bluuebunny/crossref_metadata_2025 huggingface dataset:
Cost-Efficient Well-Head Purification of Produced Water using a Humidification-Dehumidification Process
Authors: Balch R. S. , Muraleedharan S.
Published: June 2014

The objective of this research was to design, build, and test a desalination unit for produced water purification at the wellhead, yielding water clean enough for beneficial uses, while reducing the waste stream requiring disposal. A low-temperature distillation / humidification dehumidification (HDH) process was designed and constructed to meet requirements of energy efficiency and high tolerance to inlet water chemistry. Through the process, water is evaporated at an elevated temperature (175°F/80°C) in a flowing air stream, followed by cooling and capillary condensation resulting in the collection of purified water. The average treatment cost of produced water purification with this method was estimated, after successful field demonstration, to be $0.31/bbl when co-produced or solar heating was used. In contrast the cost of transported disposal of can reach and exceed $2.50/bbl.

After bench scale testing a prototype of the low-temperature distillation unit with desalination capacity of 30 barrels/day was designed and constructed. Produced water purification was then demonstrated at a gathering site provided by industry partner Harvard Petroleum Co. LLC and the technical and economic feasibility of the process was evaluated. After the field demonstration of the HDH process, experimental results indicated that ∼20% of the processed water was purified in each pass through the system and that adding the concentrate back into the inlet stream of the HDH unit did not subsequently impact efficiency of the process. Salts, minerals, and dissolvable organics in the produced water were removed efficiently by the process: the total dissolved solids (TDS) were reduced to less than 200 mg/L for inlet TDS as high as 250,000 mg/L, and the total organic carbon was reduced from 470.2 to 17.83 mg/L. The purified produced water is of suitable quality for beneficial uses, such as agriculture, irrigation and industrial processes. The system not only processes water economically, but also does not require the significant use of fossil energy that conventional desalination plants require to preheat water. The portable nature of the unit and the fact that it can be located at a wellhead or at a field gathering site reduces transportation costs, a major cost factor.
A Generalized Rheological Model for Drilling Fluids Using Cubic Splines
Authors: Bui Binh T. , Tutuncu Azra N.
Published: June 2014

In drilling fluid rheological characterization and hydraulics modeling, selecting a proper rheological model and obtaining rheological parameters using viscometers are critically important. Bingham Plastic, Power Law, and Yield Power Law are the most commonly used standard models for drilling fluid rheology since they are mathematically simple to implement. However, due to the complex nature of drilling fluids, these models do not often fit well to the rheological data. This leads to a significant error in drilling fluid hydraulics modeling. While searching for models based on the physical interaction between the various components of the drilling fluid, it is very practical to find simple mathematical functions that best fit to any experimental data obtained from field viscometers. This will improve the accuracy of hydraulics modeling, in particular for time dependent drilling fluids.

In this research, cubic splines have been used to fit the experimental data obtained from field viscometers. A generalized hydraulics model is presented to calculate pressure drop in pipe and concentric annulus with detailed sample calculations. A numerical simulator has also been developed to assist the calculations. The results obtained from the model have been validated with experimental data to verify the effectiveness of the proposed model.

The model introduced in this paper is the generalized form of all the other commonly utilized models and can be implemented for any fluid. The main advantage of the model is that it can capture all the complex rheological response of the fluid. Hence, all readings obtained from the viscometers can provide valuable input for the hydraulic model. Also, the numerical solution is stable and straightforward to implement. The model provides drilling engineers a simple and powerful method to accurately predict the pressure distribution along the wellbore. This is highly important in drilling fluid hydraulics program optimization and well control operation, especially in deep-water and arctic environments.
Completion Optimization Utilizing Multivariate Analysis in the Bakken and Three Forks Formations
Authors: King Victoria Martinez , Wray Laura
Published: June 2014

Completion optimization has been a key factor for ensuring an economic well in the Williston Basin. In North Dakota, most completion information is public after three to six months unless the wells are confidential. This enables operators to closely monitor offset completion and production performances. The goal was to optimize well economics through analyzing completion parameters. The area of interest for this analysis was confined to the Fort Berthold Indian Reservation and surrounding acreage in North Dakota.

Public and internal completion, reservoir and geologic data was gathered, interpreted, and used as inputs for the multivariate statistical analyses. These analyses were designed to understand the impact that both reservoir quality and completion design parameters have on production. The multivariate tool, coupled with quality checked and carefully interpreted data, has aided in understanding how sensitive well performance is to these parameters, as well as how these variables behave. This tool provided an analytic method to determine what parameters and their ranges are most critical to good production.

This paper will elaborate on the following high sensitivity completion and reservoir parameters and their behaviors: lateral length, proppant volumes, stage lengths (plug to plug or sleeve to sleeve), proppant type, treatment rate and water cut. The completion parameters were easily controlled by frac design, but additional analysis and review was needed to better understand the causes of high water cut. An understanding of completed reservoir (Middle Bakken or Three Forks) water saturations, job size, and geologic anomalies was critical in understanding and predicting this negative reservoir parameter.

This information was combined to predict the performance of various completion designs without having to invest the capital in large field tests. Economic analysis was then done using the cost of the respective completion design and expected performance. The optimized completion design was derived, in part, from the multivariate analyses and is currently being field tested.
Acoustic Techniques to Monitor and Troubleshoot Gas-Lift Wells
Authors: Taylor C. , Rowlan L. , McCoy J.
Published: June 2014

The distance to the fluid level provides beneficial information throughout the life of a gas-lift well. From the initial unloading of the well, to maintaining production, and even into troubleshooting the well, the location of the fluid level plays a crucial role in understanding the well's performance.

Some of the most valuable fluid level shots occur during the unloading process, when the fluid level is compared to the gas injection depth. Fluid levels can be used to help determine whether a problem is occurring within the wellbore or due to equipment malfunction. A quick surface measurement determines valves below the fluid level are not injecting gas. Finding holes in the tubing string and location of any restrictions in the tubing or casing help identify problems impacting production. During a workover, monitoring the fluid levels of a well filled with kill fluid ensures sufficient hydrostatic pressure is maintained against the formation. In gas-lift wells without a packer, producing bottomhole pressures can be accurately measured using an acoustic fluid level instrument. Bottomhole pressure information is useful in designing and operating gas-lift installations and measuring overall producing efficiency1.

Examples of fluid level shots on gas-lifted wells will be used to demonstrate these concepts. Acoustic fluid levels acquired on gas-lift wells provide a low cost, direct method to observe the well and benefit the operator through knowledge of the well's producing conditions.
Diagnostic Fracture Injection Tests: Common Mistakes, Misfires, and Misdiagnoses
Authors: Barree R. D. , Miskimins J. L. , Gilbert J. V.
Published: June 2014

Over the last twenty years, Diagnostic Fracture Injection Tests, or DFIT's, have evolved into commonly used techniques that can provide valuable information about the reservoir, as well as hydraulic fracture treatment parameters. Thousands are pumped every year in both conventional and unconventional reservoirs. Unfortunately, many tests that are pumped provide poor or no results due to either problematic data acquisition or incorrect analysis of the acquired data.

This paper discusses common issues and mistakes made while acquiring DFIT data. Guidelines on how to avoid these errors and secure the best possible data are provided including data resolution, pump rates, test duration, and fluid selection. Rules of thumb are provided to estimate the time required to reach fracture closure and establish stable reservoir transients for analysis.

The last part of the paper addresses potential (and commonly observed) problems in the analysis of the DFIT. These issues can be magnified in tight gas and shale reservoirs due the long data acquisition times and the subtle pressure transients that can occur. Specific issues that are discussed include poor ISIP data from perforation restriction, loss of hydrostatic head, gas entry and the resulting phase segregation, the use of gelled fluids, and errors in after closure analysis.
Estimation of Stimulated Reservoir Volume Using the Concept of Shale Capacity and its Validation with Microseismic and Well Performance: Application to the Marcellus and Haynesville
Authors: Ouenes A. , Aissa B. , Boukhelf D. , Fackler M.
Published: June 2014

To reduce our dependence on microseismic data which is only available in about 5% of the shale wells, a recently developed workflow based on "hard" Geophysical and Geological data is used for the estimation of SRV and its varying rock properties in a reservoir simulator. This workflow relies on the use of the concept of Shale Capacity which encompasses the four key shale drivers responsible for most of the factors affecting the shale well performance: TOC, Brittleness, Fracture Density and Porosity. The shale capacity is available over the entire 3D reservoir volume and is estimated from well and seismic data.

The SRV varying enhanced permeability is estimated through the use of a variable Half fracture length, a radial function and the shale capacity thus providing a realistic distribution and values to the reservoir simulator. Using appropriate gridding techniques such as the Tartan grid for the SRV cells, near-wellbore effects are accounted for along with no-Darcy effects and gas desorption in the shale reservoir. With these key factors represented in the dynamic model around the well, a Haynesville gas, water rate and pressure was successfully matched without the need for any major history matching effort. The resulting irregular and asymmetric SRV region and pressure distribution takes into account the geologic variability which has major implication on the EUR and well spacing. When comparing the EUR estimated from the derived geologically constrained model and those computed from traditional decline curve analysis, shale operators could be booking reserves that could be 50% lower than the actual ones. Finally, the spacing of the laterals could be optimized by taking into account the resulting irregular and asymmetric pressure distribution around the shale wells.
Environmental Responsibility of Current Proppant Solutions
Authors: Fuss Tihana , Shi Jingyu , Ma Jun , Herndon Daniel C. , Stephens Walter T.
Published: June 2014

The hydraulic fracturing industry recognizes two primary proppant types: sand and man-made (ceramic) proppants. Selecting the right proppant for a well focuses on the mechanical strength and conductivity of proppants under down hole (application) conditions. Since proppants are generally stable under high temperature, high pressure conditions, their environmental impact on well completion is often considered minimal. However, with recent increases in proppant consumption, mass of proppant used on a well site can now easily reach 6 million pounds. Transportation, storage and handling of such high volumes of any material pose an environmental challenge. This study compares the environmental impact of three different types of proppants: sand, lightweight kaolin clay proppants and intermediate density bauxite proppants, and proposes best practices to minimize risks.

This study first investigates dust generation associated with transportation, handling and storage of proppants. Results show that attrition of all tested proppant types generates dust. Chemistry, morphology and health hazard ratings of crystalline species present in generated dust are compared across variety of proppant types. Best practices for dust control are discussed.

Secondly, study focuses on natural radioactivity of current proppant products and compliance with state waste disposal NORM regulations. Study compares levels of detected natural radioactivity in proppants based on their type, geographic origin and detection method used. Costs associated with waste disposal of these materials are compared for several different states.
Complexities Associated with Thermal Stimulation of Low Gravity Oil Sands Using Horizontal Wells
Authors: Qi Q. , Zhang Q. , Ershaghi I.
Published: June 2014

Among the complex issues associated with recovering extremely viscous oil (API < 5 degree) using CSS; we focus on two important factors. First is a feature of these reservoirs with water lenses imbedded or overlain on top of the oil column. Next is the issue of optimum well completion method to uniformly deliver steam, enhance productivity and reduce steam requirements. The option of using CSS with horizontal wells to avoid water lens effects is compared to that of recovering such oil deposits using CSS in vertical holes. We computed expected responses for scenarios that included spot heating or distributing steam along the entire lateral of the horizontal well. For comparison purposes, we computed expected recoveries using horizontal vs. vertical completions for such ultra-viscous oil systems and compared with benchmark data from number of field historires of CSS for somewhat lighter heavy oil reservoirs.
Computational Fluid Dynamics for Horizontal Well Plunger Lift System Design
Authors: Longfellow Neil , Green David
Published: June 2014

As the future of gas and oil well drilling lies largely in directional and horizontal wells, it is important to develop tools that allow for the optimum operation of these wells. A key issue in this matter is the challenge of deliquifying horizontal gas and gassy oil wells. This paper discusses the use of computational fluid dynamics (CFD) to design and evaluate tubing plungers to improve performance in horizontal well deliquification.

Previous use of CFD by the authors thus far has been in design and evaluation of plungers for vertical wells. A validation study was carried out in which the fall rate of a variety of plungers were predicted with CFD and then compared to measured field results acquired through an acoustic study. The study found that CFD predicts fall rates within 8% of observed fall rates, validating it as a capable tool to characterize plungers. The process of using CFD predicted characteristics of a plunger, such as drag coefficient, to determine whether a particular plunger is appropriate for a particular well based on its typical operating conditions is also discussed.

Two major issues with plungers in horizontal wells are uneven wear and gas blow-by. CFD modeling addresses these with quantitative results such as the torque induced on the plunger during rise and fall, the forces on particular surfaces in plungers with multiple parts such as padded plungers. Qualitative results such as the flow patterns can also be used to predict if a given plunger will perform properly in a horizontal well.

Despite its strengths and capabilities, CFD can be limited in capturing the unsteady multiphase flow physics in inclined or horizontal tubing. To address this we are developing an experimental apparatus in which to study the flow physics in horizontal and inclined plunger-tubing systems. The results of this will be used develop and validate appropriate engineering criteria in CFD modeling for plunger deliquification in horizontal and inclined wells.
A Production Performance Prediction and Field Development Tool for Coalbed Methane Reservoirs: A Proxy Modeling Approach
Authors: Rajput Vaibhav , Basel E. D. , Ertekin Turgay
Published: June 2014

Field-scale simulations for development optimization can be overly demanding in terms of their time and manpower requirements. Exploration of a full suite of different design scenarios and operational behavior of a given reservoir becomes impossible within a reasonable period of time. This paper develops a method that can be used to predict production performance of a given field and perform field development studies with nominal manpower and computational requirements. Artificial neural networks (ANN) are used for development of expert systems for prediction of instantaneous and cumulative gas and water production, as well as for reservoir property prediction. A commercial reservoir simulator is used for generation of database for training, validation and testing of these expert systems. Uncertainty in reservoir properties is taken into account by varying the reservoir parameters within an estimated range of values. The overall performance levels of expert systems are optimized by varying various network parameters, and monitoring the error values for testing datasets.

Networks used for prediction of gas and water production profiles perform at error bounds less than 3% (forward networks), while those that are developed for prediction of reservoir characteristics at error levels of 15-19% (inverse networks). Forward networks were then used for optimization of field development. In this case, net present value (NPV) of a given field was placed as the parameter to be maximized during the search for optimum design specifications. Several case studies were carried out and analyzed. Improper field development strategies can result in huge losses for operating companies. Arriving at a proper well/drainage area selection and operational well specifications requires large operational time and excessive amount of simulation runs. With accurate results being obtained in fraction of seconds, this paper provides a simple and computationally-efficient technique that can be used to predict various production profiles and carry out effective field development studies.
Impact of Fracture Closure on Productivity Decline of Unconventional Wells
Authors: Sarna A. , Xing Q. , Mork J. , Ershaghi I.
Published: June 2014

With the rapid pace of drilling wells to tap unconventional oil and gas resources in the U. S., there is a need for further understanding of the fundamentals of reservoir mechanics that control well productivities. Wells with more than 5 years of data provide the opportunity to understand flow mechanisms affecting well productivity. What is particularly important is to test the validity and appropriateness of decline curve forecasting methods advocated in the literature over the last several years. To explain the unique and similar performance trends from unconventional wells, there are a number of issues that are gradually getting attention. Among these are the causes of rapid production decline seen after the initial peak. Certainly the physics of flow conditions causing the decline is not captured when regression analysis of production data is used with various decline models. Based on earlier studies, there is self-similarity among fractures formed during hydraulic fracturing. As discussed in the literature; the transient pressure behavior of complex self-similar fractures is equivalent to that for a single fracture. As such it is the flow capacity of the equivalent fracture that controls the behavior seen in actual performance of hydraulically fractured wells.

To test the applicability and weaknesses of commonly practiced regression models, we examined the performance of number of wells with production histories exceeding five years We used more than 40 examples from various shale plays all showing the loss of fracture quality resulting in lower flow capacity within the fracture network. The dynamic change in flow capacity is certainly not captured when decline curves are used that do not honor the flow regime's changes. As such, there can be major uncertainties associated with estimated EUR's from decline analysis techniques
Time-Domain Magnetic Defectoscopy for Tubing and Casing Corrosion Detection
Authors: Aslanyan A. , Aslanyan I. , Arbuzov A. , Zagidullin B. , Al-Rahawi T. A. , Prosvirkin S. , Al-Ajmi M. F. , Awad M. O. , Sharma S. S. , Das M.
Published: June 2014

The Magnetic Imaging Defectoscope (MID) is a tool designed to record the time response to high-energy electromagnetic pulses. Metal presence around the tool is evaluated by matching measured and numerically modelled magnetisation decays. The air response decays faster than if the tool is placed inside a metal pipe. If multiple pipes are present around the tool, the near pipe responds at earlier times and the more distant ones at later times. This phenomenon is key to detecting metal presence in each individual pipe. The MID tool features two sensors, short and long, to ensure reliable detection of responses from a wide range of multi-barrier completions and differentiate between defects in each barrier independently.

Despite this simple concept, the response detected by the tool has a complex time behaviour and cannot be modelled in a simple analytical way, which put time-domain technologies on hold for many years. The recent advances in computer speed and multicore parallel computing enable accurate numerical modelling of complex responses and determining metal presence in two metal barriers separately. In addition to thickness profiles for each barrier, the MID tool generates differential (DELTA) data panels, based on the difference between numerical models and actual responses, that visualise electromagnetic signatures of metal structures and can be used to locate and recognise various completion components, such as packers or SSD.

The paper describes the basics of the time-domain magnetic-pulse technology, specifications of the tool itself and laboratory test data. This technology has been tested in a dual-string producer of the Raudhatain field operated by the Kuwait Oil Company. The long and short strings were suspected to be communicating due to identical water cut trends. The MID tool was run once in memory mode on slickline through the long string and detected a 1.5-inch corrosion hole between packers that created communication with the short string. This communication flow left a footprint in a shut-in temperature log right across the corrosion hole. Another corrosion hole was located in the casing below the tubing shoe, immediately above the perforations. During a subsequent workover, the tubing was retrieved and a 1.5-inch corrosion hole was located in the exact place where it was identified by the MID tool.
Internal Corrosion Assessment of the Otter Oil Production Spool
Authors: Rodrigues Edgar , Akid Robert
Published: June 2014

One of the challenges facing the offshore oil and gas industry is the identification and quantification of internal corrosion for both topside and subsea process facilities. An increasing major cause of system failures and loss of production is that due to the presence of microorganisms that lead to the onset of Microbiologically Influenced Corrosion (MIC) in the offshore system [1]. Throughout the service life of the Otter oil production spool, internal corrosion was identified during the inspection programmes indicating severe metal loss of up to 1.7 mm/y for the Oil Topside Production spool. Internal corrosion and degradation were also detected in the subsea oil production pipeline during the 2010 and 2012 In-Line Inspection (ILI) programmes, where metal loss values of 12.5 mm depth were detected. Corrosion coupons and probes have confirmed that internal corrosion was active. The worst cumulative metal loss based on corrosion modelling indicated a corrosion rate of 0.22 mm/y. Furthermore, the microbial surveys performed using the most probable number (MPN) method has reported very low numbers of microorganism within the system.

Furthermore, the investigation of the spools when removed from topside, has confirmed severe internal corrosion aligned with inspection data. Samples of black deposits directly in contact with the carbon steel were taken for microbiological analysis and the novel DNA-based enumeration method quatitative Polymerase Chain Reaction (qPCR) has been used to assess whether or not MIC has occurred and to identify the key microorganisms responsible for this corrosion mechanism. High numbers of microorganisms were detected that could not be identified during service life indicating that MIC was in fact the primary mechanisms responsible for the damage found. Based on the results obtained, this paper discusses how the degree of internal corrosion was previously underestimated and how the microorganisms responsible for MIC that have been present were not properly identified and quantified. The paper also gives directions on how to strengthen MIC Threat Assesssment in the future.
Corrosion Inhibitors Squeeze Treatments-Misconceptions, Concepts and Potential Benefits
Authors: Graham Gordon M. , Bowering Deborah , MacKinnon Kirsty , McCall Matthew , Stalker Robert
Published: June 2014

While downhole chemical squeeze treatments are common practice for deploying scale inhibitors to protect wellbores and downhole production tubulars from inorganic deposits, their adoption for corrosion inhibitor treatments (CISQ) is much less commonplace. Historically they have often not been considered an option due to either anticipated poor lifetimes or the risk of formation damage in the form of emulsion blocks, wettability changes or relative permeability modification. However, in a number of carbonate reservoirs producing from different regions, corrosion inhibitor squeeze treatments have been shown to provide corrosion protection for downhole production tubulars when no alternative downhole chemical deployment technique is available.

This paper will present a technical review of the potential benefits of CISQ treatments. Different inhibitor retention/release mechanisms in sandstone and fractured carbonate reservoirs will be discussed, including classic adsorption/desorption and chemical imbibition/diffusion, as will the impact of these mechanisms and oil/water partitioning behaviour on squeeze lifetimes. Another factor limiting adoption of CISQ treatments is the misconception that residual assay techniques may be inadequate, and we demonstrate that this is not necessarily the case.

In addition to providing a mechanistic interpretation of the available retention and release mechanisms, the results of laboratory core flood studies will illustrate the different retention mechanisms and offer the potential to achieve considerably different lifetimes with different types of corrosion inhibitors. Field examples will also be cited in support of this. In these cases, the accuracy of the measured residual corrosion inhibitor return concentrations were confirmed by conventional electrochemical corrosion inhibitor performance measurements.
Corrosion Inhibition under FeCO3-forming Conditions at Elevated Temperatures
Authors: Palencsár Attila , Gulbrandsen Egil , Kosorú Katerina
Published: June 2014

Testing of inhibitors for CO2-corrosion at elevated temperatures is often performed so as to delay or avoid formation of a protective iron carbonate layer. Inhibitor performance in the presence of FeCO3 (partly or fully covering the steel surface), however, also deserves attention. This is relevant for parts of pipelines where rapid iron carbonate formation is expected, or when formation water breakthrough requires switching from pH stabilization to inhibition. From a methodological viewpoint such studies may indicate whether experiments in the presence of FeCO3 layers should be included in routine inhibitor performance testing. Investigating and comparing the behavior of corrosion inhibitors in the presence of iron carbonate layers of varying degrees of protectiveness was the objective of a series of experiments within the framework of a Joint Industry Project focusing on high temperature inhibition, carried out in our laboratories.

This contribution presents the results obtained with an imidazoline type generic inhibitor in high salinity brines with pH above 6, with 0.5 and 1 bar CO2 partial pressure. Inhibitor performance was studied by means of electrochemical measurements in glass cells at 80°C as well as in a pressurized jet impingement apparatus at 100°C and 120°C. Timing of the inhibitor injection was based on the development of the iron carbonate layer.

The inhibitor effectively reduced the corrosion rate when protective FeCO3 formation was not yet complete. Measurements of the Fe2+ concentration also revealed that the inhibiting effect hindered the increase of the supersaturation required for effective FeCO3 precipitation, slowing down or completely halting the film formation process. In contrast, once a fully protective iron carbonate layer has developed, no additional corrosion rate reduction can be observed upon inhibitor addition.

The results provide insight into how the inhibitor effect manifests itself when applied at various stages of iron carbonate formation on a steel surface. The experiments performed under enhanced convection illustrate the important role mass transport plays in the formation of iron carbonate layers and on inhibition. Both aspects are important for an improved understanding of inhibition of CO2-corrosion in oil and gas pipelines.
Multi-faceted Approaches for Controlling Top of Line Corrosion (TLC) in Pipelines
Authors: Frenier Wayne W. , Wint David
Published: June 2014

This paper reviews the mechanisms of initiation and the prevention of TLC. Practical multi-faceted techniques based on the most recent research and developments will be described and then illustrated using documented sources to arrive at best practices for control of this significant corrosion manifestation.

The application is in the complex corrosive environment in multi-phase and stratified flow pipelines (including gathering lines) that are frequently observed in new shale play production. The sizings of pipelines have become a critical factor to meet the current and future projected production rates. Especially where pipelines may be under-sized there is preferential attack in the top of the pipeline when water condenses and provides the electrolytes for acid gas and vapor attack on the steel surfaces.

Conventional corrosion inhibition methods (continuous or intermittent injection) are frequently not effective since physical contact of the inhibitors is difficult to achieve in multiphase flowing systems at the top of the line. In addition, the pipelines must be piggable to be properly cleaned and treated and traditional slug or continuous treatment methods have been found to not be adequate where conditions exist for TLC to occur.

Several innovative methods are being developed to provide effective and long lasting protection to the entire pipeline surface. Included are the use of pig trains with inhibitor slugs, inhibitor containing gels and foams and special pigs that provide a 360° spray of inhibitor chemicals. The newer methods will be compared with the other technologies.

The rapid expansion of the production of oil and gas from unconditional sources requires the annual construction of thousands of miles of new lines. These will experience a bewildering and changing range of conditions that will require the use of new and innovative internal corrosion protection methods described here that have been proven in field applications.
Application of Plant Extract for Inhibiting Corrosion in Acidic Environments
Authors: Belakshe Ravikant , Salgaonkar Lalit
Published: June 2014

Use of chemical corrosion inhibitors is quite common in production and processing operations. Depending on the type of acids used, different inhibitors have been developed to minimize corrosion and enhance the life of metal tubulars. Development of new chemicals and chemistries, which maintain good protection of materials under a variety of conditions while being environmentally acceptable, is an extremely challenging task.

This paper investigates the inhibitive properties of a new environmentally acceptable inhibitor toward corrosion of different steel alloys in the presence of mineral and organic acids. The inhibitor explored in this paper is a food grade chemical derived from a plant and commonly used in medicinal formulations. It is easily available, non-polluting, and biodegradable, being of plant origin. The inhibitor composition has several N, O, and S atoms containing alkaloid structures, which helps enhance the adsorption capacity of the chemical as well as imparts corrosion inhibition properties. The inhibitor can be used either in the form of a solid powder derived from the roots of the plant or in a liquid form derived by means of extraction.

Corrosion inhibition of oilfield alloys, such as N-80, 13Cr-L80, and QT-800, were studied in the presence of corrosive media, such as 7.5 and 15% HCl acid, and organic acid mixtures comprising acetic and formic acid. Weight-loss measurements were used to evaluate the inhibition efficiency and a corrosion loss of ≤ 0.05lb/ft2 was considered as a pass. Tests were conducted on the metallurgies mentioned over a temperature range of 150 to 275°F.

The results disclosed illustrate the potential of the inhibitor to serve as an effective environmentally acceptable inhibitor for the corrosion of steel alloys in the described temperature range. This single inhibitor composition can be applied for both HCl and organic acid media in fresh water and salt brine systems.
Accurate Tool for IOR/EOR Screening and Estimating Target Recovery Factors
Authors: Zijlstra Ellen , Wunnik John Van , Doren Jorn Van , Bimani Aisha Al , Wilson Ove , Shidhani Sultan Al
Published: June 2014

A semi-analytical method to calculate recovery factors is presented which is valid for recovery technologies that are based on flooding the reservoir with a liquid, such as Water, Polymer, Alkaline Surfactant Polymer and solvents including MGI and WAG. The method is based on describing the total Recovery Factor (RF) as the net result of a macroscopic displacement efficiency, essentially capturing the fraction of the reservoir that can be contacted by the injectant, and a microscopic displacement efficiency, capturing the extent to which the contacted rock can be swept clean. Given specific reservoir and fluid characteristics such as reservoir permeability distribution and relative permeability relations, these two components can each be described analytically and then merged together in the so-called PDO Tubes Model.

A comprehensive analysis of about 50 real IOR and EOR field cases with different geologies was done to validate the method. The PDO Tubes Model predictions of RF as a function of injected water in pore volumes were compared to full field simulation models showing a discrepancy of less than 5%. In this paper the tool and its validation will be discussed in detail and an example will be shown of an application of the tool for testing IOR and EOR implementation strategies for a very diverse set of fields.

Application of the PDO Tubes Model has resulted in a good understanding of the contributions of various EOR technologies to unlocking remaining oil in the Sultanate of Oman. Among others the tool can be used in any company for: IOR and EOR selection and target recovery factor setting, QC of simulation results, steering geological model building and analysis of a company's portfolio of fields for IOR and EOR potential and their implementation strategies including the resource requirements imposed by a specific strategy.
A Comparison of Asphaltene Deposition in Miscible and Immiscible Carbon Dioxide Flooding in Porous Media
Authors: Soroush Samaneh , Pourafshary Peyman , Vafaie-Sefti Mohsen
Published: June 2014

Carbon dioxide injection is used for tertiary oil recovery and can recover significant amount of residual oil. CO2 injection has been used successfully as an enhanced oil recovery (EOR) method for several decades. Recently, CO2 flooding method has gained popularity due to the growing concerns over the global warming issue. Hence, many light and medium reservoirs are subjected to Immiscible, miscible, and near-miscible CO2 flooding. In CO2 or hydrocarbon flooding, the asphaltene to resin ratio of crude oil is altered, causing asphaltene precipitation and thereby its deposition.

The deposition of asphaltene in an oil reservoir during production causes formation damage and productivity decline. The severity of this damage is different during miscible and immiscible flooding. In this study, asphaltene deposition due to miscible and immiscible carbon dioxide flooding and its effect on porous media damage are experimentally investigated. A high-pressure, high-temperature coreflood set-up is designed to work under reservoir conditions up to 6000 psia and 150 ºC.

Dynamic displacement experiments were carried out to study the process of asphaltene deposition and permeability reduction during CO2 injection in core samples. For this purpose, the pressures along the core were measured at 4 different points to study the damage distribution. Damage index were measured in different sections and compared during miscible and immiscible flooding and the effect of residual gas saturation in permeability reduction is studied as well.

The results showed that two parameters could change the permeability of the medium. At pressure lower than MMP trapped gas in the pores may also reduce the permeability and at pressure above the MMP asphaltene deposition is the main factor for the porosity and permeability reduction. The maximum damage index occurs in miscible flooding which was equal to 0.79.
A Laboratory Study of Ionic Effect of Smart Water for Enhancing Oil Recovery in Carbonate Reservoirs
Authors: Awolayo Adedapo , Sarma Hemanta , AlSumaiti Ali M
Published: June 2014

Enhanced oil recovery by smart waterflooding represents an implementable and attractive emerging oil recovery technology. For sandstone reservoirs, smart waterflooding has shown an outright incremental oil recovery in most laboratory and field tests while some promising experimental data have been presented from carbonates. It seems more difficult to assume a favorable performance for some reservoir formation a priori while dismissing the other, so more data and better understanding of the underlying mechanism in carbonates are needed.

This paper describes a series of experiments on Middle East carbonate core plugs designed to determine the impact of formation water and different versions of seawater (which has its sulfate concentration increased in the ratio (0.5:1:2:4:8) on oil recovery, wettability and surface charge modification. The results obtained lead to the following conclusions:

Coreflooding experiments at 2300F and 3000psi with formation brine and various versions of seawater coupled with spiking sulfate concentration executed on carbonate core aged showed an incremental recovery of about 10% OOIC; An increasing concentration of sulfate in the seawater makes a Crude Oil/Brine/Rock system less oil-wet; The higher the sulfate concentration, the greater the repulsive forces in the electrical double layer, thereby forming an aggregate and detaching the oil from the rock surface, while increasing the sulfate concentration beyond four times seems ineffective as it gave a swift increase in pH and rock surface charges;

The results obtained are therefore discussed within the framework of mechanisms previously described for smart water's ability to enhance oil recovery. The study concluded that a relatively economical modification of injection brine composition could considerably increase oil recovery.
Predicting Interfacial Tension Of Multiphase Systems Based On Computational Single-Molecule Quantum Mechanics And Thermodynamics Applying Four Different Physical Models And COSMO-Theory
Authors: Bennetzen Martin V. , Andersson Martin , Mogensen Kristian
Published: June 2014

Reduction of interfacial tension is of key importance for mobilising residual oil trapped by capillary forces during a secondary waterflood. The Conductor-like Screening Model (COSMO) and its extension COSMO-RS, developed over the last decades, enables prediction of thermodynamic properties of mixtures. Molecular charge distributions and associated charge distribution properties, so-called sigma moments, can be calculated and used as input parameters for various physical models to predict IFT of fluid mixtures.

In this paper we present and compare four different and complementary approaches to predict IFT based on single-molecule properties derived from COSMO-RS theory. The first method is based on predicted liquid-liquid extraction (LLE) phase-specific mole fractions using a formalism suggested by Apostoluk and Szymanowski (1996). The second method relies on a Taylor-like approximation of chemical potentials of mixtures using a realisation of Method of Moments (MoM) as described by Klamt and co-workers. The third method, recently described by Andersson et al., relies on LLE calculations as well as free energies for molecules present at the interfaces in multiphase immiscible systems. The fourth method, the so-called GSM-model recently described by the authors of this paper, relies on non-linear statistical relations between COSMO-derived energy descriptors and IFT.

By conducting a comprehensive comparative analysis we show that each of the four models estimates IFT with significant accuracy, that these models are complementary and that the models should be chosen based on the specific system of interest as well as the present available system information. Moreover, we demonstrate that COSMO-RS theory, when used in combination with physical models, provides a powerful tool for EOR research enabling fast, accurate computational prediction of IFT of multiphase fluid mixtures. Hence the models presented here may be used for systematic laboratory testing of e.g. surfactants and co-solvents for EOR processes as well as for predicting properties of multiphase fluid systems.
Potential of Alkaline Surfactant Polymer (ASP) Flooding in a Medium-Light Oil Reservoir with Strong Bottom Aquifer
Authors: Al-Sulaimani Hanaa , Stoll Martin , Wunnik John Van , Faber Rien , Arkesteijn Fred
Published: June 2014

A central Oman oil field was evaluated for the potential of an ASP flooding development. The field is a sandstone reservoir containing medium to light oil of 33° API with a viscosity of 9cP.

Till today, the field is under natural depletion with, lately, pressure supported by water injection into the aquifer at the NW and SW flanks. The recovery factor is already high and currently the field water cut is at 97%.

Recently, an EOR screening study was conducted on PDO's fields and the subject field was found to be one of the potential candidates for ASP flooding. Several lab experiments were conducted on reservoir rock and fluid samples to assess the potential of an ASP application. The ASP formulation was tested on two wells in this field through the Single Well Chemical Tracer (SWCT) test technique where the residual oil reduced from 20% to 4% for one well and from 15% to 8% for the other.

Different development scenarios were evaluated: a scenario that makes use of the strong bottom aquifer in combination with horizontal injectors near the OWC was found to be a technically viable development option. The liquid rate forecasts were subsequently used in the project economics showing that the company's screening criteria were met.

The full field development versus phased development approaches were also evaluated where the latter was found to be favorable as it allows for early starting and proper de-risking for following phases. The subsurface feasibility study for this reservoir revealed that there is an opportunity of increasing the Recovery Factor of this field by more than 10%.

This paper will describe in detail the study and the overall de-risking strategy with its various phases namely; lab experiments, single well tests, full field evaluation and showing of commercial attractiveness and finally the optimized implementation through phasing.
Shifting to a New EOR Area for Sandstone Reservoirs with High Recovery, No Damage, and Low Cost
Authors: Attia M. , Mahmoud M. A. , Al-Hashim H. S. , Sultan A. S.
Published: June 2014

Experimental investigations and field applications showed an increase in oil recovery by using low salinity water injection. The mechanisms leading to the increase in oil recovery by low salinity water injection are debatable. Furthermore, low salinity water injection requires relatively fresh water to dilute sea water which is not available in many areas around the world especially the Arabian Gulf region. Using low salinity water as an enhanced oil recovery process is a costly process because it requires a lot of fresh water to dilute the sea water.

In this study we introduce an economic and new chemical enhanced oil recovery fluid capable of recovering additional oil from sandstone reservoirs after the primary water flooding stage. The new chemical enhanced oil recovery fluid utilizes high pH chelating agents at low concentrations prepared in sea water without any dilution. Coreflood experiments were performed using Berea sandstone cores at 100°C to test the effectiveness of this new EOR fluid system.

The results of the coreflooding experiments showed that the new fluid system is able to recover additional oil up to 30% from the initial oil in place after sea water flooding. Zeta potential measurements were performed using the new fluid system and crushed Berea cores to identify the mechanism leading to this additional oil recovery. The results of the zeta potential revealed more negative values for the new system more than the sea water and low salinity water, confirming that the rock wettability is altered to a more water-wet condition. This changed in rock wettability could be due to rock dissolution and the chelation of the different ions such as calcium, magnesium and iron ions. The new fluid system very attractive as its cost is low compared to the cost of diluting the sea water in the case of low salinity water flooding.