bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geochemical Modeling and Experimental Evaluation of High-Ph Floods: Impact of Water-Rock Interactions in Sandstone
Authors: Kazempour Mahdi , Sundstrom Eric , Alvarado Vladimir 
Published: September 2011

Abstract
Alkaline flooding, either for enhancing heavy oil recovery, or in alkaline-polymer (AP) and alkaline-surfactant-polymer (ASP) flooding for lighter oils, represents an important EOR strategy. Injection of alkaline solutions leads to mineral dissolution and precipitation with likely resulting changes in permeability and porosity of reservoirs, which in turn alter solution pH. Accurate prediction of pH, alkali consumption and aqueous chemistry changes are required to design suitable chemical flooding blends. Excessive consumption of alkali can result in degradation of flood performance and lower than expected oil recovery.
We report results of state-of-the-art geochemical simulations for sandstone reservoir mineral assemblages and alkali solutions (NaOH, Na2CO3, and NaBO2) employed in AP and ASP formulations. The strategy has been tested for conditions of the State of Wyoming in Minnelusa reservoir and Berea sandstones. Single-phase high-pH floods were completed in the lab to calibrate and validate geochemical simulations.
Results show that rock-fluid interactions are a strong function of mineral type and amount, alkaline solution injection flowrate, and composition of injected and formation water. It is found that anhydrite has a significant impact on pH buffering capacity, water chemistry changes and permeability damage against conventional alkali agents in chemical flooding particularly in the case of Na2CO3, but no significant pH buffering is observed during NaBO2 flooding. Experimental data and model results show that the pH-buffering effect is maintained even after several pore volumes of alkaline solution are injected, if a sufficient fraction of relevant minerals are present. Comparison between linear core and field flooding simulations show that short reaction times tend to minimize these effects and may lead to conclusions that cannot be readily transferred to field cases.
By applying reaction-transport modeling, the design of chemical flooding can be improved and formulation effectiveness losses caused by reservoir mineralogy can be avoided, even in cases where traditional laboratory screening procedures would indicate a suitable formulation for chemical flooding.
A New Dimension Added to the Hydraulic Fracture Stimulation for a Volcanic Reservoir Based on Microseismic Monitoring
Authors: Mishra Satyabrata , Gupta Anish , Mathur Mohit , Purusarthy Naresh , Wenk Andrew 
Published: September 2011

Abstract
The Raageshwari Deep Gas (RDG) Field in the Barmer Basin, India is a lean gas condensate reservoir, with excellent gas quality of ~80% methane, low CO2 and no H2S. The productive zones are in volcanic rocks and volcanogenic sediments. From a permeability perspective, the RDG reservoir is similar to typical tight gas reservoirs in other parts of the world which cannot be commercially developed without large-scale hydraulic fracturing. Recent RDG hydraulic fracture treatments have been monitored with microseismic mapping technology. The microseismic data was acquired in June 2010 to quantify the trend of hydraulic fracture networks induced in a 5-stage stimulation program. The recorded P and S wave events were subsequently mapped in 3D space by fracture stage (in time) to effectively represent the onset, propagation and trends of the fractures and the extent, overlap or inter-connection of the resulting fracture networks. The initial objective of conducting microseismic mapping was only to calibrate the existing fracture simulator. Earlier hydraulic fracture treatments had been conducted with a conventional gas condensate frac design in mind, with targets of ~100m of frac length and a dimensionless fracture conductivity (FCD) ranging from 5-10. The initial frac schedules were designed with large pad and proppant stage volumes (~275,000lb of 20/40 ISP and 16/30 ISP). The efficacy of these fracture treatment designs was to be verified with the microseismic mapping technology. It was found that RDG does not have the typical tight gas reservoir architecture which was assumed for the initial frac designs, but consists of tight matrix porosity contained within a very complex network of natural fractures and planes of weakness with conjugate jointing. Hence the conventional fracture design was changed to deal with such fracture network for future fracturing campaigns.
Integrated Geo-Statistical Modeling – An Effective Tool to Meet the Exploration Challenge of Low Porosity Carbonate Reservoir within Najmah-Sargelu Formation, Kuwait
Authors: Nath Prabir Kumar , Prasad Raghav , Khan Badruzzaman , Singh Sunil Kumar , Abu-Taleb Reyad , Bader Sara 
Published: September 2011

Abstract
The emergence of low porosity carbonate lithofacies of Najmah-Sargelu Formation as a commercial hydrocarbon play has led to change the exploration perspective of these formations. Several wells from different structures in Kuwait has shown the production potential of light oil@ 1000–4000 BOPD and natural gas 3.8–19.0 MMSCFD. The production has been obtained from bituminous mudstone, wackestone and algal limestone from Najmah-Sargelu Formation.
Understanding the geometry and distribution of carbonate lithofacies of Najmah-Sargelu Formation is a major exploration challenge. Geo-statistical 3D model is a dynamic tool, which has been utilized to quantify the geometry and spatial distribution of carbonate lithofacies vis-a-vis its continuity.
A careful geo-statistical workflow was evolved to address the major challenges of these reservoirs. An artificial intelligence, neural network was trained against cored section and subsequently applied in the noncored sections for lithofacies prediction. Sequence Stratigraphic framework, seismic grid and 3D geo-statistical modeling were integrated to create a geological model. Core-measured rock property data were analyzed to illustrate the distributions of core porosity and permeability of Najmah-Sargelu lithofacies. The distribution of internal properties and heterogeneity has been quantitatively described as the relationship of a reservoir facies within a sequence stratigraphic framework. Spatial estimation of lithofacies and reservoir properties provides insight into the deposition and diagenetic process of the reservoir units.
The depositional pattern and connectivity analysis suggests a ramp setting in inner shelf environment of deposition with three major alternate transgressive and regressive sequences. An integrated geo-statistical modeling has resulted in depicting the internal geometry and connectivity of low porosity carbonate lithofacies thereby reducing the uncertainty in volumetric assessment in the delineation phase of Najmah-Sargelu Formation.
Gas Condensate Flow Around Deviated And Horizontal Wells
Authors: Ghahri P. , Jamiolahmady M. , Sohrabi M. 
Published: September 2011

Abstract
Drilling deviated and highly deviated wells (DWs) in gas condensate reservoirs is aimed at increasing reservoir reach and reducing pressure drop, thus improving well deliverability. The flow of gas and condensate around the wellbore when the pressure drops below dew point pressure is affected by phase changes and variation of relative permeability (kr) with velocity and interfacial tension (IFT). Flow simulations and well productivity calculations for these near critical fluid systems and in the case of such three dimensional DW geometries, are more complex compared to those of a 1D radial vertical well. There are limited sensitivity studies dedicated to such important petroleum engineering situations.
We have developed various mathematical single-well models simulating flow of gas and condensate around such wells. A comprehensive sensitivity study (over 500 simulation runs) was then conducted to evaluate the impact of pertinent parameters on the DWs performance with some important practical findings. We have also considered horizontal wells, which are DWs with the deviation angle of 90°. The results demonstrated that the performance of DWs strongly depends on wellbore gas fractional flow (GTRw) and velocity. For instance, for a given pressure drawdown, the coupling effect (increase in kr due to an increase in velocity or decrease in IFT), improves the performance of highly DWs at short well lengths, whilst the negative impact of high velocity inertia (a decrease in kr by an increase in velocity) is more pronounced at higher GTRw, smaller wellbore radius and higher reservoir thickness values. For long DWs the productivity ratio (deviated to vertical well fluid production rate ratio) does not vary with GTRw. However, for short DWs, it increases for moderate condensate fluid but decreases for the rich gas condensate fluid. This is due to the variation of contribution of coupling and inertia with GTRw in the deviated and vertical wells.
Multi-Scale and Multi-Physics Methods for Numerical Modeling of Fluid Flow in Fractured Formations
Authors: Qin Guan , Gong Bin , Bi Linfeng , Wu Xiaohui 
Published: September 2011

Abstract
Natural fractures reside in various subsurface formations and are at various length scales with different intensities. Fluid flow in fractures, in matrix and between matrix and fractures are following different flow physics. It is thus a great challenge for efficiently modeling and simulation of fluid flow in fractured media due to the multi-scale and multi-physics nature of the flow processes.
Traditional dual porosity and permeability approach represents factures and matrix as different continuum. The transfer functions or shape factors are derived to couple the fluid flow in matrix and fractures. The dual porosity and permeability model can be viewed as a multi-scale method and the transfer functions are used to propagate fine-scale information to the coarse-scale reservoir simulation. In this paper, we perform a detailed study to better understand the optimal way to propagate the fracture information to the coarse-scale model based on the detailed fracture characterization at fine-scale. We use two different upscaling procedures. One is the multiple sub-region method (SPE 102491) that is based on the dual porosity and permeability approach. The other is using Stokes-Binkman equation (SPE 105377) to solve the fine-scale flow problem and then deriving the upscaling information from the fine-scale solution.
The Discrete Fracture Modeling (DFM) approach is used to represent each fracture individually and explicitly. Then, both the multiple sub-region method and Stokes-Brinkman equations are used to solve for fine-scale flow information based on the DFM. The fine-scale information captured by these two approaches are used in coarse-scale reservoir simulations respectively. The two approaches are compared in terms of how well they preserve key fine-scale flow dynamics in the coarse simulations. We then propose an efficient and accurate upscaling workflow for numerical modeling of fractured media, which will extends predicting capability in efficient development of fractured reservoirs.
A Systematic Analysis to Select an Optimized Perforating Interval as a Key Factor for Improved Oil Recovery: Impact of Dynamic and Static Petrophysical Properties on Well Production
Authors: Miranda Luis Javier , Angel Franklyn 
Published: September 2011

Abstract
Unexpected high water cut, sand production and low productivity have negatively affected multiple wells producing from reservoirs in the Apure Area fields of southwest Venezuela. As a result, multiple well interventions have been conducted which increase costs and delay oil production. Several of these wells are inactive today but could be potential candidates for reactivation by reperforating prospective intervals. In several cases, the selection of the perforated interval for these reservoirs is considered inefficient because the effects of multiple dynamic and static petrophysical properties are not considered in the current method, such as vertical permeability, anisotropy or pore throat size, among others. We propose a systematic analysis to optimize the interval to be perforated for inactive and new wells that will minimize such related production problems.
The proposed analysis involves the incorporation of multiple variables (type of perforation, interval to perforate, distribution of reservoir fluids, fluid of completion, etc.) to consider the effects of the different petrophysical properties on well productivity. The latter are obtained by integration of rock-core data and conventional and advanced well logs acquired in open and cased hole. In addition, we conducted a sensitivity study to analyze other parameters, such as perforating method and production behavior. A technical analysis was performed to select the optimum design based on different conditions leading to a complete study. The results show that the optimum interval selection and type of perforation to be implemented should not involve only a simple net pay consideration but also multiple factors such as reservoir properties, reservoir fluids distribution and perforating method that play a key role in well production behavior. Finally, we present field applications that confirm the success of this method that enables the reliable selection of an optimized perforated interval.
Challenges and Solutions for Automated Wellbore Status Monitoring - Breakout Detection as an Example
Authors: Wessling Stefan , Dahl Thomas , Pantic Dinah 
Published: September 2011

Abstract
Automated real-time wellbore stability services contribute to a significant reduction of non productive time. Automation reduces the workload, supports the decisions of engineers and facilitates simultaneous remote supervision of multiple wells. The industry is approaching first steps towards automated drilling; however the accomplishment of mature automated systems requires further extensive research and development. In particular, automated real-time wellbore stability systems require a high level of confidence because decisions based on the results can have significant consequences. Robust, reliable and intensively tested algorithms need to be developed and experience has to be gathered by comprehensively supervised field testing.
This paper presents an algorithm and its applications for the automated monitoring of wellbore status. Taking the detection of breakouts on images of the borehole wall as an example, observations and experience gained during the development of such a system are documented. A breakout detection system is fed by formation evaluation and drilling dynamics logs acquired by downhole tools during the drilling operation. The automated breakout detection algorithm is able to scan image log data to identify the existence or non-existence of breakouts and to deliver parameters such as the breakout orientation and width for the calibration of in-situ Earth stress directions and magnitudes needed for calculation of the shear failure gradient (one of two lower bounds for the pressure window).
The automatic detection of breakouts on low-resolution resistivity and density real-time images proves the algorithm's applicability while drilling. The tests were also used to identify operating constraints, i.e., circumstances (especially of geological nature) under which the system may deliver erroneous information. Users need to be aware of such operating constrains to have confidence in the algorithm's reliability.
Engineering Workflows Provide Integrated Operations and Streamline Real-Time Production Optimization
Authors: Barbarino Sebastiano , Sarmiento Salvador , Cuadras Romel , Suarez Jose , Hung Mailing , Manzanilla Franklin 
Published: September 2011

Abstract
This paper explores the results of one operator's successful implementation of a workflow-based solution for real-time Production Surveillance and Optimization of a large on-shore field in Mexico. We will also examine the fundamental aspects of large-scale workflow delivery in a real-world environment – in this case, involving over 200 wells producing over 200,000 STBD, 50+ users, multiple and often conflicting sources of data (ex. Field vs. SCADA), and integration of production modeling applications from multiple vendors.
The solution combines automation of production modeling workflows, real-time monitoring, Surveillance-by-Exception, and virtual integration of 8 data sources – including real-time, operational, well test, field data, and others – into a single and user-friendly environment. It has been designed with the asset in mind, and has delivered their goals of: Maximize total oil production,Minimize downtime,Virtual Well Flowrate Metering,Well performance overview, providing a single point-of-access to all available information,Standardize engineering processes across the asset, with a heavy emphasis on automation and analytics.
The "intangible" benefits of standardizing processes and providing readily-available access to information are seen as key enablers of the more directly measurable economic benefits.
Prior to the implementation of this solution, it was demonstrated that a significant portion of the asset engineers' time was spent on gathering data from multiple sources. Such activities were manual and error-prone, and led to data duplication, data inaccuracies, and - most importantly - potential for decisions to be made based on incomplete information.
The new solution addresses all of these challenges. Integrated reporting and surveillance-by-exception methods ensure that engineers' time is now focused on engineering issues – not data gathering. "Live links" to all sources ensures that data duplication is no longer an issue. And workflow-based automation have brought the various pre-existing Well, Production Network, and Reservoir modeling tools "Online", so they can be incorporated into daily operational activities and decision-making.
The work is significant as a successful implementation of a large-scale production optimization solution configured to established operator best practices. In an age when operators are faced with declining production rates, smaller discoveries, and a "graying" workforce, such solutions allow operators to do more with less and deliver maximum asset value.
Probabilistic Performance Forecasting for Unconventional Reservoirs with Stretched-Exponential Model
Authors: Can B. , Kabir C. S. 
Published: September 2011

Abstract
Reserves estimation in an unconventional-reservoir setting is a daunting task because of geologic uncertainty, complex flow patterns evolving in a long stimulated-horizontal well, among other variables. To tackle this complex problem, we present a reserves-evaluation workflow that couples the traditional decline-curve analysis with a probabilistic forecasting frame. The stretched-exponential production decline model (SEPD) underpins the production behavior. Our recovery appraisal workflow has two different applications: forecasting probabilistic future performance of wells that have production history and new wells without production data. For the new field case, numerical model runs are made in accord with the statistical design of experiments for a range of design variables pertinent to the field of interest. In contrast, for the producing wells the early-time data often need adjustments owing to restimulation, installation of artificial-lift, etc. to focus on the decline trend. Thereafter, production data of either new or existing wells are grouped in accord with initial rates to obtain common SEPD parameters for similar wells. After determining the distribution of model parameters using well grouping, the methodology establishes a probabilistic forecast for the individual wells.
This paper presents a probabilistic performance forecasting methodology in unconventional reservoirs for wells with and without production history. Unlike other probabilistic forecasting tools, grouping wells with similar production character allows estimation of self-consistent SEPD parameters and alleviates the burden of having to define uncertainties associated with reservoir and well-completion parameters.
Automating Decline Curve Analysis in an Integrated Reservoir Management Portal
Authors: Nuaim Ahmed , Madani Husameddin , Seemann Dennis , Holdaway Keith 
Published: September 2011

Abstract
Estimating reserves and predicting production in reservoirs has long been a challenge. The importance of performing accurate analysis and interpretation of reservoir behavior using only rate and pressure data as a function of time or cumulative production is fundamental to assessing remaining reserves and for forecasting production. An interactive system was developed to assist in Decline Curve Analysis (Cartesian, Exponential, Harmonic and Hyperbolic) and Production Forecast in an Integrated Reservoir Management environment.
This paper introduces a refreshingly intuitive navigation of the disparate data sources and input parameters aligned with a comprehensive suite of forecasting models wrapped into a web-based solution. The user is enabled with interactive graphical output to extensive "what-if" combinations of critical input parameters across multiple forecasting models. Whether working with oil or gas reservoirs, the user has access to a rich compendium of forecasting techniques that detail accuracy indicators and interactive graphs. The relationship, for example, between P/Z and cumulative gas production for typical gas reservoirs can be studied by calculating pressure response to various modes of gas production and water encroachment.
The motivation of designing a web-based DCA in an integrated portal was the need of reservoir engineers to establish a one stop information analysis integrated platform. This platform integrates different data sources and applications used for analyzing engineers' fields and reservoirs saving them the time needed to search and manipulats the data.