bluuebunny/crossref_metadata_2025_split huggingface dataset:
Results of Reservoir Modeling of the Operation and Production of a Recompleted Gas Well in a Geopressured/Geothermal Reservoir in the Wilcox Formation, Texas, for Electricity Generation
Authors: Esposito Ariel , Augustine Chad 
Published: June 2014

Abstract
Reservoir modeling of production of hot geothermal fluid and natural gas from a geopressured reservoir in the Wilcox formation, Texas, for geothermal-electricity generation is carried out primarily on the basis of well-log data. The reservoir modeling takes into account operational considerations such as a constant target flow rate, a 30-year reservoir lifetime, and minimum wellhead pressure as well as uncertainty in reservoir parameters such as gas saturation and reservoir volume. The results of the reservoir modeling are presented and their relevance to other similar geopressured/geothermal wells with the potential for natural-gas production is discussed.
Installation of Complex Multilateral Wells With Standalone Sand Screens in the Vincent Field
Authors: Nettleship Gary , Palmer Anthony , Eshtewi Abdullah 
Published: June 2014

Summary
The Vincent project is an offshore oil field developed by subsea multilateral (ML) wells with sand control. This paper provides an insight into how completion practices were developed to maximize well productivity and how they were balanced against risks for constructing ML junctions.
The fluids used for drilling and cleaning up openhole laterals can have a significant impact on well productivity in standalone-screen applications, especially with respect to sand-screen plugging. This paper details the development of openhole fluid selection and cleanup practices for completing long 7,000-ft+ horizontal laterals with standalone screens. The Vincent wells are more complex because of drilling trilateral wells that include two technology-advancement ML (TAML) Level-5 ML junctions requiring openhole connections. The paper identifies the key risks for installing the ML junctions in a weak formation, including risks imposed from cleanup practices.
The paper reviews the lessons learned during execution, how the ML-junction installation risks were mitigated, and how the Vincent wells were delivered with a well-performance meeting expectation.
In Situ Combustion Technology in the Later SAGD Process in Extra Heavy Oil Reservoir
Authors: Desheng M.. , Lanxiang S.. , Changfeng X.. , Xiuluan L.. , Erpeng G.. , Fengxiang Y.. , Xiaorong S.. , Yaoli S.. , Changjun D.. 
Published: June 2014

Abstract
Steam assisted gravity drainage (SAGD) enjoys great advantages in the development of extra heavy oil reservoir such as high oil rate and favarable oil steam ratio. However, there are also disadvantages, such as intensive energy consumption, produced water recycle and disposal, that have impacts on the economics of SAGD projects. Furthermore, oil steam ratio declines and water cut rises when the SAGD comes into its later stage while great residual oil existing in the wedge zone. This paper proposes a new method, turning to in situ combustion (ISC) in the later SAGD, to improve the performance of the later SAGD. The feasibility and performance are both studied systematically. Firstly, a numerical model is established on the basis of reservoir and fluid parameters from a block in Xinjiang oil field, China, and then the performance characteristics in different stages of SAGD in extra heavy oil are studied. Particularly, characteristics of performance, features of temperature, pressure, steam chamber, distribution of residual oil in the later SAGD in extra heavy oil reservoir are deeply characterized. Combining these features and using physical simulation method, the feasibility of ISC in later SAGD in extra heavy oil reservoir has been discussed in terms of the effects of the oxidation kinetics characteristics, the thermal connectivity, the fuel supply, the coke deposit and the combustion front shape of extra heavy oil. Furthermore, the time when or before the steam chamber spreads to the edge of the SAGD well pair pattern is determined to be the optimum time to turn to ISC for the typical reservoir. By adding vertical wells for air injection in the middle of SAGD well pairs is the appropriate well pattern for ISC in the later SAGD. And perforating in the middle and lower interval is demonstrated to be the better method to control injection and production. Four stages in the process of ISC performance are determined and dissected. The study results indicate that stable combustion front shape and high production rate can be achieved after turning to ISC. Another 50.7% of the OOIP can be obtained in the ISC stage, regardless of 30% oil recovery in the SAGD stage.
Improving Reservoir History Matching of EM heated Heavy Oil Reservoirs via Cross-well Seismic Tomography
Authors: Katterbauer Klemens , Hoteit Ibrahim 
Published: June 2014

Abstract
Enhanced recovery methods have become significant in the industry's drive to increase recovery rates from oil and gas reservoirs. For heavy oil reservoirs, the immobility of the oil at reservoir temperatures, caused by its high viscosity, limits the recovery rates and strains the economic viability of these fields. While thermal recovery methods, such as steam injection or THAI, have extensively been applied in the field, their success has so far been limited due to prohibitive heat losses and the difficulty in controlling the combustion process. Electromagnetic (EM) heating via high-frequency EM radiation has attracted attention due to its wide applicability in different environments, its efficiency, and the improved controllability of the heating process. While becoming a promising technology for heavy oil recovery, its effect on overall reservoir production and fluid displacements are poorly understood. Reservoir history matching has become a vital tool for the oil & gas industry to increase recovery rates. Limited research has been undertaken so far to capture the nonlinear reservoir dynamics and significantly varying flow rates for thermally heated heavy oil reservoir that may notably change production rates and render conventional history matching frameworks more challenging. We present a new history matching framework for EM heated heavy oil reservoirs incorporating cross-well seismic imaging. Interfacing an EM heating solver to a reservoir simulator via Andrade's equation, we couple the system to an ensemble Kalman filter based history matching framework incorporating a cross-well seismic survey module. With increasing power levels and heating applied to the heavy oil reservoirs, reservoir dynamics change considerably and may lead to widely differing production forecasts and increased uncertainty. We have shown that the incorporation of seismic observations into the EnKF framework can significantly enhance reservoir simulations, decrease forecasting uncertainties and cope with the growing nonlinearity caused by the heating process for efficient and accurate reservoir forecasting.
Optimizing Field Development of Greenfield Polymer Floods using Experimental Design
Authors: Shook G. Michael , Walker D. L. , Jackson A. C. , Ruby N. H. , Poulsen A. 
Published: June 2014

Abstract
Waterflooding viscous oil suffers from poor displacement efficiency, requiring excessive volumes throughput for a given recovery. Heterogeneity reduces recovery further by reducing volumetric sweep efficiency. These can be mitigated by modifying injection viscosity with polymer. An improved mobility ratio reduces the throughput to achieve a given recovery, increases volumetric sweep efficiency, and reduces water production and associated handling costs. These three factors make polymer flooding an attractive alternative to waterflooding.
From a volumetric sweep perspective, there is no practical limit to the benefit of increased injection viscosity. However, increased fluid viscosity decreases injectivity, through damage (residual resistance factor) or increased resistance to flow with injection of a more viscous fluid. Injectivity issues can be overcome by decreasing well spacing, but at a capital cost. This introduces a de facto limit on polymer concentration; by reducing the concentration we can increase injectivity and increase well spacing, but at the expense of reduced macroscopic displacement efficiency and increased throughput. There are two decision variables (polymer concentration and well spacing) that have three consequences (injectivity, processing rate, and total volume throughput).
We have designed a workflow that maximizes NPV for given reservoir and flood properties by optimizing well spacing and polymer concentration. For given polymer concentration and spacing we analytically solve for injection rate vs. time and use that in fractional flow calculations to determine oil production vs. time. The workflow is automated, so a wide range of decision variables can be easily explored via Experimental Design. Surface response methods are then used to determine well spacing and polymer concentration that maximize net present value.
The methods developed for the optimization are presented, and the workflow steps are outlined. The method was applied to a field study; for the reservoir properties and under tertiary polymer flooding, the optimized set of conditions was 1900 ppm polymer and an injector-producer spacing of 700 ft. Injecting polymer prior to any water injection reduces the spacing to 380 feet and increases the polymer concentration to 2250 ppm, in large part because the low oil bank mobility dominates injectivity decline. This suggests an important design consideration of pre-conditioning the reservoir prior to instigating a polymer flood.
Integration of 4D Seismic Data for Well Optimization in SAGD
Authors: Masih Shahbaz , Rodriguez Maximo , Williams Andrew 
Published: June 2014

Abstract
The depositional environment at Statoil's Leismer SAGD demonstration project is dominated by a fluvial-deltaic system with complex geological features which present challenges for SAGD operations. An efficient monitoring tool that could combine geoscience data with production knowledge is vital for optimizing SAGD operational strategies. Time lapse (4D) seismic survey is one such monitoring tool. It can be integrated with wells and production data to prepare and optimize operational strategies. The pattern of growth of steam chamber is critical for well performance optimization. Steam chamber development dictates which reservoir areas are using heat efficiently and contributing to drainage of bitumen and increased production.
At Leismer, two 4D monitor seismic surveys have been conducted since the start of operations. The 1st monitor was acquired in 2012 to observe one year of SAGD performance and the 2nd monitor in 2013 to observe the performance after 2 years of operation. These surveys have been used to identify challenges to maximizing well pair productivity. Of primary concern is the effective distribution of steam along the entire horizontal section of the SAGD well pair. Other 4D monitoring benefits include, monitoring subcools with respect to reservoir heterogeneities, bottom water communication, steam chamber coalescence, baffle or barrier to steam chamber growth identification.
In this study, examples are presented to show how combining production and 4D seismic data has contributed to well pair optimization. Communication with bottom water in the early stages of SAGD, while rare, occurred in specific Leismer well pairs – analyses of production data combined with 4D seismic data helped identify steam loss into bottom water which drove steam injection strategy and improved well productivity. Another Leismer example shows how 4D seismic has been used to confirm a low reservoir roof at the toe of a particular well pair. This knowledge drove a change in injector well completion to optimize production. In the final example, it is shown how 4D seismic has helped analyze and confirm well conformance (heat distribution along SAGD well pairs) which is critical for uniform steam chamber development.
Based on Statoil's Leismer experience of applying results of 4D seismic analyses for well optimization, it can be concluded that 4D seismic has proven to be a very useful and value adding monitoring tool.
Updated Screening Criteria for Steam Flooding Based on Oil Field Projects Data
Authors: Hama M. Q. , Wei M.. , Saleh L. D. , Bai B.. 
Published: June 2014

Abstract
Enhanced oil recovery (EOR) screening is considered the first step in evaluating potential EOR techniques for candidate reservoirs. Therefore, as new technologies are developed, it is important to update the screening criteria. Many of the screening criteria for steam flooding that have been described in the literature were based on data collected from EOR surveys biennially published in the Oil & Gas Journal. However, these datasets contain some problems, including outliers, missing data, inconsistent data and duplicate data, that could affect the accuracy of the results. Despite the importance of ensuring the quality of a dataset before running analyses, data quality has not been addressed in previous research related to EOR screening criteria. The objective of this current work was to update the screening criteria for steam flooding by using a database that had been cleaned. The original dataset included 1, 785 steam flooding field projects from around the world (Brazil, Canada, China, Colombia, Congo, France, Germany, Indonesia, Trinidad, U.S. and Venezuela). These projects had been reported in the Oil and Gas Journal from 1980 to 2012. After detecting and deleting the duplicate projects, only 626 field projects remained. To analyze and describe the results of the dataset, both graphical and statistical methods were used. A box plot and cross plots were used to detect and identify data problems, allowing for the removal of outliers and inconsistent data. Histogram distributions and box plots were used to show the distribution of each parameter and present the range of the dataset. New screening criteria were developed based on these statistics and the defined data parameters. The developed criteria were com-pared with previously published criteria, and their differences are explained in this paper.
Alteration of matrix wettability during alternate injection of hot-water/solvent into heavy-oil containing fractured reservoirs
Authors: Mohammed M. Almojtaba , Babadagli Tayfun 
Published: June 2014

Abstract
An alternate injection of solvent and hot water/steam called Steam-Over-Solvent injection in Facture Reservoirs (SOS-FR) has been recently suggested and tested by our research group. In this process, most oil is produced during the solvent phase and then hot water/steam phase is assigned, mainly to retrieve the solvent. Oil recovery during this phase is typically low due to limited thermal expansion in the case of oil-wet matrix, and because capillary imbibition and gravity drainage driven by viscosity reduction do not have a significant contribution to the recovery. Wettability alteration toward more water-wet state will, however, enhance these mechanisms.
Based on these facts, different wettability alteration agents were tested including cationic and anionic surfactants, ionic liquids, nano-fluids, high pH solutions, and low salinity water. The potential of these materials to modify the wettability of aged sandstone and limestone samples was evaluated using imbibition tests.
Berea sandstone (aged to be oil-wet) and Indiana limestone samples were saturated with heavy oil (3, 600 cp). After the wettability modification was confirmed using different tests, the SOS-FR method was applied. The process was initiated by soaking cores into solvent (heptane or diluent oil) and the oil recovery was estimated using refractive index measurements. Then, two different experimental schemes were followed. In this first scheme, different brines were used and the oil production readings were taken periodically. These experiments will yield additional oil recovery (and solvent retrieval) by capillary imbibition and enhance gravity drainage if the wettability alteration due to solvent effect in the previous phase and chemical injected in the subsequent phase was achieved. In the second scheme, the heptane was retrieved first by hot-water exposure and the capillary imbibition tests were performed to test the selected chemical additive solutions as the wettability alteration agents.
After conducting a total of 28 experiments, the most promising wettability alteration agents were marked and optimal application conditions (i.e., temperatures, injection sequence) were identified.
Induction and Radio Frequency Heating Strategies for Steam-Assisted Gravity Drainage Start-Up Phase
Authors: Ghannadi Sahar , Irani Mazda , Chalaturnyk Rick 
Published: June 2014

Abstract
Steam-assisted gravity drainage (SAGD) is the method of choice to extract bitumen from Athabasca oil sand reservoirs in Western Canada. Bitumen at reservoir condition is immobile due to high viscosity and its saturation is typically large that limits the injectivity of a steam at in-situ condition. In a current industry practice, steam is circulated within injection and production wells. Operators keep the steam circulation till mobile bitumen breaks through the producer and communication is established between the injector and the producer. The "start-up" (or "circulation") phase is ranging between three to several months. A variety of processes are used to minimize time of start-up phase such as: electro-magnetic (EM) heating either induction (medium frequency) or radio frequency (RF) ranges. Knowing the hot-zone size formed by steam circulation and benefit of simultaneous EM-heating techniques help better understand the start-up process and how to minimize the start-up duration. The aim of the present work is to introduce an analytical model to predict start-up duration for only steam circulation and also for with EM-heating. The results obtained from this study reveal that induction slightly decrease start-up time for frequencies smaller than 10 kHz, and it can reduce start-up time to 30% of original steam circulation for 100 kHz frequency.
An Innovative Modeling Approach to Unveil Flow Control Devices' Potential in SAGD Application
Authors: Riel A. , Burton R. C. , Vachon G. P. , Wheeler T. J. , Heidari M. 
Published: June 2014

Abstract
Sand screens with flow control devices (FCDs) have demonstrated significant potential in improving recovery in a Steam Assisted Gravity Drainage (SAGD) well pair. The premium wire-mesh sand control screens would have the capability to prevent sand flow into the liner in the event of a steam break-through. In addition the FCDs would improve steam conformance along the wellbore in the early time, and allow the producers to achieve higher production and lower Steam to Oil Ratios as well as restricting steam production if and when breakthrough at the producer occurred.
To better understand FCD behavior in SAGD operations, modeling of the different FCD designs has been attempted and has shown that steam breakthrough can be more effectively controlled utilizing devices that promote water flashing as fluids pass through them. With tools providing this type of control, steam breakthroughs in the producer can be more effectively restricted resulting in a better-produced fluid distribution along the wellbore. This also allows the producers to be operated with lower subcool margins without fear of sand production and the potential liner damage.
In order to validate the theory of improved performance and better thermal efficiency, a wellbore model coupled to a thermal reservoir simulator has been enhanced to more accurately model the impact of flow control devices on the reservoir/well performance. A collaborative effort has been initiated with the Computer Modeling Group (CMG) to develop a reservoir simulated FCD solution that will allow the user to enter characteristic performance curves for a variety of FCDs.
The development of the new keyword associated with ConocoPhillips FCD's mechanistic modeling has shown to be an improvement to the way that FCDs are currently modeled helping to unveil their potential for in SAGD and thermal recovery applications. Results from FCD pressure loss predictions and modeling of FCDs in the reservoir are provided to demonstrate the benefits of FCD use in SAGD operations.
A Novel High-temperature Gel to Control the Steam Channeling in Heavy Oil Reservoir
Authors: Wang Changjiu , Liu Huiqing , Wang Jing , Hong Cheng , Dong Xiaohu , Meng Qingbang , Liu Yongge 
Published: June 2014

Abstract
Controlling the steam channeling is a major challenge for increasing production in heavy oil reservoirs developed by steam injection. The conventional gel used in water flooding reservoirs always has poor heat resistance, so this paper proposed a novel high-temperature gel (HTG) blocking agent on the basis of a laboratory experimental study. The HTG consists of nonionic filler and unsaturated amide monomer with graft polymerization and crosslinking. The optimal gel system has a high gelling strength and controllable gelation time, which is achieved through incomplete orthogonal design method. Then the stability and plugging performance are studied through singular and parallel sand-pack experiments.
The results indicate that the HTG has strong salt resistance and dilution resistance. In addition, the HTG can still maintain high strength at 200°C for 72hr. The singular sand-pack experiments suggest that the HTG has good injectability that ensures the on-site construction safety. Moreover, the HTG has a high breakthrough pressure gradient after gelling and could keep the plugging ratio above 99.8% after gel breakthrough when the subsequent injected volume reaches 10PV. The results obtained in parallel sand-pack experiments show that the HTG can effectively plugging the steam channeling after injecting into the high permeability sand-pack from the production end, and force the subsequent steam to enter the low permeability sand-pack. That raises the producing degree of the low permeability sand-pack. Finally, the difference between high and low permeability sand-pack liquid production is reduced by 99.098%, indicating that the producing profile is tremendously improved, and the oil recovery is enhanced by 41.34%. As a result, the novel HTG blocking agent can be used to control the steam channeling in heavy oil reservoir.