bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Dynamic Simulation to Assess Effectiveness of Downhole Pump for Gas Well Deliquification
Authors: Yusuf Rahel , Veeken Kees , Hu Bin 
Published: June 2014

Abstract
Reservoir pressure depletion in gas reservoirs causes gas flow reduction with time and eventually leads to liquid loading as the gas flow up the well can no longer efficiently lift the associated liquids to surface. Liquid loading has a detrimental impact on production and a suitable deliquification method is required to continue production and maximize recovery. A downhole pump is one such deliquification measure where the pump sits at the bottom of the producing interval and evacuates the accumulated liquids up an insert (coiled tubing) string. It is important to assess beforehand whether the pump will effectively remove the liquids and hence deliver sufficient business value.
A transient multiphase simulator has been used to simulate the gas well liquid loading process in a candidate well completed with 5.5" tubing, followed by the deliquification process triggered by a downhole pump installed 20 m above the bottom of the producing interval on a 1.5" coiled tubing. Simulations have been conducted for seven different liquid pump rates, three reservoir pressures and two water-to-gas ratios to assess the effectiveness of the pump under different operating conditions and to arrive at the optimum pump size and operation methodology.
Simulations indicate that the downhole pump is capable of deliquifying the well and restoring production. However, for a given pump capacity and reservoir pressure, the surface gas production may either oscillate or settle at a steady state value. Oscillations occur when the pump capacity is too high and causes gas ingress into the pump, which introduces partial albeit temporary liquid loading of the wellbore. Continuous steady state gas production occurs when the pump capacity is not too high and an equilibrium situation is reached between the liquid being pumped out and the liquid being produced. The optimum pump rate is controlled by the effectiveness of the downhole separation between the gas and liquid phases and will minimize oscillating ingress of gas into the pump.
This study emphasizes the role of transient simulations in predicting the effectiveness of a deliquification measure before embarking on field deployment. The simulations provide valuable insight into flow and pressure transients inside the wellbore during a gas well deliquification using a downhole pump. The information retrieved from the transient simulations is used to decide the optimum pump capacity and operation guidelines. To the best of authors' knowledge, this is the first time that a transient simulation of a downhole pump for gas well deliquification is presented in open literature.
Foam Cement Job Simulations: Learning from Field Measurements
Authors: Dooply Mohammed , Flamant Nicolas , Kanahuati Alia Iza , Pringuey Thibault 
Published: June 2014

Abstract
Foamed cement is often used to seal the annulus of many surface casing strings in deepwater offshore wells. The objective of this paper is to highlight the benefits a foamed fluid placement simulator brings to the design and evaluation processes for foam cement jobs.
A dynamic compressible hydraulic model that simulates the flow of nitrified fluids during primary cementing operations is presented. For a long time, the industry had relied on models that used average density properties for the foamed fluid. Yet the foam quality can change from 70% at surface conditions to 10% or less at bottomhole conditions. In terms of density this ranges from 600 kg/m3 (5 lb/gal) to 1800 kg/m3 (15 lb/gal). The average density approximation is therefore too coarse. In reality, there is continuous changing of fluid density and rheology during placement of the foamed fluids due to the changes of pressure and temperature along the flow path. Both density and rheology variations can be taken into account in a compressible hydraulic model that simulates the flow of nitrified fluids during primary cementing operations.
Measurements taken on actual foam cement jobs are compared to the simulator's output. The actual data and the simulated output compare favorably. Discrepancies between the model and acquired data are also analyzed to improve the understanding of the actual operation. The inherent limitations of post job analysis are discussed. The absence of caliper or known geometry on surface and conductor casings becomes more obvious. The placement of sensors on flow lines, the absence of sensors after the foam cross, and the uncertainty on geothermal gradient are also sources of divergence between the model and the measurements as will be seen through case study in this paper.
The continuous improvement of the model and the simulator will contribute to more robust foam cement job designs. Robust foam cement job designs will assure the isolation integrity of the structural casing strings for deepwater wells and ensure safe operations while executing this type of jobs.
High-Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of Gulf of Mexico Oil Mixed With Nitrogen
Authors: Hustad Odd Steve , Jia Na , Pedersen Karen Schou , Memon Afzal , Leekumjorn Sukit 
Published: June 2014

Summary
This paper presents fluid composition, high-pressure pressure/volume/temperature (PVT) measurements, and equation-of-state (EoS) modeling results for a recombined Tahiti oil, Gulf of Mexico (GoM), and for the oil mixed with nitrogen in various concentrations. The data include:
Upper and lower asphaltene onset pressures and bubblepoint pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F), asphaltene precipitation is seen after the addition of 27 mol% of nitrogen. Viscosity data for the swelled fluids showing that the addition of nitrogen significantly reduces the oil viscosity. Slimtube runs indicating that the minimum miscibility pressure (MMP) of the oil with nitrogen is significantly higher than estimated from published correlations.
The data were modeled with the volume-corrected Soave-Redlich-Kwong (SRK) EoS and the perturbed-chain statistical association fluid theory (PC-SAFT) EoS. Although both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid-phase compressibility of the reservoir fluid swelled with nitrogen.
Nitrogen-gas flooding is expected to have a positive impact on oil recovery because of its favorable oil-viscosity-reduction and phase behavior effects.
Managing Shut-in Time to Enhance Gas Flow Rate in Hydraulic Fractured Shale Reservoirs: a Simulation Study
Authors: Fakcharoenphol Perapon , Torcuk Mehmet , Bertoncello Antoine , Kazemi Hossein , Wu Yu-Shu , Wallace Jon , Honarpour Matt 
Published: June 2014

Abstract
Some shale gas and oil wells undergo month-long shut-in times after multi-stage hydraulic fracturing well stimulation. Field data indicate that in some wells, such shut-in episodes surprisingly increase the gas and oil flow rate. In this paper, we report a numerical simulation study that supports such observations and provides a potentially viable underlying imbibition and drainage mechanism. In the simulation, the shale reservoir is represented by a triple-porosity fracture-matrix model, where the fracture forms a continuum of interconnected network created during the well simulation while the organic and non-organic matrices are embedded in the fracture continuum. The effect of matrix wettability, capillary pressure, relative permeability, and osmotic pressure, that is, chemical potential characteristics are included in the model.
The simulation results indicate that the early lower flow rates are the result of obstructed fracture network due to high water saturation. This means that the injected fracturing fluid fills such fractures and blocks early gas or oil flow. Allowing time for the gravity drainage and imbibition of injected fluid in the fracture-matrix network is the key to improving the hydrocarbon flow rate during the shut-in period.
Factors Affecting Early Well Productivity in Six Shale Plays
Authors: Crafton James W. , Noe Sandra L. 
Published: June 2014

Abstract
A population of over 360 wells from six shale play areas was investigated to assess the impact of various early production management strategies, with attention given to the time delay between stimulation and first production, the "resting" or "soak" period, the effect of subsequent shut-ins, proppant conductivity and interfacial tension management. Subsets of this population were used to perform the various evaluations. The use of the non-volatile or persistent interfacial tension management chemistry significantly mitigated, but did not prevent, damage arising from delay to first production or shut-ins. Based on the performance metric used, delay to first production is not beneficial. However, based on other data, the likelihood of improvement when using persistent interfacial tension management is slightly better than even odds, but without it, only about one in three. Once on production, if the rate with which the flowing pressure was decreased exceeded about 100 psi per day, a significant negative impact on the reservoir / wellbore connectivity was observed. The last control factor was the obvious benefit derived from using high conductivity proppants, in conjunction with the persistent interfacial tension management.
A Day in the Life of a Barrel of Water: Evaluating Total Life Cycle Cost of Hydraulic Fracturing Fluids
Authors: Watts Robin 
Published: June 2014

Abstract
For several years now, regulatory agencies including the U.S. Environmental Protection Agency (EPA), energy associations like the American Petroleum Institute (API), and more recently the Center for Sustainable Shale Development (CSSD) have provided recommendations, regulations, performance standards, and guidelines to improve water management in oil and gas exploration. Yet, to fully appreciate the life cycle costs of fluids used for hydraulic fracturing – including water, one needs to examine the total costs of fluid acquisition, management and disposal. Typically, these costs are divided between various groups within an operator's organization (i.e., completions and production), with budgeting emphasis on acquisition costs during the completions process.
This paper examines the total life cycle costs of hydraulic fracturing fluids, comparing water-based and energized solutions. It evaluates when fracturing fluids energized with carbon dioxide (CO2) or nitrogen (N2) can be used to reduce water volume for more economical hydraulic fracturing. It also evaluates how the selected fracturing fluid can affect productivity. In certain situations, the increased productivity achieved with energized solutions can more than offset lower per-barrel water costs, driving a lower overall unit cost of production. To approach our analysis, we will look at "A Day in the Life of a Barrel of Water" used for hydraulic fracturing.
Design of a Cyclonic Solids Jetting Device and Slurry Transport System for Production Systems
Authors: Rawlins C. Hank 
Published: June 2014

Abstract
Production separators require increased sand handling capability as watercut grows due to field maturation and EOR use. A compact cyclonic jetting device allows on-line fluidization and removal of sand and solids from production vessels and tanks. The cyclonic transporter combines the jetting and evacuation functions into a single device for integration into new build or retrofit separation vessels. Using an optimized hydrocyclonic platform this technology converts jetting spray water into shielded vortex flow that affects sand in a circular zone with no disturbance of the oil-water interface. The area of influence for the device is a function of set height, spray flow, and spacing. The optimum placement of a single unit was determined at 10 cm (4") set height with 0.7 barg (10 psig) spray pressure. At 28 cm (11") sand bed depth in an atmospheric tank, the device has a circular area of influence of 1.1 m² (11.7 ft²).
Placing two units in parallel with overlap of their affected zones does reduce the egg-carton effect. Optimum operation, in terms of total sand removed, occurs when the units do not overlap. The discharge slurry concentration has a peak of up to 60 wt.% solids which follows an exponential decay profile as the sand is evacuated. The concentration decreases to negligible sand at 10-15 minutes of operation which validates the process jetting time. The design of the cyclonic jetting device allows on-line solids removal using less water than conventional spray jetting with no disturbance of the oil-water interface during operation and elimination of mechanical wear.
Visualization and Analysis of Surfactant Imbibition into Oil-Wet Fractured Cores
Authors: Mirzaei Mohammad , DiCarlo David A. , Pope Gary A. 
Published: June 2014

Abstract
Imbibition of surfactant solution into the oil-wet matrix in fractured reservoirs is a compl icated process which involves gravity, capillary, viscous, and diffusive forces. The standard experiments for testing imbibition of surfactant solution involve an imbibition cell, where the core is placed in the surfactant solution and the recovery is measured versus time. Although these experiments prove the effectiveness of surfactants, little insight into the physics of the problem is achieved.
In this study, we performed water and surfactant flooding into oil-wet fractured cores and monitored the imbibition of the surfactant solution using CT scanning. From the CT images, the surfactant imbibition dynamics as a function of height along the core was obtained. While the water flood only displaced oil from the fracture, the surfactant solution imbibed into the matrix; the imbibition is frontal with the greatest imbibition rate at the bottom of the core, and the imbibition decreasing roughly linearly with height. Experiments with cores of different sizes showed that increase in either the height or the diameter of the core causes decrease in imbibition and fractional oil recovery rate. We also perform numerical simulations to model the observed imbibition.
Based on the experimental measurements and numerical simulation results, we propose a new scaling group that includes both the diameter and the height of the core. We show that the new scaling groups scale the recovery curves better than the traditional scaling group.
Propagation Measurements for Acoustic Downhole Telemetry Systems
Authors: Farraj Abdallah K. , Miller Scott L. , Qaraqe Khalid A. 
Published: June 2014

Abstract
Advanced downhole communication technologies are used by well operators to monitor flow rate, temperature, and pressure data. Currently, the use of wired tools is popular although these tools present cost, maintenance, and reliability issues. Acoustic waves that propagate by vibrating the pipe's body inside the well are investigated as an alternative solution. While this technology offers great benefits, its propagation aspects inside the wells are unclear.
This work explores the use of acoustic waves for downhole telemetry systems. A testbed was designed to investigate the propagation of acoustic waves over production pipes. The testbed comprises an acoustic tool that transmits data from inside wellbore to the surface without cables, an internally-developed receiver unit, and five segments of 7-inch production tubing that form a pipe string. Acoustic waves propagate by vibrating the pipe's body in this setup. Input frequencies from 100 Hz to 2000 Hz were investigated, and propagation measurements were taken along the pipe string. Further, the application of signal processing techniques is investigated to address the effects of dispersion and attenuation in the acoustic channel.
Results of this work show that many harmonics propagate through the pipe string. Acoustic waves experience a frequency-dependent attenuation over the pipe string. Multipath reflections in the pipe string also cause noticeable signal dispersion. This work also shows that acoustic waves experience an extra frequency-dependent attenuation due to the presence of concrete; many high-order harmonics are heavily attenuated after encasing the pipe in concrete. Moreover, signal processing algorithms provide pronounced results in reducing the channel attenuation and dispersion. This work recommends that acoustic-wave technology is a promising cost-effective and reliable solution for wireless downhole telemetry systems. Furthermore, signal processing algorithms can be useful tools for the acoustic downhole communication systems.
Technical contributions include: characterizing the channel response to different input frequencies along the pipe string; investigating the power spectral density, signal-to-noise ratio, and attenuation rate measures; studying the dispersion parameters of the channel; characterizing the effect of concrete on acoustic wave propagation; and applying signal processing algorithms.
Using Big Data and Smart Field Technology for Detecting Leakage in a CO2 Storage Project
Authors: Haghighat S. Alireza , Mohaghegh Shahab D. , Gholami Vida , Shahkarami Alireza , Moreno Daniel 
Published: June 2014

Abstract
Smart Fields are distinguished with two characteristics: Big Data and Real-Time access. A small smart field with only ten wells can generate more than a billion data points every year. This data is streamed in real-time while being stored in data historians. The challenge for operating a smart field is to be able to process this massive amount of information in ways that can be useful in reservoir management and relevant operations. In this paper we introduce a technology for processing and utilization of data generated in a smart field. The project is a CO2 storage demonstration at Citronelle Dome, Alabama and the objective is to use smart field technology to build a real-time, long-term, CO2 Intelligent Leakage Detection System (ILDS).
The main concern for geologic CO2 sequestration is the capability of the underground carbon dioxide storage to confine and sustain the injected CO2 for very long time. If a leakage from a geological sink occurs, it is crucial to find the approximate location and amount of the leak in order to take on proper remediation activity.
To help accommodate CO2 leak detection, two PDGs (Permanent Down-hole Gauges) have been installed in the observation well. A reservoir simulation model for CO2 sequestration at Citronelle Dome was developed. Multiple scenarios of CO2 leakage are modeled and high frequency pressure data from the PDGs in the observation well are collected. The complexity of the pressure signal behavior and the reservoir model makes the use of inverse solution of analytical models impractical. Therefore an alternate solution is developed for the ILDS, based on Machine Learning.
High Frequency Data Streams are processed in real-time, summarized (by Descriptive Statistics) and transformed into a format appropriate for pattern recognition technology. Successful detection of location and amount of CO2 leaking from the reservoir using the real-time data streams demonstrates the power of pattern recognition and machine learning as a reservoir and operational management tool for smart fields.
Probabilistic Reserves Addition within a Project
Authors: Morales E. , Horizon B. V. , Lee W. J. 
Published: June 2014

Abstract
The SPE-Petroleum Resource Management System (SPE-Petroleum Resources Management System, 2007) is a project based system, where the project definition and its treatment play a key role in the estimation and categorization of reserves and resources and their range of uncertainty. This is key to capture the potential downside and upside of the project and the commercial opportunities that may exist. Wrongly defining the project may result in an improper ring-fencing of the elements that must be considered in reserves and resource estimation and in improper risk assessment, with potential for missed opportunities or failure as an outcome.
The SPE-PRMS is clear on the type of aggregation that can be used within a field, a property or a project, with probabilistic addition allowed within each of these entities. However, despite this clarity, most companies in the oil and gas industry have not yet adapted their methods to reflect these best practices.
The technical literature has devoted significant effort to address technical and commercial issues in probabilistic reserves and resource estimation of a field or incremental activity (e.g., drilling wells). However, very little effort has been devoted to the proper definition of a "project", its attributes, ring-fencing, uncertainty assessment approaches for the fields within the project and in the categorization and aggregation of reserves or resources within the project.
Furthermore, downside project economics should capture the true project's downside (or the true P90 of the project) rather than an overly-pessimistic estimate of its proved reserves calculated using arithmetic additions within the project.
In order to describe a simple approach to project reserves estimates, this paper uses a Liquefied Natural Gas (LNG) project and its reserves estimate as an example. The selected example shows different interpretations among joint venture (project) partners of the existing standards, recommendations and regulations. The approach described can also be used in other types of projects or resources estimates (e.g. contingent resources), to properly capture the downside and upside risks, uncertainty ranges and project business opportunities, truly reflecting the project's reasonable certainty at the P90 level. Gas projects are preferred to illustrate this approach.
For gas commitment purposes, many buyers require the LNG project's proved (P90) reserves to be independently certified before contractual commitments can be finalized. Underestimation of the project's true proved reserves may result in loss of opportunities and/or in an overly-pessimistic assessment of the Proved reserves not reflecting reasonable certainty.
Requirements from regulatory bodies (e.g., NARA (SEC), 2009; ESMA, 2011) and their linkages to reserves aggregation within a project are also addressed in this paper.