bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Workflow for Fully Consistent Water Saturation Initialization without Capillary Pressure Scaling
Authors: Ghorayeb Kassem , Darous Christophe , Acharya Mihira N. , El-Anzi Ealian 
Published: December 2011

Abstract
Discrepancies in terms of hydrocarbon initially in place volumes (HIIP) between static and dynamic models might take place because of nonlinear dependency of the saturation height function (SHF) versus porosity and averaging of height above free water level. Upscaling tends to eliminate the high and low porosity values in favor of the average porosity, which might lead to substantial changes in the resulting water saturation. Furthermore, pressure and compositional variation with depth in the dynamic model might lead to substantial contribution to the discrepancies, independent of upscaling.
We present a procedure to address the above issues and provide full consistency between static and dynamic models in terms of HIIP, without the use of capillary pressure (Pc) scaling by the reservoir simulator. A "preprocessing" workflow is used to slightly reassign the Pc curve of each grid block so that a very close match is obtained between the two models in terms of HIIP.
Results show that HIIP obtained from the dynamic model through equilibration using the proposed procedure are within 1% of those obtained using the static model without having to use Pc scaling in the reservoir simulator which warranties realistic and physically valid Pc curves in the reservoir dynamic model initialization process.
Integration of Fiber Optic Enabled Coiled Tubing System with Multiphase Production Logging Tool for Remedial Work Candidate Evaluation
Authors: Al-Buali Muhammad H. , Shawly Alaa S. , Dashash Alaa A. , Stuker John , Burov Anton 
Published: December 2011

Abstract
Multiphase production logging is essential to identify the contribution of different zones, types of fluids produced and other production related issues in producing wells. Data collected is used to determine if the well requires other services to enhance production or isolate unwanted zones.
Locating water production and cross flow between thief zones are common problems for carbonate formations. Remedial well services require costly multiple mobilizations of wireline, coiled tubing (CT) and stimulation units. Results might not be accurate due to the time gap between identifying the problem and implementing the action.
The new fiber optic enabled coiled tubing (FOECT) system supports many well intervention services, such as production logging, water shut-offs and/or acid stimulations with a single CT string. Combining FOECT with a real-time multiphase production logging tool (MPLT) reduces well downtime and improves remedial service quality control. Downtime is reduced by using the same surface equipment of FOECT to perform multiphase logging and also remedial work. Only the required bottom-hole assembly (BHA) needs to be changed. This successful logging job for Saudi Aramco allows evaluating remedial well services to be planned right after the production logging job to maximize quality control.
This paper documents the implementation of the FOECT system with real-time MPLTs and demonstrates the following improvements for the Ghawar field: First time in a Saudi FOECT system and MPLTs were used to log a wet oil producer well for immediate evaluation of remedial work needed.Significant reduction of well downtime by eliminating multiple mobilizations of wireline, CT and pumping units.Established best practices for production logging with FOECT and multiphase tools, including equipment rig up and single acquisition system setup.Optimize the required equipment by eliminating the electric line (e-line) logging unit.
Passive Inflow Control Devices versus Multiple Fracturing in Horizontal Wells: Selection Criteria for Optimized Completions in Oil Reservoirs
Authors: Uelker E. B. , Galimzyanov A. , Ostrowski L. , Gordeev Y. , Mirochnichenko A. 
Published: December 2011

Abstract
The industry has faced rapid advances in openhole completions in recent years, mainly in horizontal wells. Among these innovations, multistage fracturing and inflow control devices (ICDs) have gained notoriety as popular methods for field development, especially in unconventional reservoirs.
Fracturing a horizontal well may be considered when formation permeability is low and laminated shales are present. Compartmentalization or anisotropies are also a reason for this type of completion. In the same manner, ICDs can be de-ployed in a heterogeneous reservoir to mitigate the potential for early water and/or gas breakthrough.
To compare the features and benefits of both completion methods, the water breakthrough time was investigated in a full-field simulation model. Initially, a near-wellbore simulator was used to evaluate the applicability of the hydraulic multifrac and ICD completion. Then, a full-field simulation model was used to quantify the benefits of these completion techniques, where flow performance and completion optimization were accounted for. A degree of increase of recovery factor due to optimized completion was investigated.
The multistage frac was modelled with explicit gridding techniques. These used local grid refinement and a single porosity approach around the well and induced fractures. ICDs were modelled with a multisegment well model, which analyzed the lateral well branches, fluid phase changes and pressure variations.
This paper provides an example of the unconventional reservoir development for both a multistage frac option and an ICD completion. The optimization designs were aimed to achieve the optimum well completion strategy to fit specific reservoir conditions and an increasing recovery factor. The work was based on a real field case from Russia. The simulation runs were carried out using a commercial black oil simulator. Evaluation and selection criteria of these optimized completions are discussed in this paper.
Fine Numerical Simulation of Alkaline-Surfactant-Polymer Flooding Considering Emulsion and alkaline scale Mechanism
Authors: Lei Zhengdong , Song Jie , Zhu Bin 
Published: December 2011

Abstract
The mobilization of ASP emulsions and the existing of alkaline scale played important effect on fluid flow characteristics through porous media, which exert import effect on the simulation and prediction of ASP flooding process.
The previous studies were carried out to observe alkaline dissolution and precipitation reaction, emulsion rheology, emulsion drop capture, and stable emulsion flowing through capillary tube. However, few studies had been carried out to quantitatively describe emulsion and alkaline scale effect on enhanced oil recovery. This paper aims to improve simulation accuracy by description of physical chemical reaction processes, and enhance simulation speed and stability by improved solution.
The prediction model of permeability and porosity alternation caused by alkaline scale was established, and emulsion flow mechanisms in porous media including emulsifying startup, emulsifying entrainment, emulsion rheology and emulsion droplets capture was mathematically described. On this basis, an improved ASP flooding numerical simulation model incorporating emulsification and alkaline scale was established. In order to better solve the above model, IMPLICIT difference scheme and improved Parallel computing method IBiCRSTAB was proposed. The simulator was validated by comparing the simulation results with the results from linear core floods performed in the laboratory.
The ASP flooding process was simulated on geological model of DaQing Oilfield. The simulation result shows that emulsification role is favor of further improvement of displacement efficiency on middle-high permeability layer, moreover, it could enhance sweep efficiency of low-middle layer. Alkaline scale could decrease inject capability of injection wells and produce capability of oil wells, and bring higher formation damage for low-permeability layer. The proposed IMPLICIT method is more stable and efficient than the traditional methods of IMPES, and the IBiCRSTAB method could significantly improve efficiency 66% for large-scale simulations.
EOS Modelling for Two Oils with High Concentration of Organic Sulphur - Case Study
Authors: Dias Ana , Alves Fernando 
Published: December 2011

Abstract
A reliable fluid characterization achieved through the use of an Equation of State (EOS) is vital to reproduce the phase behaviour of a reservoir fluid and consequently, to improve understanding of the reservoirs EOR potential.
In this case, an EOS model was developed aimed at accurately reproducing the phase behaviour of two reservoir oils in the same field that contain, besides H2S, substantial amounts of organic sulphur components. The tuning of the EOS for both oils was more difficult to achieve than in cases without such level of sulphur components.
The tuning of the Peng-Robinson EOS was achieved with 9 pseudo-components for both oils, following the selection of the lumping scheme considered adequate for reservoir simulation studies. Organic sulphur components are concentrated in the higher range of molecular weights and, consequently, were incorporated into the heavy fraction. The tuned EOS was then used on a 1 D reservoir simulation compositional model to match the available slim tube experiments, to verify the validity of the EOS tuning. Using the compositional simulation of slim tube displacements, minimum miscibility pressure (MMP) was estimated for both oils and different injection gases.
Although a 9 component scheme is adequate for reservoir performance purposes, engineering of surface facilities requires more detail. Therefore, a delumping methodology was developed to allow engineers to estimate detailed fluid composition from the lumped components obtained from reservoir simulation studies. One of the objectives of this study is to obtain a table of variation of the detailed components distributions that can be used for delumping purposes at different stages of the gas injection project.
Using Microseismic Monitoring as a Real Time Completions Diagnostic Tool in Unconventional Reservoirs: Field Case Studies
Authors: Ajayi Babatunde , Walker Kirby , Sink John , Wutherich Kevin , Downie Robert 
Published: December 2011

Abstract
Horizontal wells drilled in unconventional gas reservoirs are often completed by combining multiple perforation clusters in a hydraulic fracture treatment stage. Each treatment stage is typically prevented from communicating by using an isolation plug. It is a challenge to design a limited entry completion that comprehensively ensures that all perforation clusters are equally stimulated within a treatment stage (Miller et al, 2011, Mcdaniel et al, 1999). Slippage or failure of isolation plugs have also been known to occur during treatment execution and in many cases, these failures are discovered only after the well stimulation has been completed. This paper presents three case studies in the Marcellus Shale where real-time microseismic Hydraulic Fracture Monitoring (HFM) was used to evaluate the behavior and development of the induced fracture and a need for the corrective intervention was observed. In one of the cases, an innovative corrective action was implemented and microseismic results show that the intervention was successful.
This study shows how real-time microseismic monitoring can been used for not only evaluating fracture geometry and azimuth but can also be used as a diagnostic tool for observing operational failures in completion tools as well as making real-time changes to completion design in order to improve completion efficiency. Some of the potential failures that may be diagnosed using HFM analyzed in this study include loss of isolation between hydraulic fracture stages, breach in casing integrity, poor cement bond in annulus and confirmation of plug ball seating.
The first case study describes a hydraulic fracture treatment where the real-time HFM interpretation was useful in identifying a failure in the isolation plug between completion stages. This observation during the treatment execution was later confirmed by tagging the depth of the plug during coiled tubing operations. A production log was also run in the well and showed limited production contribution from the stage with the plug failure. The other two case studies address the use of real-time HFM interpretation to identify undesired fracture growth into an already stimulated region. Subsequent intervention by using an isolation plug between perforation clusters as a means of diversion was implemented in one of the cases.
These examples clearly show how real-time microseismic monitoring can be used to adapt conventional completion designs to the dynamic nature of completion operations in the field. The paper also highlights the innovative use of an isolation plug as a diversion mechanism during fracture treatment.
Modeling and Simulation of Gas and Liquid Flow in Tight Gas Sand
Authors: Khlaifat Abdelaziz , Qutob Hani , Arastoopour Hamid 
Published: December 2011

Abstract
Gas production from tight gas sands is vital for developing secure unconventional sources of energy. The porous media considered in this paper belong to tight gas reservoirs characterized by extremely low permeability (range of microdarcies) and low porosity (less than 7%) matrix. The transient, three dimensional, two-phase numerical model is presented for simulating the simultaneous gas and water flow through tight gas sand. The solved continuity and momentum equations treat both fluids as incompressible and immiscible. Darcy's and nondarcy's laws were incorporated into the equations to couple them by a fluid transfer term which depends on the potential difference between different specified physical domains. Also, the model accounted for the effect of capillary pressure and relative permeability. The numerical solution was obtained using the modified CFX-Flow3D code. Finite volume approach was used to discretize the equations. The set of discretized and linearized equations were solved using the inter-phase slip algorithm (IPSA) method. The simulation was applied to some obtained results in the laboratory experiments and predicted two-phase flow behavior. Calculated two-phase flow rates reflect the sensitivity of fluid flow to gas and liquid permeability in tight gas sand. The calculated flow behavior agrees reasonably well with experimental drainage, imbibition and two-phase flow behaviors.
The Role of Formation Damage in Hydraulic Fracturing Shale Gas Wells
Authors: Guo Boyun , Gao Deli , Wang Quanjun 
Published: December 2011

Abstract
Producing natural gas from shale gas presents a unique challenge to the petroleum engineers because of the low permeability nature of this type of gas reservoirs. Large scale hydraulic fracturing operations are often required for enhancing gas well productivity. Due to the shally characteristics of the reservoir rock, the productivity of the hydraulically fractured gas wells is very vulnerable to the damage by the fracturing fluids. The damaging mechanisms have been recognized to include fluid invasion, proppant embedment, gel filter cake at the fracture face, and the gel residue in the proppant pack. The relative significances of the well damage due to different mechanisms are not clear. It is highly desirable to have an analytical method for predicting the relative importance of different types of damage and optimizing fracturing treatment accordingly. This paper presents such a model and observations from model analyses.
A new mathematical model was developed in this study to predict the effects of fracture fluid filtration, proppant embedment, gel filter cake at the fracture face, and the gel residue in the proppant pack on the productivity of fractured gas wells in shale gas reservoirs. A unique feature of the new model is that it considers reservoir-fracture cross-flow in wells with long fractures and non-linear influx to wells with short fractures. Sensitivity analyses with the model show that, among the investigated four mechanisms, the fluid invasion should have the most detrimental effect, while the formation of proppant-embedment layer should have a negligible effect on the productivity of fractured wells in shale gas reservoirs.
Case Studies: Improved Performance of High Brine Friction Reducers in Fracturing Shale Reserviors
Authors: Paktinat Javad , O'Neil Bill , Tulissi Michael 
Published: December 2011

Abstract
The primary purpose of friction reducers (FR’s) used in stimulating shale reservoirs is to overcome tubular friction pressure and establish high pumping rates. Slickwater (or water frac treatments where friction reducers are used as main source of reducing tubular pressure) fracturing has increased significantly with the advent of horizontal shale stimulation. Technologies, including multi-stage fracturing of horizontal wells have increased frac volume requirements per well. Recent restrictions limiting fresh water usage and environmental concerns of flowbacks have created challenges for operators to adopt mechanical and chemical water treatment means to remove impurities from flowbacks for reuse in slickwater fracturing. However, most treatments do not remove brines from the water requiring development of high brine tolerant friction reducer to maintain high performance.
This study presents experimental and case studies of various cationic and anionic FR’s of the similar molecular weight in high brine flowbacks collected from two major shale plays. Finger print water analyses of shale reservoirs were used as brine source for evaluation. Dynamic friction loop flow apparatus was used to evaluate the rheological properties and formation damage of the FR where high brine waters are being used as the main source of slickwater fracs.
Field data collected for two case histories document the ability of the high brine tolerant friction reducers to perform at a level consistent with traditional products used in fresh water. This confirms the experimental flow data obtained from dynamic friction loop investigations. Results obtained from this study can be used to optimize slickwater frac treatments where flowbacks are the main source of frac water. Primary objectives include.Comparison studies of new high brine tolerant friction reducer with conventional FR’s used in the oilfield.Experimental data illustrating the performance of newly developed FR’s in high brine shale flowbacks. Cost advantage can be realized by using less polymer, while reducing fresh water and disposal of the flowbacks.(will be addressed at a later publication)Case studies of wells treated with the new friction reducers show performance in brines similar to these achieved with conventional FR’s when used in fresh water.
Recent Stimulation Results in the Weir Sandstone
Authors: Hoffman Kurtis Z. , Tellers John H. , Krcek Robert H. 
Published: December 2011

Abstract
The Weir zone in West Virginia is comprised of three separate sandstones that are Lower Mississippian in age and fall within the Price formation. The Weir sandstone of southeastern West Virginia is characterized by a near shore fluvial dominated delta front environment causing a gas bearing reservoir. Stimulation of the Weir sandstones is necessary for economic recovery of gas reserves.
This study provides background on the Upper Weir sandstone of McDowell, Mercer and Wyoming counties of West Virginia and focuses on historical stimulation treatments involving parameters such as amount of proppant and injection rate influencing the Estimated Ultimate Recovery (EUR). An extensive database containing geology, completion, stimulation and production data from the Upper Weir sandstone in southeastern West Virginia was utilized in this study. Single zone completion and adequate production history, greater than 12 months, were the criteria for well selection from the database of Weir wells in the southeastern West Virginia area. The total proppant placed was the major contributing factor in the resultant EUR. Increasing the total proppant not only increases the EUR but also decreases the number of wells to effectively drain the reservoir. From the results, economic analysis was completed to provide guidelines to achieve economic recovery from the Upper Weir sandstone in southeastern West Virginia.
DoReMi-A Passive Geophysical Monitoring Technique for CO2 Injection
Authors: Chen Shen-En , Liu Yangguang , Wang Peng 
Published: December 2011

Abstract
The carbon dioxide (CO2) injection at the Citronelle Oil Field in Alabama has been deployed since December 2009. The injection of the first 7,500 tons of CO2 has been completed in September 2010. To monitor the CO2 injection process and determine the potential for geological changes that may occur because of the injection, geophysical testing has been used at the site: a Derivative of Refractive Microtremor (DoReMi) method using wireless sensor has been conducted for acquiring ground motion in October 2008, January 2009 and June 2009, prior to injection, and again in December 2009, March 2010, May 2010 and September 2010, during injection, and after injection in November 2010, March 2011 and May 2011. The measurements were made at well sites along two linear arrays running from north - south and from northeast - southwest. The outcomes of the geophysical monitoring at the Citronelle Oil Field are shear-wave velocity profiles that are correlated to the static stress distribution at different injection stages. It is noticed that the pressure in the oil production layer and overburden strata at the time of water injection and CO2 injection has already built up in the entire monitored region. The results of the geophysical monitoring for the pilot injection will aid oil field operators in decision making for the future commercial-scale reservoir management strategies.
Pressure Transient Characteristics of Hydraulically Fractured Horizontal Shale Gas Wells
Authors: Cheng Yueming 
Published: December 2011

Abstract
Shale gas wells require a long horizontal lateral intersecting multiple hydraulic fractures to be economically viable. Because of the nature of ultralow permeability of shale matrix, it would take a significant long period of time for a well producing in transient flow regimes. Therefore, pressure transient characteristics for such a gas well is of considerable importance in both evaluation of fracturing treatment by estimating fracture and reservoir parameters and prediction of the long-term production behavior of wells in gas recovery.
The pressure transient response for a horizontal shale gas well with multiple transverse fractures is controlled by a specific combination of reservoir properties and well configuration. Focused on Marcellus shales, this paper investigates the characteristics of pressure transient response under a number of factors and flow mechanisms. The factors that are considered include matrix permeability, conductivity of hydraulic fractures, cluster spacing, and size/enhanced permeability of stimulated zone. The impacts of gas desorption and stress-dependent fracture conductivity on pressure transient behavior are also illustrated. This study provides insights into the pressure transient characteristics during shale gas well production.