bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of H2S Partial Pressures and Fugacities in Flowing Streams for a More Accurate Assessment of Integrity Threat in Sour Systems
Authors: Harper Christopher , Taghiyev Kanan , Wilkie Peter , Hall Douglas 
Published: April 2016

Abstract
An Excel-based tool was developed that utilizes cubic equation of state (EOS) and thermodynamic electrolyte chemistry modelling. The software enables operators to assess sour production streams from a reservoir, through production tubing, pipelines and facilities to an export pipeline within a range of temperature and pressure conditions. The tool enables quick and accurate sour-production- stream assessment, improving the operator's understanding of the H2S- related integrity risks to ensure safe and stable production. The tool is designed to support materials of construction suitability reviews and provide input to optimize scavenger applications, using the most at-risk components and/ or locations in the system to determine if wells and facilities are safe to operate under current conditions.
This development represents a unique combination of functionality because it combines three elements to derive accurate partition coefficients across a range of operational conditions and gas/liquid compositions: thermodynamic modelling of water chemistry; equation-of-state hydrocarbon modelling; and the basic physical principles at work in production streams.
The approach is employed to assess the integrity risk posed to system components on Chevrons' Alba field in the North Sea. At the time of the modelling, the asset team planned to bullhead three production wells with base oil because of the significant well integrity concerns resulting from high H2S levels. The ability to quickly determine accurate partial pressure and sulphide partitioning profiles for the three production wells ultimately led to the wells remaining open, and saving the operator from deferring in excess of 3,000 bbl/day of oil production from the at-risk wells.
The modelling results were confirmed by a third-party analysis of sulphide concentrations in three phases in the test separator, indicating that the calculated total sulphide per-unit-volume in the system was correct, and the partial-pressure and three-phase concentration profiles for each well were also correct.
The tool was developed so that non chemists, field personnel, engineers and any other relevant stakeholders can make their own integrity assessments.
Nano-Laminated Alloys for Improved Return on Oilfield Assets
Authors: Paz Orlando , Lomasney Christina , Chaloner-Gill Benjamin , Lomasney Samuel , Yamali Nampetch , Casioppo Daniel , Haley Bart , Hussain Syed M 
Published: April 2016

ABSTRACT
Nano-laminated metallic claddings is an emerging technology that is being used to generate products with material property combinations heretofore not possible. Through a patented electrochemical controlled deposition process, Modumetal produces precisely defined configurations of layered metal alloys that can be applied to a variety of substrates or as near net shape parts. The deposition process can be controlled to produce nano-scale layers with unique interfacial properties resulting in corrosion resistance, elastic modulus, strength, hardness, and fracture toughness combinations uniquely different from conventional material processing.
Oil and gas equipment is constantly exposed to corrosive elements that threaten asset longevity and productivity. Corrosion and wear of equipment such as tubulars, downhole artificial lift systems and pumps, leads to production decline over time and ultimately to expensive repairs and operational downtime, all of which negatively impact companies' bottom lines. Until now, the most common fixes to combat pipeline corrosion required a sacrifice of either performance or cost. On one hand, more corrosion-resistant equipment coated with expensive materials like tungsten carbide coatings or high nickel containing steels can be installed at considerable cost. Alternatively, lower-performance materials like carbon steel or organic coatings can be applied, with the understanding that more frequent replacements will be needed. This paper presents a novel class of materials, called nano-laminated alloys that are based on the same conventional materials used today in galvanizing or metal coatings, but configured into nano-laminated structures that deliver significantly higher performance at a price that is competitive with conventional metals and coatings.
Calling on data from field tests carried out in collaboration with Chevron in various onshore fields in the Mid-Continent Region, this paper illustrates how nano-laminated alloys achieve higher performance than traditional alloys at comparable costs. The presentation will include a performance and economics data-rich comparison of nano-laminated alloy coating performance and cost with conventional steels and coatings.
Two case studies are presented for downhole tubulars and downhole plunger lift systems. These case studies represent the conclusions of actual field trials. Results of these case studies review the up-front cost of the nano-laminated product installation, performance comparison both in lab and field trials and return on investment calculation for the nano-laminated products in the field environment.
Corrosion- and Erosion-Resistant Metal Matrix Nanocomposite Coatings for the Oil and Gas Industry
Authors: Monteiro Othon R. , Murugesan Sankaran , Suresh Radhika , Khabashesku Valery N. 
Published: April 2016

Abstract
Ni-based metal-matrix nanocomposite (MMnC) coatings with diamond particles offer an interesting alternative to hard chromium and to conventional electroless Ni coatings, which are used in many components in the Oil and Gas industry. The properties of most value of electroless Ni for the industry are the thickness uniformity, excellent corrosion resistance and abrasion/erosion resistance. In this article we demonstrated that Ni-based MMnCs outperform conventional electroless Ni and hard chromium. Therefore, components manufactured with inexpensive base materials coated with MMnCs should have longer service life, which translates into lower operating cost. In this article we report hardness, erosion and corrosion tests of Ni-based MMnCs, and compare those results with commercially used Ni-B coatings. Ni-B coatings are usually favored over Ni-P in the applications experiencing erosive wear; however they are less resistant than Ni-P to corrosion attack. The results presented here demonstrate that Ni-based MMnC coatings outperform conventional electroless Ni-P and Ni-B, and are expected to outperform hard chromium. The novelty of the Ni-diamond MMnC coatings is in the ability to provide simultaneous corrosion and erosion protection for oil and gas tools and components.
Inhibition Performance of Mild Steel Corrosion in the Presence of Co2, HAc and MEG
Authors: Ikeh Lesor , Enyi G. C , Nasr G. G 
Published: April 2016

Abstract
The formation of hydrate and scale deposition is a major challenge in the petroleum industry. To avoid corrosion and hydrate formation, monoethylene glycol (MEG) is been utilized in the pipeline as an antifreeze and anticorrosion agent. It has been observed that the MEG has to be separated from acetic acid (HAc) and acid gases which enhance corrosion of mild steel in the oilfield environments. HAc and MEG also has an adverse effect of lowering the solubility of mineral salts and causing a higher risk of scale formation.
In this study, the mitigation of corrosion of mild steel in the presence of HAc and MEG in CO2 saturated environment were investigated at 25°C and 80°C using 3.5% wt. NaCl solution in a semi-circulated loop setup. Weight loss and electrochemical measurements using linear polarization resistance (LPR) were used to evaluate the efficiencies of two corrosion inhibitor based chemicals (the phosphate ester and the Olei imidazoline salt) at different concentrations. Test results obtained show that the corrosion inhibitors are found to be very effective in reducing the corrosion of mild steel in the presence of HAc and MEG at different conditions tested. At 25°C and 10ppm of inhibitors, the average corrosion rate decreases from 0.22mm/yr to 0.11mm/yr and from 0.21mm/yr to 0.05mm/yr with 50ppm of both inhibitors. At 80°C, the corrosion rate decreased from 0.20mm/yr to 0.07mm/yr with 10ppm of inhibitors, and from 0.19mm/yr to 0.03mm/yr with 50ppm of inhibitors A and B. The decreased in corrosion rate with the inhibitors shows that the active sites of the steel surface are prevented by the inhibitors absorption which in turn inhibits the absorption of the HAc and CO2 on the mild steel surface.
Review of Typical Challenges in Establishing the Integrity Status of Subsea Pipelines: A Case History
Authors: Marinou Eugenia , de Souza Valdir , Munday Martin 
Published: April 2016

Abstract
An assessment was performed in order to understand better the integrity status of a carbon steel N. Sea pipeline which transports hydrocarbon fluids with a high CO2 content (5.7-6.2 mole%) and H2S (ca. 600 ppm), receiving continuous injection of a combined scale/corrosion inhibitor. The review was triggered by high corrosion rates, with readings up to 0.9 mmpy measured by intrusive topsides corrosion probes coupled with low confidence in the applied corrosion mitigation and management controls.
The assessment concentrated on the following parameters: flow velocities and wall shear stress rates using field production data; calculation of uninhibited corrosion rates using NORSOK M506; estimation of uninhibited wall loss; review and trending of available corrosion monitoring data; corrosion inhibitor application; review of chemical qualification testing; compliance of inhibitor injection with designated target rate and correlation with the corrosion probe readings; and review of historical production data to ensure that the velocities / shear stress values used for chemical testing were comparable to the flowing regime in place.
The assessment identified that numerous performance metrics were either not in place or not followed up correctly, e.g., inhibitor selection, application, field optimisation and interaction with other chemicals, corrosion monitoring and correlation with inspection data, impact of sand production on inhibitor availability and efficiency, management of change procedures, and issues around internal and third-party communication and interfaces. The latter are of particular significance in operating environments where there are multiple entities involved in operating a system – especially integrity management.
This paper presents a summary of the identified root causes for the observed metal loss spanning a review period of two years; highlights elements of ineffective integrity management practice; and provides a list of pertinent parameters that ought to be assessed so as to obtain a pragmatic understanding of a pipeline's condition, including amendment of applied mitigation measures.
Corrosion in MEG Injection Lines in the Presence of O2 - Experiments and Modelling
Authors: Palencsár Attila , Amri Jamel , Seiersten Marion , Omgba Christian 
Published: April 2016

Abstract
Membrane nitrogen with up to 5 vol% O2 is widely used as blanket gas in the petroleum industry, including as blanket gas on rich and lean MEG tanks. The presence of oxygen, even in low concentrations raises questions with regard to potential corrosion damage in the carbon steel injection line as well as consumption of the dissolved oxygen and residual levels upon entering the pipeline. These aspects constitute the scope of this work.
A series of experiments were carried out with carbon steel specimens exposed to environments similar to service conditions encountered in MEG injection lines, including temperatures between 5 and 65 °C and various levels of alkalinity/acidity. The corrosion processes were monitored by electrochemical measurements. These allowed the empirical determination of a number of parameters governing the corrosion and oxygen consumption reactions. Based on the experimental findings and literature data, a comprehensive finite element model was developed and used for tracking the corrosion rate along an injection line of Lean MEG in the presence of dissolved oxygen under acidic, near-neutral and alkaline conditions. Consumption of dissolved oxygen along the injection line was accounted for via the bulk oxygenation of ferrous iron released during the corrosion process.
The experimental results revealed that the contribution of electrochemical oxygen reduction to the corrosion rates is minute; the oxygen is rather consumed in reaction with ferrous ions in the bulk. The model reproduced the measured corrosion rates well and made it possible to study the consumption of dissolved oxygen as a function of acidity/alkalinity, temperature and residence time. The results showed, for example, that the dissolved oxygen may not get completely depleted in the injection line at high flow rates.
The results presented here, as well as the approach used by the authors can be a useful aid in assessing the risk of corrosion damage in glycol injection lines and pipelines, associated with the presence of oxygen in the lean MEG.
Modulating Hydrofluoric Acid Reactivity and Corrosion Effects of Acidizing Fluids for Different Metallurgies: Titanium, Steel, and Chrome Tubing
Authors: Reyes Garcia Enrique A. , Smith Alyssa LaBlanc , Beuterbaugh Aaron M. 
Published: April 2016

Abstract
Because of increased activity in deepwater and high-pressure/high-temperature (HP/HT) environments, the safe operation of corrosion resistant alloys (CRAs) of different types is important. Reservoirs can be subjected to different flow impairment mechanisms that can require the use of acidizing fluids. Titanium (Ti) alloys can be present in subsea completions and in the casing of geothermal wells, as these are able to withstand ultrahigh-pressure and temperature and corrosive conditions. The need to remove clays or silica fines obstructing fluid flow in deepwater wells and enhanced geothermal systems can pose difficulties to operators if the use of hydrofluoric (HF) acid fluids is necessary. At present, there is no HF-acid fluid compatible with Ti alloys because any contact of HF acid with a Ti alloy will result in its corrosion and dissolution. In this paper, the development of a corrosion inhibitor solution to protect Ti alloys against HF-acid attack is presented.
Different metallurgical specimens (Ti, chrome, carbon (low or high) steel) were exposed to an HF-acid fluid based on a sodium-containing aminopolycarboxylic acid (APCA-Na) chelating agent. The Ti specimens (Grade-1 and -29) underwent delamination or blistering at low temperature (140–250°F), depending on the inhibitor and type of alloy present. An HF acid modulating agent was used to help minimize corrosion and the dissolution of Ti. The steel alloys were tested at 260°F with the HF-acid/APCA-Na fluid, displaying minimal mass loss resulting from corrosion. The main effect observed was surface pitting. While suitable inhibitors exist against HF acid for CRA tubing, there are still limitations, such as in mixtures containing acetic acid, which lead to pitting, complicating the inhibitory process. Temperatures in excess of 100°C limit the exposure time to an HFacid fluid, further convoluting the corrosion protection and inhibitor optimization for multiple alloys. Use of the described HF-acid fluid containing APCA-Na in conjunction with the set of HF acid anti-corrosion agents can facilitate acidizing in wells whose completions contain HF-acid-sensitive alloys, including Ti.
Cost-Conscious Corrosion Control
Authors: Cavallaro Brandon , Clayton Richard , Campos Mario 
Published: April 2016

Abstract
From the summer of 2014 to the summer of 2015, global oil prices declined by nearly 60%. The initial impact of this decline on unconventional assets was to reduce or stop drilling and completion activity, but the lower oil price also had a significant impact on cash flow from existing wells. Operators were able to achieve some reduction in operating expenses through contract renegotiations with suppliers, but cash flow margins from sales of oil and gas from production operations were severely impacted. In fields with higher operating expenses due to corrosive environments, the need to manage costs became even more critical. For example, in onshore fields with highly corrosive reservoir fluids, production chemicals can account for more than 40% of monthly operational expenses. Reducing chemical spend can therefore seem like an easy way to reduce lifting costs. However, a reduction in treatment volume can lead to mechanical integrity issues that are more costly to remediate than to prevent, therefore requiring a strategy to balance cost reduction and mechanical integrity preservation.
A cost-conscious corrosion management strategy was developed and implemented for an onshore, sour-bacteria-laden oil from a shale oil development in south Texas. The strategy addressed treatment cost per barrel produced, the effectiveness of chemical formulations, metallurgies of downhole and surface facility components, and the cost of remediation. This full-spectrum corrosion management approach had a positive financial impact across the field.
Key performance indicators were defined and tracked, and a workflow was implemented to manage the large amounts of data from wells in the field. A lifecycle data management system was employed to not only capture failures, but also facilitate root cause analysis. This afforded the opportunity to design-out repeat failure mechanisms, for example by changing downhole metallurgies. This workflow supported the on-time optimization of chemical pumping rates, which reduced operating costs without ceding equipment integrity. This workflow reduced time spent toiling over corrosion management, thus saving on engineering resources.
Despite a challenging economic environment, corrosion management must be maintained in operational budgets. The example of the successful cost-conscious methodology used in the south Texas field shows that even dramatically reduced budgets can still support the safe, environmentally sustainable operation of an oilfield asset.
Probabilistic Reserves Assessment and Evaluation of Sandstone Reservoir in the Anadarko Basin
Authors: Ampomah W. , Balch R. S. , Chen H.-Y. , Gunda D. , Cather M. 
Published: April 2016

Abstract
This paper presents a field scale reservoir evaluation and uncertainty analysis of hydrocarbon reserves estimation for the Upper Morrow B reservoir of the Farnsworth Unit (FWU), Ochiltree County, Texas. The degree of uncertainty in volumetric reserves estimation for hydrocarbon in place is controlled in larger order by the geological complexity of the reservoir and quality of available geologic data.
Morrow B core and thin sections were examined to determine composition, porosity types, depositional environment and diagenetic history. Composition and porosity types determined from XRD and optical microscopy were compared with results from an ELAN analysis. This information together with additional core, well log, borehole image logs, vertical seismic profiles and 3D surface seismic data were used to characterize and subsequently create a fine scale lithofacies based geocellular model (Ampomah et al., 2016b). The reservoir is classified as a highly heterogeneous.
Probability density functions for input uncertain variables were constructed to estimate probabilistic reserves using first order, parametric and Monte Carlo simulation methods. The relative impact of input variables from these methods were compared and analyzed based on geology, petrophyiscs and engineering knowledge from the FWU to ascertain the applicability of these approaches.
The result for each method is presented with expectation curve and log-probability plot elaborating the likelihood of occurrence as P10, P50, P90 and Mean reserves. A P10-to-P90 ratio and a coefficient of variance were used to analyze the total uncertainty of the reserves estimation. Histograms were used to illustrate the sensitivity of input parameter’s contribution towards the overall uncertainty. Statistical mean reserves from the three methodologies were close to the deterministic calculations. Formation thickness and area were the most uncertain variables and have to be topmost priorities to ensure accuracy in reserves estimation for FWU.
The results from this study show that an analytical procedure such as the parametric method which is easily generated within spreadsheets can be used to replace the "black box" Monte Carlo simulation of estimating hydrocarbon reserves in the oil and gas industry.
Forecasting Production of Shale Volatile Oil Reservoirs Using Simple Models
Authors: Makinde Ibukun , Lee W. John 
Published: April 2016

Abstract
Due to the advent of shale reservoirs as important sources of oil and gas production, there has been a critical need for reliable techniques for forecasting production and estimating reserves from these plays. This work presents the results of a study to determine whether simple decline models can be used to forecast production and estimate reserves of both oil and gas in shale volatile oil reservoirs with reasonable accuracy. We found that hybrid models (i.e., one model such as the Duong model for transient flow coupled with a different model, such as the Arps hyperbolic model with an appropriate value of the parameter "b") are appropriate for forecasting oil production and that it is possible to forecast solution gas production with availability of adequate data.
To establish the "truth case" for comparison, we simulated production with four different reservoir fluids using a commercial compositional reservoir simulator. We tested a variety of hybrid and simple DCA models on simulated data (and later on field data) with a work flow that included identifying flow regimes with diagnostic plots for each fluid sample. We analyzed 0.5 to 3 years of production history to estimate model parameters for forecasting future production. Also, we forecasted gas production using a technique similar to one recently presented in the literature.
Lengthy transition periods between transient linear flow and boundary dominated flow (BDF) were observed on the diagnostic plots. This is presumably due to multi-phase flow effects, as this transition period is typically much shorter in single-phase shale reservoirs. As in single-phase flow, the Arps decline model proved to be good for forecasting in the BDF regime. For transient flow, we examined the Duong model (which includes transient linear flow as a special case) and YM-SEPD (modified form of Stretched Exponential Production Decline model). In some cases, we applied the Arps model for both the transition period and BDF regimes (with different b values). We concluded that hybrid DCA models are more appropriate for multi-phase flow analysis than simple DCA models. In most of the cases, the hybrid YM-SEPD and Arps models led to more accurate oil production forecasts than other alternatives. Our analyses of solution gas forecasts indicated that solution gas production forecasting is possible but there is still need for more research in this area.