bluuebunny/crossref_metadata_2025_split huggingface dataset:
How Does Mixing Water Quality Affect Cement Properties
Authors: Saleh F. K. , Rivera R. , Salehi S. , Teodoriu C. , Ghalambor A. 
Published: January 2018

Abstract
The integrity of a well is a crucial component for the longevity of a well. Cement isolates the casing and protects the well from fluids, pressure, and other components that may jeopardize its stability. Extreme care and research should be invested in analyzing the water quality that is used to mix cement. In this study, the effects of water quality on API Class G-Portland cement were studied to understand the relationship between water quality, rheology, thickening time, and compressive strength. Although extensive research has been made on well cement in general, no previous research focused on oilwell cement water quality was available until now. Thus, this paper is intended to serve as reference as well as motivation for future research. Cement thickening time was recorded using a cement consistometer and compressive strength using a universal testing machine. We tested several samples including soft to very hard, very saline and field waters. We also tested the hard water at different temperatures to investigate the effect of temperature on thickening time. A positive correlation occurred between the temperature of the mixing water and consistency, the higher the temperature was of the mixing water, the faster the consistency rose. In contrast, a negative correlation between water hardness and thickening time occurred. As water hardness increased, thickening time decreased and vice versa. A percentage change up to 2.4% was recorded between different water qualities making soft water (0 gm/L) have a longer thickening time in comparison to very hard water (180 gm/L+). Variations on the pH of the different waters used did not seem to have a significant impact on the results obtained. Compressive strength results showed that soft water (water with no hardness) is the strongest among the other samples prepared with different waters. In addition, a similar trend cannot be observed at different curing times. For instance, some samples show high strength on the first day but drops as cement hydration time increases.
Injectivity Decline During Waterflooding and PWRI due to Fines Migration
Authors: Borazjani Sara , Chequer Larrisa , Russell Thomas , Bedrikovetsky Pavel 
Published: January 2018

Abstract
Injectivity decline by fines migration with two-phase flow is important in low-salinity and smart waterflooding in oilfields. The complexity of detachment of the natural reservoir fines, their mobilization, migration and straining in two-phase environment preclude simple formulae for injectivity decline prediction. The objective of the present study is to derive of the semi-analytical model for two-phase axi-symmetric flow with variation of injected salinity, fines migration, and consequent permeability damage. A simple and robust model allows investigating the effects of injection rate, injected salinity, oil viscosity, relative permeability, and kaolinite content in the rock on skin-factor growth.
Treating Liquid Banking Problem to Increase Shale Gas Wells Productivity
Authors: Phan Tri , Kazempour Mahdi , Nguyen Duy , Champion Nalco 
Published: January 2018

Abstract
One of the common causes of gas wells productivity loss is attributed to liquid accumulation near the wellbore over the production life of the wells. For gas condensate reservoirs, when the bottomhole pressure falls below the dew point pressure, liquid hydrocarbon drops out of the gas phase, residing in the near wellbore region and causing condensate block. Fracturing fluid also contributes to liquid blockage as only 5 to 30% of fracturing fluids are recovered from the reservoir. For a tight shale formation where the pore sizes are as small as nanometers, capillary pressure is large enough to cause liquid entrapment in the pore body reducing the relative permeability to the gas phase.
A variety of methods such as gas cycling, super critical CO2 injection, solvent injection, and wettability alteration using fluorinated surfactants/polymers have been suggested to treat liquid block or banking (i.e., water and condensate). However, these methods are either not effective or expensive, and do not provide a good return on investment. As capillary pressure depends on surface/interfacial tension (ST/IFT) and the contact angle, a treatment method that combines the effect of ST/IFT reduction and wettability alteration can be applied to lower capillary pressure, thus, to enhance liquid unloading. In addition, reducing the ST between gas and the liquid phase (water/gas condensate) will increase the carrying capacity of the gas phase with respect to the banked liquid phase.
This paper presents a practical laboratory testing procedure developed to screen and recommend cost effective production enhancement formulations to treat liquid blocking. Based on laboratory test results obtained from this testing procedure, a non-fluorinated production enhancement formulation was recommended for a field trial. The recommended formulation was tested at two gas wells: one vertical and one horizontal in North Texas. The proposed formulation was used in the fracturing fluids when the wells were re-fractured. Production data from the two wells have shown a sustained increase in gas production and water recovery rate. The lessons learned here can be used as a guideline to increase production life of existing gas wells and to maximize hydrocarbon (gas and associated condensate) recovery rates.
Economic Evaluation of Wettability Alteration towards the Alleviation of Condensate Blocking
Authors: Ajagbe Oluwatobi , Weiss Maxine , Fahes Mashhad 
Published: January 2018

Abstract
Wettability alteration has been investigated by research groups over the past two decades as a possible answer to the problem of condensate blocking in order to mitigate its effect on productivity loss, however, very limited field applications have been attempted with one case of success and two cases of failure. A volume of experimental and simulation studies have been published, but these papers rarely identify the factors that can contribute towards the success or failure of such a stimulation method. The absence of an actual economic analysis of this method in the literature is also evident. In this study, we build upon the experience of the research team in this area in order to produce a comparative study to be able to identify the conditions under which wettability alteration can be recommended as a suitable approach to address condensate blocking.
Well Productivity Impairment Due to Fines Migration
Authors: You Zhenjiang , Bedrikovetsky Pavel 
Published: January 2018

Abstract
Compressibility needs to be accounted for when estimating productivity decline in closed gas and oil reservoirs, and in closed aquifers. Previous works derived an analytical model and well index for inflow performance accompanied by fines migration and consequent permeability damage for incompressible flow towards well. In the present work, we account for fluid and rock compressibility. The problem with given and constant well production rate is investigated. Mathematical model is developed, which provides well productivity index decline with time. Under this model, the solution of damage-free compressible flow in a closed reservoir is matched with the impedance growth formulae for incompressible flow in the well vicinity. The well production data have been successfully matched by the model; the tuning parameters have the common values. It allows indicating the fines mobilization, migration and straining as possible well impairment mechanism in wells under investigation.
Methodology for Evaluating Drag Reduction Characteristics of Friction Reducer
Authors: Shah S. , Asadi M. , Wheeler R. , Brannon H. , Kakadjian S. , Ainley B. , Chen Y. , McElfresh P. , Ghalambor A. , Kaufman P. , Archacki D. 
Published: January 2018

Abstract
Friction reducers have been an integral part of the oil and gas industry for many years. They possess very unique properties of reducing friction pressure associated with the flow of fluid in tubulars. Friction pressure loss or hydraulic characteristics of friction reducers depend greatly on how they are tested and evaluated in the laboratory. Today, there is no standard procedure for their evaluation. American Petroleum Institute (API) oversees the development and publication of industry standard practices for various fluids and materials. Recognizing the need for a standard testing procedure for friction reducers, a Committee made up of members from industry and academia was formed and charged to develop a document outlining the standard procedure.
Round-robin tests were conducted by four industry organizations and one academic institution, employing their in-house flow loops and were requested to report the results. Tests were to conduct friction pressure measurements of friction reducers, and to develop and deliver to the industry a standard procedure and method to measure and analyze friction reducers data in straight pipes. The test fluids chosen were two friction reducers: one anionic and the other cationic. Water data were also gathered as base line. Same fluid samples were submitted to all laboratories. The calibration procedure and fluid testing procedure was developed and distributed to all involved in fluid testing. The analysis for data reduction and for reporting results was also developed and distributed to all.
It was found that the calibration procedure was more critical than originally thought. The determination of internal diameter of the circular tube is the most important parameter that influences the friction pressure loss results greatly. In this paper, the details of various flow loops, calibration procedure, data analysis procedure, and results obtained with water as base line and two friction reducers are presented and discussed. A standard procedure for testing and evaluating friction reducers for their friction loss properties is outlined.
Following this standard procedure and carefully performing the testing with friction reducers will yield very similar results among various laboratories in the industry. This will make it easy when comparing the performance of friction reducers for their friction loss properties from different organizations.
Comparative Study on the Performance of Different Stand-Alone Sand Control Screens in Thermal Wells
Authors: Fattahpour V. , Mahmoudi M. , Wang C. , Kotb O. , Roostaei M. , Nouri A. , Fermaniuk B. , Sauve A. , Sutton C. 
Published: January 2018

Abstract
Stand-alone sand screen (SAS) is proven to be effective for sand control in unconsolidated sands in thermal wells. The characteristic design parameter to specify SAS is the aperture size, while the Open to Flow Area (OFA) is chosen to balance between the mechanical integrity of the screen, the completion cost, and the plugging risk. The objective of this study is to compare the performance of common SAS types for a certain geological condition.
A series of three-phase large-scale sand retention tests (SRTs) is performed on slotted liner, wire-wrapped screen, and punched screen coupons. The tests are performed using two common representative PSDs of the McMurray Formation. The test matrix includes the common aperture sizes and OFA for each screen and PSD based on the current best practices in the industry. The test procedure is designed to mimic the near wellbore flow velocities, with three-phase flow ranging from 0%-100% water cut and produced gas-oil ratio ranging from 0-277 scf/bbl. The gas flow was supposed to simulate the steam breakthrough incidents. Live measurements are obtained of the sanding amount and pressure drops along the sand-pack and across the screen. Screen plugging is assessed after the completion of each test.
The sanding and flow performance are shown to be a function of the aperture size, PSD, near-wellbore flow velocities, and the water cut. In low fluid flow rates, all the screen types show minimal pressure drops and perform similarly. As near-wellbore velocities increase or gas flow occurs, pressure drops show a significant increase for all devices. Results show OFA, aperture size, and screen type affect the pressure drop and sanding. In all cases, the produced sand in three-phase flow is the determining design parameter for the upper-bound acceptable aperture. The gas flow is observed to accompany large amounts of sanding for larger aperture sizes. Further, test results indicate high pressure drops for three-phase flow conditions. Test results reveal the complexity of the interaction between different design parameters, which affect the sand and flow performance, hence, necessitating an SRT test for each specific case.
This paper presents the results of physical model testing of different standalone screens in terms of flow performance and sand control. This will help to identify the main factors that influence the performance of each specific screen type and develop the rationale for the screen type selection in new developments.
Improving Wormholing Efficiency in Carbonates with a Novel System Based on Hydrochloric Acid
Authors: Daeffler Christopher S. , del Valle Julia Fernandez , Kariampally Jacob , Elkhoury Jean E. , Max Nikolaev , Panga Mohan 
Published: January 2018

Abstract
This paper presents a single-phase alternative to widely used emulsified acid systems. The performance of the new single-phase acid was evaluated for both fracturing and matrix operations and benchmarked against hydrochloric acid and emulsified acid. Wormhole experiments were performed in Indiana limestone cores up to 300°F. The rate of wormhole propagation was used a measure to compare the performance of the acid systems. Diffusion constants were measured with a rotating disk experiment (RDE) at different temperatures. Laboratory measurements characterized the viscosity and friction pressure of each of the acid systems. Two single-phase retarded acid concepts were evaluated. In wormhole experiments with Indiana limestone, the best single-phase retarded acid possesses lower pore volume to breakthrough (PVBT) than unmodified HCl across all injection rates. The PVBT are substantially decreased for the single-phase retarded acid at low injection rates, meaning that when HCl enters the conical wormhole regime, the single-phase retarded acid is still efficiently forming dominant wormholes. At many injection rates, the single-phase retarded acid possesses similar PVBT to emulsified acid. These observations are confirmed up to 300°F. Diffusion coefficients obtained from the RDE are up to 10 times lower for the single-phase retarded acid at 220°F. Friction reducers hydrate quickly and show low friction pressures in the single-phase retarded acid. The new single-phase system matches the performance of emulsified acids while eliminating issues that confront them.
Salt Precipitation in the Near Well Bore Region of Gas Wells
Authors: Egberts P. J. , Nair R. , Twerda A. 
Published: January 2018

Abstract
A numerical model was created to predict timing and location of salt precipitation near the well bore region of mature gas wells. The model provides quantitative insight into the relevant reservoir and well properties that govern salt precipitation and its remediation. The model is used to predict the well's gas production and improve mitigation strategies.
The numerical model has been developed using DumuX, a simulator developed by the University of Stuttgart. The model has been extended to incorporate several additional features essential to model salt precipitation and dissolution.
A sensitivity study has been conducted to evaluate the impact of varying parameters such as initial liquid saturation, permeability, salinity, well pressure and drawdown on the model. Production loss mitigation strategies used can differ depending on the location and timescales of precipitation.
A study of the parameters controlling the productivity of wells plagued by salt precipitation shows scope for improving reservoir management strategies which can delay the onset of salt clogging thereby improving gas production.
Novel Chelation Opens the Door for Redeployment of Sea Water Based Fracturing Fluids in High Temperature Wells.
Authors: Gupta D. V. , Carman Paul S. , Nguyen Susan 
Published: January 2018

Abstract
Exploration for unconventional reservoirs has begun in various countries in the Middle East. Widely recognized as the bastion of conventional crude oil and gas production, the area's exploration for natural resources –– in particular unconventional resources –– is in its infancy. The lack of fresh water may derail some of the exploration and production of unconventional resources in the Middle East. One of the solutions is to use the abundant availability of nearby sea water for fracturing treatments.
This paper will discuss the applicability of sea water for fracturing fluids for without the need for separate treatment of the water. Rheological data with synthetic sea water as well as source sea water from Saudi Arabia, identification of any potential precipitation and remediation and compatibility with produced water and proppant pack conductivity data, of applicable fluids to show the effectiveness of the systems to the high temperatures of the reservoirs in the kingdom, 325°F will also be presented.
The concept of using seawater as a base fluid is not new. Because of the problems associated with substituting seawater for freshwater in polymer-based fracturing fluids, many operators are apprehensive about using seawater for fracturing. There have been noted attempts to mix polymer-based fluids on the fly with seawater, but treatment results have varied widely. Seawater contains dissolved inorganic salts, adversely affecting hydration and viscosity development of polymer-based fluids. High content of calcium and magnesium in seawater can reduce viscosity. These salts also buffer and strongly influence pH control and may inhibit or deactivate certain gel breakers. To gel effectively, polymer fluids need a specific mixing environment with distinct pH windows. Borate crosslinking normally requires a high pH. Rheology and breaker profiles will be shown that provide the desired properties and regain conductivity to establish the non-damaging clean-up of a properly designed fluid.
The technology presented uses chemical chelation of the problem ions in the sea water, resulting in the fracturing fluids with enhanced fluid and proppant pack properties, including thermal stability, retained fracture conductivity, pH buffering capacity, scale inhibition and fluid loss control. Further, the addition of the novel additives to the fluid does not interfere with the crosslink delay time and does not complicate the preparation of the fluid. The technology discussed eliminates the need for traditional water treatment and nano-filtration of sea water and associated disposal issues.
Tunu: From Lab to Field Application with a New Hybrid Inorganic-Organic Sand Consolidation Fluid as Primary Treatment on Shallow Reservoirs
Authors: Andrieu J. , Kutzky B. , Schackmann B. T. , Mahardhini A. , Abidiy I. , Poitrenaud H. M. 
Published: January 2018

Abstract
Tunu field, which is located in Mahakam area, consists of sandstone reservoir. Due to the maturity of the field, producing layer has moved from the deep zone, which has consolidated sand, into shallow zone, which has unconsolidated sand. Hydrocarbon production from shallow zone is unmanageable without having primary sand control downhole.
Here, we present a new type of sand consolidation composite (or hybrid) low-viscous binding material, based on combination of both inorganic and organic components. After describing the properties of this material, like low viscosity and strong adhesion to sand surface, we introduce the models used in the laboratory to stay as close as possible to the injection parameters on the field. We present the results of consolidation and regained permeabilities obtained in the laboratory with this binder on several substrates (loose sand and sand stone cores) with various porosities. The formulation was tested with success on samples ranging from several darcys down to 80 millidarcys. It is also noteworthy that samples display strong consolidation after extensive brine-based overflush.
Then, this paper discusses the results obtained during eight field trials divided into three successive campaigns. The volume of water-based overflush was identified as the main parameter to find the right balance between consolidation strength without sand production and expected productivity. We achieved improvement of the formulation as well as learning curve from each campaign. After first campaign with 6 pore volumes overflush, three wells out of five produced sand free. During second campaign (1.5 pore volume overflush), two wells were treated and able to produce sand free with average gas rate 1 MMscfd (million standard cubic feet per day), after productivity impairment was solved. The trial on one well in a third campaign with 3 pore volumes overflush was successful, with the well producing sand free with average gas rate 0.8 MMscfd.
Mechanisms of Perforation-Induced Damage in Carbonates and the Effect on Injection Flow Performance
Authors: Seagraves A. N. , Smart M. E. , Ziauddin M. E. 
Published: January 2018

Abstract
Fluid diversion in heterogeneous carbonate formations is critical to the design of successful stimulation treatments. In cased andperforated wells, microstructural damage around the perforated tunnels represents a significant challenge for the analysis of flow distribution along the wellbore. While this damaged or"crushed" zone has been a subject of numerous studies involving sandstones, the specific mechanisms of perforation damage in carbonates and theeffect on flow efficiency are not well understood. We examine the carbonate crushed zone at a fundamental level by interpreting the results of flow experiments on perforated cores using direct observation and analysis of the crushed zone at the porescale.
Injectivity index was recorded in Indiana limestone (IL) cores perforated using a gas-filled wellbore, an approach that suppresses wellbore dynamics and produces worst-case damage conditions. After the flow test, continuum modelsof the perforated coreswere constructed fromcomputerized tomography (CT) scans and used to calculate core flow efficiency (CFE) andaverage crushed zone permeability. Novel image analysis algorithms extracted the radial variation of pore-scale quantities across the crushed zone from high-resolution scans of thin sections at multiple axial locations along the tunnel. A correlation wasthen developed which estimates the radial variation of permeability in the near-tunnel region from each thin section. The permeability model is calibrated using analytical solutions that connect the crushed zone and virgin rock permeability profiles to experimental measurements made in the core test. The calibration approach makes use of a new approximate analytical solution for the flow field around a perforation with nonuniform tunnel geometry and crushed zone damage.
In the flow experiments, we observe a persistent drop in CFE for multiple charge types and test fluids as the initial core permeability is increased over two orders of magnitude. This is found to coincide with a decreasing ratio of average crushed-zone to virgin-rock permeability. Thin section analysis reveals that crushed zone damage is dominated by pore compaction near the tunnel edge, which has a characteristic signature in terms of the radial variation of porosity and pore-perimeter to surface-area ratio. Analysis of the spatial distribution of permeability suggests that flow efficiency is controlled by a low-porosity zone near the tunnel edge in which the damage is dominated by porecompaction.