bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Historic Data to Improve Drilling Efficiency: A Pattern Recognition Method and Trial Results
Authors: Kristjansson Sean D. , Neudfeldt Adam , Lai Stephen W. , Wang Julian , Tremaine Dean 
Published: January 2016

Abstract
Despite recognition by the drilling industry that historic data can be used to inform the efficiency of drilling operations, published research into methods to systematically exploit historic data for this purpose are relatively scarce. In the present paper, we describe a novel method and automated solution that does just this it was developed for land-based wells drilled on the same pad or in similar geologic formations (i.e., offset wells), and it uses machine learning to search the offset data for epochs of highly efficient drilling. Once these epochs are identified, drilling parameter settings including weight on bit (WOB), drill string or drill bit revolutions per minute (RPM), differential pressure (ΔP), and pump rate (total pump output; TPO) settings linked to the highly efficient drilling epochs are extracted from the offset data. These settings then are formation- and depth-aligned to the new well to be drilled, and they are smoothed and displayed on the electronic drilling recorder (EDR) in real-time as "drilling parameter roadmaps." Such roadmaps were created for surface, intermediate, build and lateral sections for two trial wells. Trial results indicated that the average rates of penetration for the trial wells exceeded the average rates of penetration for the offsets by 20.1% and 47.8%, and time to drill the trial wells (i.e., spud to target depth) took 4.3 and 4.1 fewer days compared to the average number of days for the offsets. Per-day cost to operate these rigs was approximately $80, 000 suggesting our solution yielded substantial cost savings.
Friction Load Redistribution for Robust and Cost Efficient Design of Extended Reach and Horizontal Well Completions
Authors: McSpadden A. R. , Trevisan R. 
Published: January 2016

Abstract
In horizontal and extended reach wells where long completions are run into highly deviated or lateral zones, large compression loads arise due to running friction. These loads remain locked in the string when the packer or cement sets. Dissipation of friction during life service due to string vibrations and movements redistributes these friction loads between the wellhead and packer or top of cement. A numerical approach is presented to calculate the redistributed friction load so that an accurate initial tubing load is implemented in the tubular stress analysis. The proposed methodology offers an opportunity for design optimization via accurate prediction of tubing loads when the locked-in friction loads may be a determining factor in the balance between marginal tension limits near surface and marginal compression loads downhole.
The numerical approach is a simple 1D finite element model in which incremental frictional loads are decomposed and redistributed based on relative stiffness of the string uphole and downhole of each local node. Essentially each portion of the string is represented as a series spring. The methodology requires input of the estimated friction load for each incremental element during running from a standard torque-drag analysis.
The results are particularly relevant for ERD, multistage completion and shale-type multizonal lateral wells, where overestimation of in-service compression above the packer or cement may pose considerable design challenges for tubular components including connections. The common assumption to ignore friction in tubing analysis is non-conservative in that it may underestimate friction loads, especially downhole at the packer. However, applying the full slackoff load downhole is also unrealistic and overestimates compression above the packer leading to costly component selection. Results from the numerical model wherein post-dissipation friction loads are redistributed show that only a part of the friction induced compression migrates to the packer. Some of the redistributed friction load results in additional tension at the wellhead. The type of trajectory, kick off depth and deviation angle are important factors for the load redistribution.
The methodology presented in this work provides an approach to calculate the proportion of friction load transferred to the surface compared to the packer or cement top. The redistributed result which divides the running friction load between hanger tension and downhole compression is not always intuitive. This approach is critical for correct modelling of the initial conditions in the tubing stress analysis with significant impact on tubular cost efficiency and fit-for-purpose design and well integrity.
Nanoparticle-Based Drilling Fluids for Minimizing Formation Damage in HP/HT Applications
Authors: Mahmoud Omar , Nasr-El-Din Hisham A. , Vryzas Zisis , Kelessidis Vassilios C. 
Published: January 2016

Abstract
Drilling fluid must fulfill various functions with a great impact on the drilling performance. Drilling fluid invasion can cause formation damage. Good quality mudcakes can prevent such damage. This research focuses on the lab techniques and performance results of testing innovative water-based drilling fluids containing nanoparticles (NPs) for minimizing formation damage at high-pressure/high-temperature (HP/HT) conditions.
A couette type viscometer was used to examine the rheological properties of the drilling fluids tested in this research. Zeta potential measurements were conducted at different temperatures and concentrations to assess their stability and to investigate the role of charge potential. Indiana limestone outcrops were examined as the filter media for both static and dynamic filtration (up to 350°F and 500 psi) using a HP/HT dynamic filter press. The mudcakes were investigated using a computed-tomography (CT) scan, and Scanning Electron Microscopy-Energy Dispersive Spectroscopy (SEM-EDS). Inductively Coupled Plasma-Optical Emission Spectrometry (ICP-OES) was used to measure the concentrations of key ions in the filtrate fluids.
A significant reduction in the filtrate fluid volume was achieved when using ferric oxide NPs (-43% for 0.5 wt%) compared to that of the base fluid. However, adding silica NPs led to an increase in the filtrate volume and mudcake thickness. Increasing the NP concentration resulted in an increase in the fluid loss and mudcake thickness. The mudcakes consisted of two layers, as indicated by the CT scan analysis. 0.5 wt% was found to be the optimal NP concentration, which provides less agglomeration and a reduction in the mudcake permeability by −76.4%. At this concentration, the ICP-OES analysis showed a higher cation dissociation, which promoted the formation of a different clay platelet microstructure. At a higher NP concentration, a new layer of NPs was formed in the mudcake, which adversely affects the mudcake characteristics, as demonstrated by CT scan analysis and SEM-EDS elemental mapping. The rheological measurements indicated a good rheology at different temperatures and NP concentrations. Moreover, the NPs helped to stabilize the viscosity and yield stress at high temperatures (up to 200°F). Aging at 350°F for 16 hours showed that NP-based drilling fluids remain stable with minor changes in rheological properties. The obtained rheological data for various NPs is fitted to the classical drilling fluid rheological models to determine the best fit-model, which can then be applied to an efficient design.
This research provides a comprehensive evaluation of improved water-based drilling fluids, using ferric oxide and silica NPs for HP/HT applications. The examined NPs have the potential to enhance drilling fluid properties, which provides more efficient drilling operations and less formation damage.
Factors Governing the Performance of Multi-Layered Metal-Mesh Screens
Authors: Wu Chu-Hsiang , Sharma Mukul M. , Chanpura Rajesh , Parlar Mehmet , Ayoub Joseph 
Published: January 2016

Abstract
Multi-layered metal-mesh screens (MMSs) are widely used as stand-alone screens for sand control in unconsolidated formations. The nominal rating of such screens is usually based on the specifications of the filter layer. It is often found that screens with the same filter layer nominal rating perform differently. It is shown in this study that the primary reason for this is that the sand retention performance of multi-layered MMSs is a strong function of not only the filter layer but also the protection and the support layers.
This paper presents a systematic study that shows how the overlap between different mesh layers, the alignment of the protection and support layers, and the relative pore size ratio, defined as the ratio of pore size of the protection/support layer to that of the filter layer, have a large impact on the sand retention performance of a MMS. The pore size distribution (PoSD) of multi-layered plain square mesh (PSM) and plain Dutch weave (PDW) screens are calculated using a novel numerical technique. Influences of screen-sintering, coupon-sampling, and screen designs on PoSD of a screen are modeled by varying the layer-overlap, shifting the layer-alignment, and modifying the design of the protection and support layers. The PoSD data is used as an input into a validated analytical model for evaluating sand production of PSM screens in slurry type sand retention tests (SRTs) for screen design optimization.
For PSM screens, the results show that the PoSD of a multi-layered screen can be very different from the PoSD of the filter layer. In general, a decrease in sand production with an increase in layer-overlap is observed; the trend exists irrespective of how mesh layers are aligned. A change in mesh alignment is found to cause a variation in sand production even with the same filter layer pore size and layer-overlap. The nominal rating of the filter layer of a multi-layered PSM screen should be used to estimate sand production only when the pore sizes of the protection and support layers are much larger than the pore size of the filter layer. For PDW screens, layer-overlap is shown to dominate the screen performance by affecting the filter layer pore size. PoSD of a PDW screen is found to be less affected by variations in layer-alignment and relative pore size ratio.
This study clearly shows that layer-overlap, layer-alignment, and relative pore size ratio between mesh layers can have a significant impact on the sand retention performance of a multi-layered MMS. These factors are seldom considered when selecting a screen. As such widely different screen performances can be expected for screens with the same nominal screen rating. Our results have a direct bearing on how MMSs are manufactured, selected, and specified. Increasing the relative pore size ratio appears to be a promising screen-design approach for obtaining consistent screen performance for multi-layered MMSs.
Targeting Enhanced Production through Deep Carbonate Stimulation: Stabilized Acid Emulsions
Authors: Cairns Amy J. , Al-Muntasheri Ghaithan A. , Sayed Mohammed , Fu Liling , Giannelis Emmanuel P. 
Published: January 2016

Abstract
To meet rising global demands for energy, the oil and gas industry continuously strives to develop innovative oilfield technologies. A large portion of the world's oil and gas reserves are trapped in carbonate reservoirs, particularly in the Middle East. Well stimulation treatments for these highly heterogeneous formations have traditionally relied upon the use of strong mineral acids, e.g. hydrochloric acid (HCl). However, fast rock/acid reaction rates and corrosion issues pose a significant challenge to the longevity and practical application of such treatments. Alternative approaches have been proposed to slow down this process, among the most popular being emulsified acids. In this case, the release mechanism of live acid is governed by droplet contact with the surface of the formation in conjunction with suitable downhole conditions (i.e., temperature, pressure, pH). Upon release, the acid proceeds to rapidly react with the carbonate formation thereby unveiling a conductive wormhole network.
This paper presents a systematic experimental study targeting deeper well stimulation using an improved emulsified acid system. The current study demonstrates the success of an emulsion-based system that is stable at elevated temperatures (e.g. up to 300°F/150°C) for a prolonged period of time. To gain a deeper understanding of the dissolution behavior and resultant wormhole morphology, a systematic coreflood study was conducted to identify key parameters that influence the overall performance of the newly developed stabilized emulsified acid. The parameters investigated include: (1) pore pressure, i.e. up to 7,000 psi, (2) flow rate, i.e. up to 5 cm3/min, (3) acid-rock contact time, and (4) fluid treatment composition.
Indeed, the stabilized emulsified acid exhibited superior performance as confirmed from coreflood experiments performed at 3,000 psi and 300°F. In this study, 0.65 PV of fluid was injected into a 12″ core and shut-in for a period of 15h, thus giving the emulsion ample time to break in all cases. Interestingly, a 3-fold enhancement in carbonate permeability was observed for the stabilized emulsified acid as compared to the conventional acid-in-diesel emulsion.
Moreover, the CT images for the treated core samples show that the stabilized acid system had less face dissolution and had the desired wormhole characteristics, i.e. narrow and directional propagation behavior with deeper penetration into the core sample. Finally, additives were defined and used to improve the performance of emulsified acid systems at high temperature, which in turn improved the acid penetration rate and wormhole propagation.
Fines Mobilisation by Low-Salinity Water Injection: 3-Point-Pressure Tests
Authors: Bhattacharya S. S. , Paitaridis J. , Pedler A. , Badalyan A. , Yang Y. , Carageorgos T. , Bedrikovetsky P. , Warren D. , Lemon N. 
Published: January 2016

Abstract
Fines mobilisation and straining by changing the ionic strength of the reservoir water results in a significant permeability reduction, and is a well known mechanism of formation damage. The phenomenon occurs during drilling and completion, where the fluid invasion with fines lifting may cause significant productivity damage. The paper experimentally investigates the permeability damage of natural sandstone rocks in order to select ionic compositions for drilling and completion fluids.
Two sandstone rock cores from the same production well from the Birkhead Formation in the area of underlying Patchawarra Trough (Eromanga Basin, Australia) were chosen to study formation damage during successively decreasing (piece-wise) the ionic strength of injected fluid using a three point pressure measurement method along the core. Effluent particle concentration and electrolytic conductivity were measured for effluent streams. It was observed that formation damage in the studied rock cores after their contact with low-ionic strength fluid is caused by fines mobilisation, their migration in the porous medium and straining in thin pores. Each coreflood is characterised by decreased rock permeability with stabilisation times significantly exceeding one pore volume, suggesting that mobilised particle’s drift velocity is significantly lower than that for a carrier fluid. The electrolytic conductivity profile shows that the fluid front in porous medium is not piston-like, rather diffusion driven, suggesting that there is an additional reason behind long permeability stabilisation time – a delayed contact of rock with low ionic strength fluid.
A Simulation Study on Mitigation of Water Hardness Damages in Fracturing Fluids
Authors: Bao Chen , Han Jiahang , Li Leiming , Qiao Changhe , Sun Hong , Sookprasong Andy 
Published: January 2016

Abstract
Preparing fracturing fluids from low-quality water such as hard water is an environmentally friendly option in field operations and is therefore highly desirable. However, fluid viscosity can be significantly reduced when mixed in hard water rather than fresh water, requiring the addition of stabilizers to mitigate the hardness damages. Although some stabilizers have already been identified in experiments, systematic studies to help optimize fracturing fluids based on chemical compositions of produced water and the chemical properties of polymer and stabilizers are still needed. In this work, we use reactive transport model to understand how stabilizers mitigate water hardness damages in fracturing fluids prepared with hard water.
We studied a system where several stabilizers have been proved to mitigate hard water damages to metal-crosslinked derivatized polysaccharide (MCDP) fracturing fluids. Reversible chemical reactions between MCDP and cations lead to polysaccharide salts precipitations that compromised the fluid viscosity. Stabilizers are chemically active substances that preferentially react with cations, especially divalent cations so they can protect MCDP from precipitating. To benchmark this system, reactive transport models were set up to explicitly consider the fluid viscosity alterations caused by the chemical reactions among polymers, cations and stabilizers in flow conditions relevant to regain conductivity tests (RCT). The numerical simulator was developed based on Crunchflow with the viscosity as a function of polymer and cation concentration.
The viscosity profiles of a number of rheology experiments were first matched as model calibrations. The effects of different stabilizers were then determined by parametric comparison of different cases. The model was then verified by matching it to the rheology of fracturing fluids prepared in experiments by mixing MCDP and stabilizers with hard water samples. Simulation results show that the type of stabilizers and cations in the hard water has a significant impact on the viscosity alteration for the same level of MCDP added. Stabilizers mitigate the hardness damages either instantly or in a latent manner depending on their intrinsic reaction kinetics with cations.
This work demonstrates that reactive transport model could be used to help design and optimize fracturing fluids according to laboratory tests and produced water compositions. It is believed to be the first time that reactive transport modeling is used to study the complicated interactions among polymers, cations and stabilizers in fracturing fluids.
Chlorophyll: A Naturally Occurring Green Polymer Breaker for Hydraulic Fracturing
Authors: Dhulipala Prasad D. , Armstrong Charles D. 
Published: January 2016

Abstract
Porphyrins produce free radicals in alkaline conditions. Chlorophyll is an Mg++-containing tetrapyrrole formed from 4 porphyrin rings and is part of the photosynthetic reactions in plants (Arnoff, 1966). It catalyzes carbohydrate synthesis in the presence of light and carbon dioxide. Using the molecular structure of chlorophyll, we hypothesized that chlorophyll functions as a breaker by producing hydrogen peroxide or other radicals in the alkaline environments of borate-fracturing fluids.
This study evaluated leaf extract containing chlorophyll as a potential polymer breaker. Leaves contain 1.5 to 2.5% of chlorophyll in their leaves and the ratio of chlorophyll a to b is 2.5-3.5 depending on growth conditions and light exposure (Willstaetter and Stoll, 1928). Chlorophyll samples were obtained from various plants and commercial sources, and their efficacy as polymer breakers was studied against guar-based fracturing fluids. The average molecular weight of treated fluids was measured by changes in intrinsic viscosity. Additionally, regain conductivity measurements were carried out. Results showed an 84% regain conductivity in proppant packs. Chlorophyll-treated cross-linked fluids showed a more than 90% viscosity reduction, without any viscosity rebound on cooling. The chlorophyll worked efficiently up to 250°F but the optimum temperatures are at 175 to 200°F with narrow pH range of 9.5 to 10. The chlorophyll-treated fluids also showed a reduction of molecular weights of the linear guar polymer from 1,472,000 to 138,000 as measured by the intrinsic viscosity method. The studies support the hypothesis that chlorophyll can function as a polymer breaker for alkaline fracturing fluids.
First Successful Application of Temporary Gel Plug Replacing Calcium Carbonate Chips to Isolate Depleted Reservoir, Case Study from Saudi Arabia Gas Field
Authors: Ziad Abdullah Bin , Gromakovskii Dmitrii , Al-Sagr Abdulaziz , Al-Driweesh Saad 
Published: January 2016

Abstract
Deposition of scale is one of the most common and serious problems seen in HPHT gas wells in Saudi Arabia. A Coiled Tubing intervention to mechanically clean out the scale deposits from the production tubing and liner has been the most common approach to address the problem. Since reservoirs get depleted with time, lost circulation becomes a severe issue. In wells that cannot support a column of fluid due to low reservoir pressure, the reservoir (open-hole, perforations) needs to be isolated to regain full circulation that allows to lift the milled scale to surface. A conventional procedure to isolate the reservoir is to use Calcium Carbonate chips until leakoff into the formation is controlled. This approach is successful in isolating, but presents significant disadvantages regarding the amount of chips needed to successfully isolate, and, more importantly, the cleanout of this solid material once the de-scaling operation has been concluded.
This paper discusses the first successful reservoir isolation using exclusively a temporary gel plug that allowed safe and successful execution of a mechanical de-scaling operation without using CaCO3 chips. Temporary gel plugs are normally polymers dispersed in water that can be either crosslinked or non-crosslinked. Well variables like well configuration, bottom-hole temperature; desired plug stability as well as operational variables such as pump rates and placement times are used in selection and design of the type of plug to be used. In the specific case of the reservoir isolation needed to perform a de-scaling operation, a delayed crosslinked polymer gel plug that generates over time a firm and highly viscous gel was used. This temporary gel plug was placed by bullheading two batches of this system down to the top of the openhole wellbore section and allowing an 8 hours setting time to crosslink and isolate the low pressure zone where fluid will leakoff thus generating a lost circulation. The reservoir isolation was confirmed by positive pressure testing the plug. The specific temporary gel plug was designed to be readily soluble in acid in order to restore communication with the reservoir and resume gas production without a need for any additional cleanout runs with Coiled Tubing and use of large fluid volumes.