bluuebunny/crossref_metadata_2025 huggingface dataset:
Forced and Spontaneous Imbibition Experiments for Quantifying Surfactant Efficiency in Tight Shales
Authors: Roychaudhuri Basabdatta , Xu Junyi , Tsotsis Theodore T. , Jessen Kristian
Published: June 2014

Surfactants have been used extensively in well completion practices and have been shown to favorably alter the wettability of a formation from highly water-wet to intermediate-wet, resulting in increased water recovery and in a reduction of water blockage around the wellbore. Spontaneous imbibition and contact angle measurements are the most popular methods for studying the efficacy of a given surfactant. Forced imbibition experiments on fractured cores under confining pressure provide a more realistic representation of the actual formation settings, but have not been used extensively to measure the effect of surfactant solutions. They are commonly avoided due to their additional experimental complexity when compared to their spontaneous imbibition counterparts. The forced imbibition data reveal information about the porosity and provide an estimate of fluid flow values under different confining pressures of the micro-fracture network and the core matrix from the imbibition rate. Compined with the pure water invasion rates, forced imbibition experiments with surfactants reveal potential impacts that the surfactant may have on a given formation.

In this work, 1 in by 1 in shale core plugs have been used to study the efficacy of a surfactant towards increased load recovery. Each core plug undergoes two forced imbibition experiments lasting 24 hr in succession: One experiment is carried out with pure water while the second experiment employs a surfactant solution. The permeability and porosity of the samples are measured before each experiment to be able to account for any changes to the cores as a result of the forced imbibition experiments. During forced imbibition, the fluid is injected at a pressure of 3500 psi. We observe an increase in water recovery of approximately 60% for a low (ppm-level) concentration of a surfactant solution. We argue that spontaneous and forced imbibition experiments provide more realistic observations of the capillary pressure effects at play than do contact angle measurements, and that they should be used together for direct quantification of surfactant efficacy in these tight porous materials under realistic reservoir conditions.
Unconventional Oil from California's Monterey Formation – Exploitation Results
Authors: Burzlaff Alan A. , Brewster David P.
Published: June 2014

There is a heightened interest in the exploitation of the California Monterey Formation as a source of unconventional oil reserves. Some publications have categorized the Monterey not only as an unconventional reservoir, but as an oil resource play similar to the Bakken and Niobrara. Over the past five years, major and independent oil companies have invested millions of dollars gathering 3D seismic data and have drilled hundreds of horizontal and vertical wells, both hydraulically fractured and acidized, to find the location of and relevant technologies for producing significant quantities of oil from intervals within the Monterey shale. This paper presents a five-year look back of the production results for the renewed industry drilling campaign targeting unconventional oil reservoirs in the Monterey. Relying on public records, this paper presents statistical information on the number of wells, Initial Productivity (IP), gas-oil ratio, water cut, and Expected Ultimate Recovery (EUR) for the onshore Monterey drilling activity during 2009–13 in the San Joaquin Valley of central California. Results show wells that are highly variable in terms of oil IP and gas-oil ratios. Key fields include the Rose, North Shafter, Asphalto, Railroad Gap, Buena Vista and Monument Junction fields. The production and reserves statistics are useful and informative to those interested in the productivity, economics and successful exploitation of the Monterey.
Management of Health and Safety Hazards in Oil and Gas
Authors: Floris Vinio V.
Published: June 2014

This paper reviews the principal health and safety hazards in the oil and gas industry with focus on unconventional gas and oil extraction activities. Risks include exposure to hydrogen sulfide, silica, hazardous chemicals, extreme temperature and fatigue, vehicle/transportation incidents, explosions and fires, falls, confined spaces, and risk of being struck-by/caught-in/ caught-between perilous objects. This discussion is accompanied by occupational health and safety statistics, description of hazards and the creation and implementation of a health and safety culture as a mean to mitigate (if not eliminate) harmful conditions.
A New Semi-Analytical Method for Analyzing Production Data from Constant Flowing Pressure Wells in Gas Condensate Reservoirs during Boundary-Dominated Flow
Authors: Sureshjani M. Heidari , Behmanesh H. , Clarkson C. R.
Published: June 2014

With the current focus on liquid-rich plays in North America, and the importance of gas condensate reservoirs globally, there is an increased importance placed on reservoir engineering methods to analyze such reservoirs. This paper provides a new semi-analytic boundary-dominated flow equation (BDFE) and also adapts the existing BDFE of dry gas reservoirs for production analysis of constant flowing pressure wells producing from gas condensate reservoirs. To analyze long-term production data, these equations are coupled with a modified material balance equation to give gas-in-place and average reservoir pressure obtained from plotting techniques which use iterative procedures. The required input data for analysis are gas flow rate, bottomhole pressure, CVD test data, and a portion of the immiscible gas relative permeability curve. We also introduce a new material balance time function for gas condensate reservoirs. To verify our analysis methods, compositional numerical simulation is used. We also test the practicality of our approach through analysis of field data.
Tensile Failure of Shales: Impacts of Layering and Natural Fractures
Authors: Mokhtari Mehdi , Bui Binh Thanh , Tutuncu Azra N.
Published: June 2014

Shale formations present anisotropic characteristics in mechanical, acoustic, and flow properties due to their layering and pre-existing natural fractures. This anisotropic behavior can create a complex fracture network rather than the conventionally presumed planar fractures. Although incorporating anisotropic behavior is essential for optimizing the hydraulic fracturing design and analyzing the post-fracture data, there are limited studies addressing the anisotropic tensile behavior of organic-rich shale formations. The objective of this study is to explore the tensile strength and tensile fracture patterns in shales by conducting splitting tests on variety of shale formations.

Core samples from the Eagle Ford shale in the oil window, its overlying Austin Chalk and the underlying Buda formation, Green River immature oil shale, Mancos shale, and Berea sandstone samples have been tested to investigate the effects of layering, natural fractures, total organic carbon (TOC), maturity and mineralogy on tensile behavior. Having different types of Green River shale, the impact of TOC on the tensile strength was obtained. The anisotropic tensile behavior of Mancos and Green River shales were studied systematically at various orientations between the applied force and the bedding direction providing key understanding on the fracture growth patterns at any direction. Finally, the tensile strength and fracture patterns for several Eagle Ford, Austin Chalk and Buda core samples with extensive natural fractures are discussed.
Sensitivity Study on Storage of CO2 in Saline Aquifer with Fracture-Surrogate Models Based on the Tensleep Formation
Authors: Alvarado Vladimir , Yu Meng , Chang Yang , Marcy Peter , Huzurbazar Snehalata , Lynds Ranie
Published: June 2014

For industrial-scale CO2 injection in saline formations, produced CO2 and pressure buildup can limit storage capacity and efficiency. Sensitivity analysis on operational strategies and reservoir parameters serves to select the optimum injection strategy to increase injectivity, relieve pressure buildup, improve CO2 trapping efficiency, and constrain brine leakage. In this paper, we developed a surrogate model for aquifers in the Tensleep Formation based on features of the the Tensleep reservoir at Teapot Dome in Wyoming. The corresponding oil reservoir model was history-matched using production data from the Teapot Dome. The history-matched simulation model was turned into an aquifer by eliminating the oil phase, but preserving the main geological traits. We then proceeded to investigate operational strategies to achieve an effective tradeoff between higher CO2 trapping efficiency and delayed CO2 breakthrough at producers. A well architecture consisting of two horizontal production wells completed at the bottom of the aquifer downdip and two vertical vertical injection wells completed updip in the reservoir. A 50-point experimental design, aimed at evaluating the effect of depth, porosity and permeability on CO2 storage, was conducted in four models: single-porosity model without solubility, single-porosity model with solubility, dual-porosity model without solubility and dual-porosity model with solubility. The result of the 50-point design shows that compared to single-porosity models, CO2 trapping efficiency is lower in dual-porosity models. In addition, the small variability in trapping efficiency for dual-porosity cases was almost completely explained by depth. This contrasts with the single-porosity models whose large variability in CO2 trapping efficiency was explained primarily by porosity, then permeability, and finally depth. We demonstrated the value of selecting optimum injection rates and well configurations considering effects of natural fractures and solubility on storage capacity. The results of the study provide insights either in selecting the operational strategies for CO2 storage in fractured reservoir systems or analyzing the effect of reservoir parameters on storage capacity and efficiency in saline aquifers in terms of regional considerations.
New Production-Decline Models for Fractured Tight and Shale Reservoirs
Authors: Ali Tariq , Sheng James , Soliman Mohamed
Published: June 2014

Production decline curve analysis is one of our common methods to estimate production rate profile and ultimate recovery of a tight or shale gas reservoir. Because of the long transient behavior of low-permeability gas reservoirs, early production data generally exhibits fracture-dominated flow regimes and late-time flow regimes have not reached yet. These challenges the robustness of production decline curve analysis in such reservoirs, and this also question the validity of several models presented in the literature.

If a well produces at a constant flowing pressure, a log-log plot of rate divided byover cumulative gas production vs. cumulative gas production yields a straight line, and cumulative gas production vs. time yields another straight line as well. Based on these two relationships and real data observations, new production-decline models are proposed in this paper.

The proposed models are verified by a large number of well production data in tight and shale reservoirs. These models are also validated by numerically simulated cases. Under some special conditions, the proposed models can be used to validate some published models. Many real data and simulate data show that the proposed models can be reliably used to estimate production rates and the ultimate recovery in tight and shale reservoirs.
Unique Application of EM LWD Casing Antenna System to Rocky Mountain Drilling
Authors: Hunter J. , Maranuk C. , Rodriguez A.
Published: June 2014

Certain formations in the Rocky Mountains preclude the use of electromagnetic (EM) telemetry due to their inherent resistivities. A new system has been developed that extends the use of EM telemetry systems where they were previously not usable. The system involves installing a special downhole antenna when surface or intermediate casing is run to improve EM signal to noise ratio. The casing antenna system not only allows operators to take advantage of the benefits of EM logging-while-drilling (LWD) systems but also extends the drilling depth range where data can be provided.

Drilling wells in the Powder River Basin often requires heavy mud weights and the extensive use of lost circulation material (LCM). Unfortunately, these types of muds play havoc on standard mud pulse telemetry systems. Washed equipment and downhole failures related to plugged pulsers often result in multiple trips for failures and excessive nonproductive time (NPT). This new EM LWD system, by contrast, has no moving parts and a through-bore, which allows for higher concentrations of LCM and heavy weighting materials to pass easily through the bottom hole assembly (BHA). The system is combinable with a variety of LWD sensors so the telemetry type proves especially useful in areas that experience high LCM incidents. A key aspect of this system is that it also extends the depth range of where EM LWD systems can operate.

Along with a compensated resistivity tool, a unique LWD spectral azimuthal gamma ray (SAGR) sensor, which provides accurate formation evaluation data, high quality gamma ray images and spectral elemental analysis, was used to help geosteer the well to stay in the zone of interest in the reservoir. This paper will examine a case study where the new system was used in an area where drilling with EM was not previously possible. It will describe the basic system design, key operating parameters, provide insight on the drilling problems, and address formation evaluation challenges and solutions.
Understanding the Implications of Multiple Fracture Propagation in Well Productivity and Completion Strategy
Authors: Mata D. , Dharwadkar P. , Gonzales V. , Sitchler J. , Cherian B.
Published: June 2014

The revolution of the multistage horizontal completions has made low-permeability laminated reservoirs a cost-effective business. The key to success relies on maximizing the surface area contacted, a process that requires an adequate stage isolation technique. From traditional "plug and perf" to efficient sliding sleeves, the application of a particular system is related to the number of fractures that can be propagated during a single treatment injection. This condition varies according to rock and reservoir properties, principal stresses, zonal isolation and stimulation design.

This study introduces a methodology to build predictive, repeatable models that integrate reservoir characteristics (mineralogy, pore pressure, thickness) along with geomechanics (anisotropic Poisson's Ratio, Young's Modulus, and horizontal stresses) and fracture pressure diagnostics (pressure history match, near-wellbore pressure analysis) to predict the likelihood of propagating multiple fractures per stimulation stage. Examples of the application of this workflow to select the suitable completion mechanism are provided using multiple datasets from the Williston Basin. Additionally, a calibrated production model measures the impact of a specific zonal isolation method on well productivity.

Finally, this paper concludes with a series of sensitivities to determine the influence of different reservoir and rock properties in fracture propagation and provides recommendations regarding data requirements to apply this methodology in a particular field.
Nikaitchuq Project Vibration Mitigation Strategy
Authors: Wright James , Borri Luca , Simeone Davide , Longo Joseph , Weber Matt , Barnes Brandon
Published: June 2014

The eni Petroleum Nikaitchuq field is located offshore in the Beaufort Sea within the North Slope region of Northern Alaska. The 12-1/4" intermediate section of the Nikaitchuq wells are drilled with a Rotary Steerable System (RSS) at high inclination prior to landing near-horizontal in the reservoir. The intermediate hole section passes through a very abrasive sand with an unconfined compressive strength (UCS) of approximately 22 ksi called the Lower Ugnu.

Historically, the drilling of the 12-1/4" intermediate section has been drilled with two to three bit runs consisting of various polycrystalline diamond compact (PDC) and tri-cone designs. This was due to the abrasive nature of the Lower Ugnu combined with interbedded soft sand causing ledging, high stick-slip and lateral vibrations which lead to consequential bit/BHA damage and a reduction in drilling efficiency.

With the objectives of drilling the section in one run and to minimize damages to the RSS and MWD, a vibration mitigation workshop was conducted between the Nikaitchuq drilling team and key service company experts. The workshop team focused on four strategies to mitigate vibrational issues:

Bottom Hole Assembly modification. Introducing new technologies and tools into the drill string to capture high density data and mitigate vibration. Mapping and prediction of the hard streaks within the intermediate section. Modification of drilling practices where possible.

BHA and bit vibration modeling, new vibration mitigation tools, Measurement While Drilling (MWD) and multi-axis downhole vibration measurement data, BHA and stabilizer reconfiguration, as well as implementing various drilling parameters were all investigated and applied in both the front end and at the rig site.

This paper demonstrates the systematic approach the Nikaitchuq drilling team implemented to mitigate damage to the bit and downhole tools as well as improve drilling performance by minimizing stick-slip and lateral vibrations.
Understanding the Impact of Field Development and Changing Fluid Compositions on Corrosion Inhibitor Selection and Performance
Authors: Kirkpatrick Alistair , Reid Melanie , Machray David , Adelusi Adedamola
Published: June 2014

Corrosion inhibitor chemicals are an established successful means of protecting oil and gas producing assets from damage caused by internal corrosion.1,2 Over life of field, these assets will often have to operate under significantly different conditions compared to the original basis of design. Long term processes such as increasing water production and the break-though of injection water in producing wells typically result in a gradual change in system conditions and fluid compositions. Alterations or additions to the system, such as through brown-field development or addition of a subsea tieback, can result in significant and rapid changes to system conditions and fluid compositions.

Corrosion modelling software is often used to predict how these changes will affect the severity of the corrosion risk in the system.3 Although useful in predicting the anticipated corrosivity of the fluids, the models do not adequately take into account the effect which these changes may have on the corrosion inhibitors used to protect the system. Factors such as brine composition can have a minor influence on predicted corrosion rate but a significant effect on inhibitor performance; other factors such as composition of the hydrocarbon phase may dramatically influence inhibitor performance but are not accounted for in standard corrosion modelling software.

This paper describes a laboratory study evaluating the performance of corrosion inhibitors under North Sea oilfield conditions. The paper details how inhibitor performance is affected by changing brine composition over time as a consequence of injection seawater breakthrough from secondary recovery. The study also describes when the overall hydrocarbon composition is altered, due to commingling of fluids in the topsides process as a result of a new subsea tieback to a gas-condensate field being brought on-line. The data presented demonstrates the importance of evaluating the suitability of a corrosion inhibitor under both current conditions and potential future conditions when selecting the most suitable inhibitor for the application. It also highlights that changes in certain factors which do not significantly change fluid corrosivity as predicted by corrosion modelling, such as brine and hydrocarbon composition, can have a significant detrimental effect on corrosion inhibitor performance. Finally, the work reinforces the assertion that inhibitor revalidation is a key requirement, whether system conditions change gradually, for example with injection water break-through or instantaneously through drilling and production of new wells.
The Challenges Associated with the Development and Application of Oil and Gas Corrosion Inhibitors
Authors: Jenkins Alyn
Published: June 2014

In many oil and gas fields around the world, hydrocarbons are being extracted from fields that have very severe system conditions. It is now commonplace for new oil and gas fields constructed with carbon steel piping to operate at extremely high temperatures (>150°C) and it is also normal for fields to produce gas that contains CO2 or H2S in excess of 20 mol%. Consequently, corrosion inhibitors are now required to be effective under very harsh operating conditions. However, these are not the only challenges that corrosion inhibitor developers need to overcome. Corrosion inhibitors are also required to mitigate many diverse forms of corrosion including pitting, under-deposit, galvanic, top-of-line and preferential weld corrosion.

Corrosion inhibitors used in oil and gas production are normally only effective in preventing sweet or sour corrosion. However, in aging assets corrosion inhibitors may also be required to control corrosion due to the presence of oxygen and many traditional inhibitors are simply ineffective when oxygen is present. Furthermore, local environmental regulations restrict what corrosion inhibitors can be used in certain geographic locations. Finally, oil and gas fields operating in deepwater environments provide additional complexities with respect to the deliverability of the corrosion inhibitor to the subsea injection location.

This paper examines the many challenges the industry now faces in developing corrosion inhibitors for new assets, aging assets and deepwater fields. The paper also details the factors that can have a negative effect on inhibitor performance. The paper discusses the restrictions regarding what inhibitor chemistries can be used as a result of environmental regulations and operator preferences. The problems associated with monitoring corrosion inhibitor performance in the field and the considerations required before deploying an inhibitor are also explored.
Passivation of Titanium Alloy with Aminopolycarboxylic Acid-Based HF Acid Fluid
Authors: Lynn Pascarella Natalie , Reyes-Garcia Enrique. A.
Published: June 2014

Exposure of a titanium (Ti)-based alloy to a hydrofluoric (HF) acid-containing fluid can result in corrosion of the alloy and potentially complete dissolution, depending on the temperature and HF acid concentration. The demanding conditions encountered in harsh environments, such as geothermal and high-pressure/high-temperature (HP/HT) wells, require suitable treatment fluids that can be used to remove wellbore scale or accumulated minerals in the near-wellbore (NWB) area. The use of HF acid fluids can then preclude the effective treatment of such formations unless corrosion can be managed. There is no known effective corrosion inhibitor that can be used in conjunction with HF acid on Tialloys. This paper presents findings that can provide advantages for the design of appropriate corrosion inhibitors for these alloys, and similarly, HF acid-sensitive metallurgies. A HF acid-containing fluid based on an aminopolycarboxylic acid (APCA)chelant has the ability to significantly prevent and even minimize the corrosive effects of such fluid on Ti. The chemical combination of chelant/HF acid and conventional corrosion inhibitor plays a functional role in the prevention of the complete corrosion of Ti alloys in the presence of HF acid. Suitable chelant concentrations range up to 0.6 mol/L, corrosion inhibitor loadings up to 4% w/v, up to 2%HF acid concentration, and a pH of 1 to 4. Corrosion loss screening spanned 250 to 300°Fwith APCA and HF acid and up to 375°F with low to no HF acid in the fluid, and specimens treated using an inhibitor suitable for hydrochloric (HCl) acid-based fluids were protected for up to 4 hr. Reasonable corrosion rates less than 0.05 lbm/ft2 were obtained based on the pH, temperature, and HF acid concentration, and to a lesser degree, the amount of chelant. The Ti specimens suffered from pitting, and this was the major negative effect observed. Notably, the use of a conventional yet inhibited HCl/HF acid fluid corroded and dissolved the specimen, unlike all the tests where the chelant/HF acid combination was used. The specimens were analyzed using scanning electron microscopy/energy dispersive X-ray spectroscopy (SEM-EDS) and surface elemental mapping, and the spent fluids were analyzed for dissolved ions (ICP); such analyses serve to elucidate the effects of the chelant and HF acid role in passivating the surface of the alloy.
Numerical Prediction of Reservoir Souring Based on the Growth Kinetics of Sulfate-reducing Bacteria Indigenous to an Oilfield
Authors: Sugai Yuichi , Owaki Yukihiro , Sasaki Kyuro , Kaneko Fuminori , Sakai Takuma
Published: June 2014

Seawater and/or brine injection for oil recovery is frequently accompanied by souring because such water contains sulfate mainly sourced by the growth of sulfate-reducing bacteria (SRB). The mechanisms of reservoir souring vary depending on reservoir conditions such as species of SRB, organic substances that become nutrients for SRB and temperature at what different specie can survive.The purpose of this study is to predict the reservoir souring in an oilfield in which brine injection is planned. For this purpose, chemical and microbiological analyses of the oilfield brine, kinetic studies of the growth of SRB indigenous to the brine, and numerical simulation studies on the reservoir souring in the oilfield have been performed.

Several kinds of organic substances as carbon donors that can be nutrients for SRB were found in both production and injection brine collected in the oilfield. Desulfonosporus sp., Desulfobulbus propionicus and Desulfomicrobium thermophilum were the types of SRB that were found in both brine samples by genetic analyses of DNA extracted from them. Bacterial cell number of SRB in the injection brine was ten times larger than that in the production brine. In addition, the most active growth of SRB was found in the injection brine supplemented with ethanol, therefore, the SRB inhabiting the injection brine was assumed to grow dominantly and generate hydrogen sulfide using sulfate and ethanol in the reservoir. On the basis of this mechanism, an equation that calculated growth rate of the SRB was derived with three variables: temperature, concentration of sulfate, and concentration of ethanol from the results of incubation experiments using the injection brine.

A numerical simulator including the growth rate equation for the SRB was constructed by modifying a simulator of Microbial enhanced oil recovery. The SRB grew and generated hydrogen sulfide around the injection well where temperature was decreased to <50 °C by injected brine. The results of the numerical simulation suggested that severe reservoir souring doesn't occur by the brine injection in the oilfield. Furthermore, the numerical simulation suggested that SRB generates H2S only around the injection well because of a temperature drop there, therefore, the reservoir souring can be prevented more surely by heating up the injection brine to 50 °C, or reducing ethanol in the injection water.
High Resolution Real-Time Thickness Measurement of Internal and External Casing Anomalies with Ultrasonic Scanner Tools
Authors: Tello Lucio N. , Azuaje Dimas C. , Tran Dung
Published: June 2014

The internal and external casing condition is an important part of well integrity evaluation. The public is concerned with environmental issues at sea and on land. In areas where shale exploitation is in full swing, the protection of the underground aquifers is of concern. Tools with increased resolution in corrosion and thickness evaluation are being upgraded to meet these challenges.

Ultrasonic scanning tools measure casing thickness by inducing a resonance in the casing in the thickness-mode. At the same time, they measure the cement acoustic impedance at higher radial and vertical resolution than standard CBL and sector tools. Traditionally, the thickness measurement is delivered after computing the resonant frequency of the pipe from the raw waveforms telemetered to the surface via the communication system. This method is fine except there is a time delay between the acquisition and the final delivered thickness log and map. Another disadvantage of this method is that in order to cover the pipe circumference for thickness, the logging speed needs to be reduced during acquisition.

A modified Digital Fourier Transform algorithm implemented in the ultrasonic radial scanner tool improves the circumferential and vertical coverage over previous methods while extending the thickness measurement range, resolution and accuracy. External corrosion is evaluated by ultrasonically measuring the pipe ID and adding it to the thickness. The algorithm is performed by the down-hole tool at high speed and resolution, covering the pipe in both circumferential and vertical dimensions, in real time and at normal logging speeds, thus saving operation and rig time.

Log examples from test wells constructed to simulate internal and external corrosion, as well as results from field testing corroborate the methodology and the algorithm. The ultrasonic radial scanner with real time thickness (RTT) capability gives a higher resolution thickness measurement and an improved internal and external corrosion evaluation.
Corrosion Management – An Overview of the Corrosion Control Process in OMV Petrom
Authors: Nicolae I. , Firu L. S.
Published: June 2014

Corrosion is causing partial or total destruction of the material in general, and of metals in special due to a reaction with the environment. This destruction is in fact a natural process because of the metals in processed form, have a high energetic level and there is a normal tendency to revert back at initial natural form as oxides in ores.

In the oil and gas industry, down hole pumps, tubing, sucker rods, pipelines and surface facilities equipment made by carbon steel are susceptible to corrosion. Corrosion is caused by the presence of CO2 (sweet corrosion), H2S or organic acids (sour corrosion).

Today applying corrosion inhibitor is a common practice in OMV Petrom. The application of inhibition on the large areas has been implemented since 2007 as part of modernization project in which more than 5000 wells were modernized. This included: the implementation of new artificial lift design and installation of new tubing, new pumps following API standards, corrosion inhibitor injection, dosing skids and optimization of production parameters. At the same time Corrosion Monitoring Devices (DMC) were installed in 10% of injection points. Appropriate chemical trucks for filling up of dossing skids and batch treatments assurance were acquired as well.

This paper shows an overview of corrosion management in OMV Petrom, achievements and benefits of the projects implemented in OMV Petrom in last years, starting with 2005 till today, where Main Time Between Failures (MTBF) increase 8, 5 times in comparison with 2005. The corrosion inhibitor injection process is monitored and optimized continuously keeping corrosion rate under control. Continuous optimization means: coupon and failure analysis, continuous inhibition or batch treatment, adjustment of dosage, new corrosion inhibitor screening considering specific environment and requirements, introducing of new chemistry for tubing carbon steel and new artificial lift design considering corrosion resistant materials etc.
A Selection Methodology for 13Cr-Type Alloy Oil Country Tubular Goods
Authors: Caldwell Eric , Zhang Hugh , Goodman Lindsey
Published: June 2014

Significant interest exists in the deployment of 13Cr martensitic stainless steels in offshore oil and gas projects. Several grades of 13Cr exist, with the seemingly negligible variations between their chemistries and fabrication processes. The different grades perform dramatically differently, especially regarding cracking resistance in sour or chloride-containing environments. Determination of the proper 13Cr grade for sour service involves the investigation of domain diagrams, and often requires further fitness-for-service testing. However, the validity of each domain diagram for only one chloride concentration or content greatly limits their practicality for selecting 13Cr, thus impeding the ability to determining if fitness-for-service testing should be performed and its potential outcome. Therefore, an empirical model compiled from fitness-for-service data and supported by oilfield experience led to the development of a resource tool designed to provide quick validation of fitness-for-service test results, increasing the efficiency of decision-making for 13Cr selections. Also, this paper summarizes the pros and cons of different 13Cr OCTG alloys, in regards to the mechanical strengths and performances in sour/non-sour conditions, high chloride levels, low pH values and presence of CO2. Specifically noted are the H2S partial pressures in excess of NACE MR 0175 limits where 13Cr materials can be successfully utilized.
Investigation of Noninvasive Healing of Damaged Piping System using Electro-Magneto-Mechanical Methods
Authors: Mukherjee Debanjan , Zaky Zeyad , Zohdi Tarek I. , Salama Amgad , Sun Shuyu
Published: June 2014

Virtually all engineering applications involve the use of piping, conduits and channels. In the petroleum industry, piping systems are extensively employed in upstream and downstream processes. These piping systems often carry fluids that are corrosive, which leads to wear, cavitation and cracking. The replacement of damaged piping systems can be quite expensive, both in terms of capital costs, as well as in operational downtime. This motivates the present research on noninvasive healing of cracked piping systems. In this investigation, we propose to develop computational models for characterizing noninvasive repair strategies involving electromagnetically guided particles. The objective is to heal industrial-piping systems noninvasively, from the exterior of the system, during operation, resulting in no downtime, with minimal relative cost. The particle accumulation at a target location is controlled by external electro-magneto-mechanical means. There are two primary effects that play a role for guiding the particles to the solid-fluid interface/wall: mechanical shear due to the fluid flow, and an electrical or magnetic force. In this work we develop and study a relationship that characterizes contributions of both, and ascertain how this relationship scales with characteristic physical parameters. Characteristic non-dimensional parameters that describe system behavior are derived and their role in design is illustrated. A detailed, fully 3-dimensional discrete element simulation framework is presented, and illustrated using a model problem of magnetically guided particles. The detailed particle behavior is considered to be regulated by three effects: (1) the field strength (2) the mass flow rate and (3) the wall interactions.
Snorre In-depth Water Diversion Using Sodium Silicate - Large Scale Interwell Field Pilot
Authors: Skrettingland Kjetil , Dale Elisabeth Iren , Stenerud Vegard Røine , Lambertsen Anne Marie , Kulkarni Kari Nordaas , Fevang Øivind , Stavland Arne
Published: June 2014

Here we report on in-depth water diversion using sodium silicate to increase oil recovery at the Snorre field, offshore Norway. A comprehensive qualification program revealed that the onset of gelation can be controlled; this was demonstrated in realistic core flood experiments as well as in a single well injection pilot. This paper highlights key design, response measurement plan and operational experiences from a large scale interwell field pilot of sodium silicate injection in a reservoir segment at the Snorre field on the Norwegian Continental Shelf. The operation of injecting 113 000 m3 preflush, 240 000 m3 sodium silicate and 49 000 m3 postflush was performed from June to October 2013. The goal is to create an in-depth restriction between a subsea water injection well and a platform oil producer with approximately 2 000 m well spacing, and thereby improve the reservoir sweep by water injection.

To perform the field pilot a 35 000 ton shuttle tanker was converted to a well stimulation vessel with the necessary equipment to accommodate a higher number of people, a desalination plant, storage and mixing equipment and high pressure pumps. The vessel was connected directly to a subsea water injection well and injected during a period of 5 months. The chosen design was to (a) soften the formation water by a KCl preflush, (b) control the gelation kinetics using HCl acid as activator, mixed into the diluted silicate solution and (c) displace the silicate solution by a KCl postflush followed by seawater injection.

The pilot injection operation is completed, and the displacement of the sodium silicate with following seawater injection to the planned position for in-depth plugging is still on-going. The operational success criteria of proving ability to perform large scale transport, mixing and injection of sodium silicate from a shuttle tanker directly into a subsea well with no near wellbore plugging is met. Future production response will reveal if the success criteria of in-depth plugging, improved reservoir sweep and decrease in water cut will be met.
Use of Carbon Dioxide and Hydrocarbon Solvents During the Method of Steam-Over-Solvent Injection in Fractured Reservoirs for Heavy-Oil Recovery From Sandstones and Carbonates
Authors: Naderi K.. , Babadagli T..
Published: June 2014

Because of low efficiencies and the high cost of the individual injection of steam and solvent for heavy-oil recovery, their hybrid applications have gained significant attention recently. Although numerous laboratory studies exist and there are a considerable number of field projects for sandstone environments, fractured carbonates lack technologies to drain matrix oil efficiently. An alternative-method injection of solvent and steam was proposed and tested earlier (Babadagli and Al-Bahlani 2008). This process applies steam initially to condition the matrix oil for succeeding solvent injection and steam reinjection to retrieve solvent in the matrix and to recover additional upgraded oil. The present study uses carbon dioxide (CO2) as a solvent and compares it with hydrocarbon solvents in this type of application. To clarify the physics of the process and to test the applicability of the method for different reservoir and injection conditions, we conducted a series of experiments by first injecting steam, followed by CO2 injection. In the third cycle, steam was injected again to produce upgraded oil in the matrix. The experiments were performed under static conditions (soaking sand and carbonate samples in steam or CO2 chambers) at different temperatures and pressures. CO2 is shown to be a reasonable alternative for hydrocarbon solvents in such a process in terms of cost and benefits by reducing the solvent expenses, keeping the oil-production levels, and disposing of a greenhouse gas.
Well Completions and Profitability: A Horn River Shale Case Study
Authors: Ross C. R. , Anderson D. M. , Stephens C. P. , Virues C.
Published: June 2014

The profitability of a well in an unconventional play is significantly influenced by its completion. It is widely understood that tighter rock needs more stimulation to economically recover hydrocarbons. However, how does one know if a well is being over-stimulated (fracture area created does not justify cost incurred) or under-stimulated (lost potential/profitability in productivity from a well's limited contact to the formation)?

The objective of this paper is to develop and demonstrate an efficient workflow that will help stakeholders make better decisions in the area of completion planning. The workflow utilizes information from fracture modeling, production data analysis, and project economics to quantify the relationship between the key input parameters of the well completion (e.g. pumping rate, proppant and fluid pumped) and expected profitability expressed in net present value (NPV) terms. As a secondary objective, the case study demonstrates that a probabilistic approach (Monte Carlo Simulation) can be used to efficiently arrive at a consistent conclusion to the primary workflow. The output of the probabilistic model includes P90/P50/P10 production and net cash-flow forecasts, from which distributions of NPV can be obtained.

This workflow is intended to help engineers compare profitability among different completion options. A shale gas field example is presented to illustrate the methodology.
Technical and Economic Evaluation of Hydrocarbon Prospects Offshore Uruguay and the Challenge of Maximizing Rent from Exploration to Production Phases through Local Content
Authors: Gristo P. , Tomasini J. , Ferro S. , Fennema J. , McLeroy P.
Published: June 2014

From 2009, when the first offshore bidding round took place in Uruguay, and in particular from the second bidding round that constituted a enormous step in the exploratory history of Uruguay, our country faces a new and nontraditional hydrocarbons upstream activity. Government take, including the National Oil Company association in the case of a discovery, is already fixed under the Production Sharing Contracts in force and do not vary much with the field size. Therefore, a possible strategy to maximize the local revenues (income from Uruguayan services, products and human resources), which constitutes a key part for a sound distribution of petroleum revenues within the country, would be to increase the local content in the supply chain.

Taking into consideration analogous geological basins, and the geological and technical probability of success for offshore Uruguay as a frontier basin, the field size and hydrocarbon potential was evaluated from a stochastic point of view. The cash flow analysis of a hypothetic oil development was carried out, incorporating the actual economic variables of the contracts in force offshore Uruguay, as well as the current fiscal regime. The standard project parameters, investments yardsticks and the government and contractor takes were calculated with the aim to obtain the Uruguayan rent and the relative impact of the local content.

This work constitutes the first approach to the analysis of expenditures and investment during the current stage of exploration, and the eventual phases of appraisal, development and production offshore Uruguay. The technical and economic evaluation applied to a portfolio of offshore prospects models the level of expenditures and investment from exploration to production.

The assessment of the potential impact of the activity on macroeconomic variables is carried out considering the local services and products that would be necessary for each stage, in order to identify the areas where increasing local content will provide the larger impact in the country economy.
The use of Constructed Wetlands in Produce Water Treatment; an Option for the Oil and Gas Industry
Authors: Korsah P. E , Ambrose I. S. , Korsah W.
Published: June 2014

Produce water treatment and discharge is a critical public health issue in most oil producing countries, where efficient and economical treatment options are being sought after. The main focus is centred on the removal of heavy metals and hydrocarbon residues. Phytoremediation, the technique that utilizes a plant's inherent ability to accumulate metals, is fast emerging as a relatively cheap and environmentally friendly alternative to conventional wastewater treatment methods. A corollary of this is an urgent need to identify plant species with the appropriate suite of characteristics for phytoremediation. The purpose of this study was to evaluate and compare the phytoremediation potentials of Limnocharis flava, Thalia geniculata and Typha latifolia using three serially connected horizontal sub-surface flow (HSF) constructed wetlands. Each wetland had only one of the three plant species but all were supplied with wastewater from a common source. From October 2010 to March 2011, the growth performance of the candidate plants was measured, and their accumulation and translocation rates of heavy metals (Fe, Cu, Zn, Pb, Hg) determined using atomic absorption spectrophotometer. Mean removal efficiencies ranged from 40-80%, 48-54%, 44-54%, 18-32% and 8-38% respectively for Fe, Hg, Zn, Pb and Cu. The removal efficiencies of the species differed depending on the metal. L. Flava was most efficient (p<0.001) at removing Fe, Cu mostly removed by T. latifolia (p< 0.001) whilst T. geniculate appeared to be the best remover of lead (p< 0.021). Both T. geniculata and T. latifolia appeared to remove zinc better than L. flava (p<0.021), but there was no statistical difference in the removal rates of mercury by the plants. Similar trends were observed for the bioaccumulation factor, which increased substantially with time. The plants accumulated most of the metals in their roots. The findings demonstrate the capabilities of the three phytoremediants for improving the quality of heavy metal contaminated water.
Use of Reservoir Simulation to Estimate Drainage Area and Recovery Factor of an In-Situ Combustion Project in a Complex Water-Drive Heavy Oil Reservoir
Authors: Gonzalez Laureano , Ferrer Jose , Fuenmayor Mac , Castillo Nerio , Gil Edison , Farouq Ali S. M.
Published: June 2014

In-situ combustion (ISC) is being carried out in the Quifa heavy oil reservoir in Colombia, employing four vertical inner wells and four deviated outer wells (inverted nine-spot pattern). Additionally there are four horizontal wells surrounding the pattern, which started producing one year before the combustion project was initiated.

In order to evaluate the project performance key parameters, such as volumetric sweep efficiency and recovery factor must be estimated. Therefore, it is important to have reliable values of drainage area and oil in-place volumes since they are basics for the calculations. Given the complex nature of this reservoir, with a strong water drive, the estimation of the drainage area, oil in place and the recovery factor posed a major challenge. The reservoir is characterized by abrupt permeability and oil saturation changes, resulting in water channeling and well interference.

This paper presents the methodology used to obtain the drainage area and current recovery factor of the ISC pilot project by using numerical reservoir simulation. It comprises the generation of oil drainage maps and cross-plots of what we called "Oil Displaced by Neighboring Wells, ODNW" as a function of time. This approach is more accurate than analytical methods for such complex reservoirs since those methods are based on ideal homogeneous reservoir conditions that assume uniform fluid displacement and a symmetrical advance of the combustion front.

Results are presented for the oil in place, the drainage area, and the recovery factor at one year of air injection. These results are compared with those derived from analytical methods. The methodology was designed to be readily applicable to similar heavy oil reservoirs worldwide.