computed as fluids are injected and produced from the reservoir. Simulation results are discussed with single as well as multiple fractures propagating. Stress reorientation due to poroelastic, thermoelastic and mechanical effects is examined for the simulated cases. The orientation of the fractures is controlled primarily by the orientation of the stresses, which in turn depends on the pattern of wells and the rates of injection and production. The sweep efficiency of the waterflood is found to be impacted by the rate of growth of injection-induced fractures. Heterogeneities in multi-layered reservoirs strongly govern the expected vertical sweep and fluid distribution, which impacts the cumulative oil recovery.
This is the first time a formulation of multiphase flow in the reservoir has been coupled with dynamic fracture propagation in multiple wells induced by solids plugging while including poro-thermo-elasticity at the reservoir scale. The model developed in this work can be used to simulate multiple water injection induced fractures, determine the reoriented stress state to optimize the location of infill wells and adjust injection well patterns to maximize reservoir sweep.
Integrated Analysis of Reservoir Architecture and Time-Lapse Seismic for Remaining Oil Prediction: A Lithologic Reservoir in Pearl River Mouth Basin, China
Authors: Yu Lin , Yun Ling , Jianming Guo , Xiaomin Zhang , Feng Zhang , Yaonan Li 
Published: September 2016

Abstract
Lithologic reservoirs are characterized by subtle locations and complex architectures. Conventional structure and deposition interpretations based on seismic and logging data are beneficial to the distribution forecast of lithologic reservoirs. But they are not enough to predict remaining oil in the late development stage. A new fine remaining oil prediction method of lithologic reservoir based on the integration analysis of reservoir architecture and time-lapse (4D) seismic is proposed and applied successfully to Reservoir H11.
H11 is a complex delta lithologic reservoir in the Pearly River Mouth Basin. By the end of 2014, its water cut has been up to 98.5%, but EOR is only 35.1%. It is urgency to study remaining oil distribution. There are three key techniques involved, including the dynamic interpretation of reservoir depositional evolutions, fine characterization of sand body architectures & flow barrier distributions and the analysis of 4D seismic difference.
Firstly, constrained by sequence frameworks, stratal slices between the top and base of H11 are extracted at 1ms interval and calibrated with logging. These slices are relatively isochronous and contain the depositional information. According to seismic sedimentology theory, integral interpretations of slices and log facies are used to study spatial evolutions and distributions of H11. Secondly, based on investigations of delta front deposits cropping out in the Ordos Basin, sand body contacts are understood. These contacts are further analogized by core, logging, 3D seismic and acoustic impendence data in subsurface. Whether the contact boundaries are seepage flow barriers is further distinguished through the analysis of development performances or pre-stack inversion data. Finally, remaining oil of H11 was successfully delineated by 4D seismic analysis. The 4D difference data shows significant water movement from the north and west. The presence of bypassed pay at the southern and eastern scattered areas is obvious. Based on these understandings, a proposed well is completed at the southern prediction area in the late 2014 and the result is consistent with the 4D response. Currently, the oil production of this well is up to 2800 barrels per day.
Besides the imperfect well pattern, the complex contacts and lithologic flow barriers among sand bodies are the other reasons leading to the subtle 4D seismic difference. The static reservoir architecture analysis and 4D seismic difference analysis are integrated to improve the precision of remaining oil prediction of H11. This method has been popularized to other lithologic reservoirs of the Pearl River Mouth Basin, and enriches the approach and technique of remaining oil delineation.
First-Time Application of Catenary Concentric Coiled Tubing and Vacuuming Technology
Authors: Choo Der Jiun , Kothari Nikita , Larke James 
Published: September 2016

Abstract
An operator needed to perform wellbore intervention on four low-bottomhole-pressure offshore wells in Malaysia. High sand production was consistent in all the wells, precluding access to the producing zones in the lower completion. The wells had been shut in since 2011, and previous cleanouts using conventional coiled tubing (CT) and nitrogen had been unsuccessful.
The job had to be performed from a work barge in a catenary style, meaning that the injector head, blowout preventers, and power pack were on the platform, but all were operated from a barge. The advanced wireless catenary unit made it possible to complete the operation with only the CT and three flexible lines connecting the barge and the vessel. Due to the nature of the concentric coiled tubing (CCT)—designed to flow returns back to surface—all returns had to be routed away from the platform and onto the barge.
After an analysis and planning session, the operator and the service provider decided to use a CCT cleanout system with a switchable jet-pump designed to remove solids and liquids from ultralow pressure wellbores that are not treatable with standard circulating methods. The operational plan also called for building a specialized CT connector that would enable conventional operations, such as fishing and sleeve manipulation with CCT.
This was the first time that vacuuming technology and catenary CCT were used together to perform a cleanout operation. The results were impressive as extensive amount of sand was removed from the wellbores to surpass target production by 185%. This paper will focus on a campaign in the South Furious field of Sabah, Malaysia in which both the logistic and operational challenges were successfully overcome with 112 days of incident free operations.
Unlocking the Potential of Marginal Reservoirs in Kuwait Through the Application of Optimized Hydraulic Fracturing Technologies
Authors: Al-Othman M. R. , Buhamad A. A. , Al-Houti N. B. , Ashkanani M. S. , Al-Mehanna H. S. , Al-Haddad M. N. , Al-Dhafiri A. A. , Al-Harbi S. M. , Al-Ibrahim A. A. , Al-Zuwayed A. M. , Ahmed A. M. , Al-Dousari M. A. 
Published: September 2016

Abstract
In Kuwait, drilling and deployment plans focus mainly on drilling vertical wells through a wide range of reservoirs consisting of high- and low-permeability sandstones and carbonates, with varying crude types from medium-heavy to condensate. Since 1935, Kuwait has produced mainly from the types of reservoirs that keep its daily production as high as possible to accommodate the country's economic needs. With the aging of these mature reservoirs, reservoir pressure reduction and water production become a major challenge, in addition to the limited access to drilling resources. Accordingly, exploring different reservoirs and unlocking the potential of the existing low- to mid-permeability reservoirs through advanced fracturing technologies are considered the alternative plan to compensate for production decreases and to improve oil production. However, implementing such technologies requires a customized design and candidate selection process.
The plan involved a multidisciplinary well candidate screening and selection criteria for different reservoirs and fields. The criteria include different parameters such as bubblepoint pressure, minimum formation thickness, and rock mineralogy, in addition to the study of the previously applied production enhancement technologies. About 50 wells have been selected from different reservoirs and fields across Kuwait for the initial pilot plan to evaluate the potential of a wide range of reservoirs. Then, a customized fracturing technology design followed that included operational planning, execution, and evaluation.
Approximately 20 fracturing treatments were executed successfully, and the post-job evaluation showed two- to four fold gains in production. This changed the development strategy and allowed for further development plans for these reservoirs. These newer plans included the application of technologies such as channel fracturing for proppant fracturing and fiber-laden self-diverting acid system for acid treatments.
The well candidate selection criteria and customized design of channel fracturing technology for the sandstone reservoirs and fiber-laden self-diverting acid system technology for fractured carbonate reservoirs resulted in a total additional gain of approximately 15,000 B/D. The detailed engineering design from candidate selection to treatment and the application of optimized hydraulic fracturing technologies enabled production enhancement and additional recoverable reserves from the most challenging low-permeability and low-API gravity candidates for the first time in Kuwait where conventional stimulation techniques were not providing the expected results.
New Algorithm to Quantify Productivity of Fishbone Type Multilateral Gas Well
Authors: Ahmed Musa Eltayeb , Alnuaim Sami , Abdulazeem A. 
Published: September 2016

Abstract
Due to the increase of global gas demand and the evolution of tight and shale gas development, thousands of multilateral gas wells have been drilled in the last decades. A multilateral well is defined, in general as a well with multiple branches in the lower borehole targeting oil and gas reserves in the same or different strata. These branches are called laterals. Multilateral wells with the laterals drilled out from the main horizontal wellbores at the same elevation are called fishbone wells. Multi branched wells are very effective in many different aspects such as reducing the development cost, improving sweep efficiency and maximizing recovery in oil and gas reservoirs. In this paper, a new empirical algorithm to quantify the productivity of fishbone type multilateral dry gas well is proposed. A reservoir commercial simulator was used to simulate the gas flow through a multilateral dry fishbone type gas well. Different well and reservoir parameters such as number of laterals, permeability ration (kh/kv), length of lateral sand lateral spacing have been changed and their effects on the well Inflow Performance Relationship (IPR) were evaluated and incorporated into the new IPR model. It was found that the IPR curves are strong function of the number of well laterals (n), the permeability variation and lateral length. Statistical software was used to perform nonlinear regression and generate a new empirical IPR correlation of Vogel-form to describe the productivity and well performance of a fishbone type multilateral dry gas well. Finally, detailed model verification was done through a comparison of data generated with the new empirical correlation and data generated from a commercial well performance software using real field data with acceptable match.
Technology Driven Rejuvenation of a Mature Field by Doubling the Gross Production Rate
Authors: Giden I. , Kometer B. , Toth P. , Geier H. , Florian T. , Sieberer M. 
Published: September 2016

Abstract
The 16. Tortonian Horizon is one of the largest producing oil reservoirs in continental Europe. The field has been on production since 1949 and has already gone through a long decline period. The average water cut currently exceeds 96%. The western region of this reservoir, called Bockfliess area, was the focus of the latest field re-development effort, aiming to increase oil production by doubling the liquid rate.
Although the project comprised various activities – including facility upgrades and the construction of additional surface infrastructure –, this paper focuses mainly on subsurface measures. The majority of modifications were conducted on existing production wells. Quick wins included additional perforations and sucker rod pump (SRP) unit changes. The artificial lift systems of more than one third of the producers were converted to electrical submersible pumps (ESPs). Three new high-rate horizontal producers were also drilled. To maintain reservoir pressure, nearly all the produced water had to be re-injected. Several of the existing producers were converted to injectors and two new horizontal injector wells were drilled.
The overall goal of doubling the gross production rate was accomplished by an integrated multidisciplinary team in a short time period. 13 additional perforations, four SRP unit exchanges and 32 conversions of producers to ESPs proved to be successful in increasing oil production.
In order to target the remaining attic oil, three high rate horizontal infill producers were effectively placed within specific zones of the reservoir by applying state of the art geosteering technology. The planned voidage replacement ratio was achieved by converting nine producers to injectors and two successfully placed horizontal high rate injector wells. These measures increased oil production by 62% (43% was gained from existing wells and 19% from new wells).
The concept of doubling the gross rate on a reservoir scale was unprecedented in Austria, especially for a reservoir that was already producing at maximum surface capacity. For single wells, gross rates were increased up to seven-fold as compared to the rates produced before the project. To control such high volumes with an optimized operation, real-time monitoring of the sensor-equipped ESPs was implemented. Horizontal infill drilling had not been implemented before in the targeted reservoir area due to the close well spacing. Real time geosteering methods using advanced logging while drilling (LWD) technology proved to be beneficial in this onshore mature brown field. Different sand control and bottom hole flowing pressure control methods were applied in each of the new horizontal producers, including autonomous inflow control devices (AICD) which are currently mainly utilized in offshore environments.